# Florida Gas Transmission — Pipeline Special Permit - **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. <<>> U.S. DEPARTMENT OF TRANSPORTATION PIPELINE AND HAZARDOUS MATERIALS SAFETY ADMINISTRATION DRAFT SPECIAL PERMIT - Class 1 or Class 2 to 3 Location Special Permit Information: Docket Number: PHMSA-2023-0022 Requested By: Florida Gas Transmission Company, LLC Operator ID#: 5304 Original Date Requested: March 24, 2023 Original Issuance Date: Month Day, 20XX Effective Dates: Month Day, 20XX to Month Day, 20XX Code Section(s): 49 CFR 192.611(a)(3)(iii) Proposed Grant of Special Permit: By this order, subject to the terms and conditions set forth below, the Pipeline and Hazardous Materials Safety Administration (PHMSA) Office of Pipeline Safety (OPS)1 proposes to grant this special permit to Florida Gas Transmission (FGT)2 for four (4) special permit segments consisting of approximately 0.13 miles of 18-inch diameter gas transmission pipelines and 0.46 miles of 30-inch diameter gas transmission pipelines located in Hillsborough County, Florida. This special permit waives compliance from 49 Code of Federal Regulations (CFR) 192.611(a)(3)(iii)3 for three (3) special permit segment(s) that have undergone changes from Class 1 to Class 3 and one (1) special permit segment that has undergone a change from Class 2 to Class 3. The Federal pipeline safety regulations in 49 CFR 192.611(a)(3)(iii) require natural gas pipeline operators to confirm or revise the 1 Throughout this special permit, the usage of “PHMSA” or “PHMSA OPS” means the U.S. Department of Transportation’s Pipeline and Hazardous Materials Safety Administration Office of Pipeline Safety. 2 FGT is owned by Energy Transfer and Kinder Morgan. 3 A Class 2 or 3 location requires a pressure test of 1.5 times the maximum allowable operating pressure (MAOP) in 49 CFR 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 location change upgrade after the pipeline has been constructed and placed into operational service. A special permit for 49 CFR 192.611(a)(3)(iii) would include 49 CFR 192.620(a)(2). PHMSA-2023-0022 – Florida Gas Transmission Company, LLC Draft Special Permit – Class 1 and 2 to Class 3 Locations – Florida Page 1 of 53 <<>> maximum allowable operating pressure (Alternative MAOP) of a pipeline segment after a change in class location.4 I. Purpose and Need FGT sought this special permit for Class 1 to Class 3 location or Class 2 to Class 3 location changes occurring on the 18-inch diameter St. Petersburg Sarasota Connector and 30-inch diameter West Leg Station 27 to Ft. Myers Pipelines. On the condition that FGT complies with the terms and conditions set forth below, the proposed special permit would waive compliance from 49 CFR 192.611(a)(3)(iii) for approximately 0.59 miles (3,135 feet) of natural gas transmission pipeline. This proposed special permit is for class location changes where the pipeline has not been pressure tested to 1.50 times Alternative MAOP or greater for eight (8) hours to meet 49 CFR 192.611(a)(3)(iii). The four (4) proposed special permit segments have been pressure tested to greater than 1.42 times the Alternative MAOP. This proposed special permit would allow FGT to maintain the current Alternative MAOP5 as shown in Table 1 – Special Permit Segments. II. Special Permit Segments and Special Permit Inspection Areas This permit pertains to the specified special permit segments and corresponding special permit inspection areas defined in this section. Special Permit Segments: This proposed special permit applies to the special permit segments in Table 1 – Special Permit Segments and are identified using the FGT survey station (SS) references. 4 The Class 1 to 3 or Class 2 to 3 location changes on the FGT pipelines have pipe with design factors in accordance with 49 CFR 192.620(a)(1) for Alternative MAOP. The special permit segments utilize alternate design factors from 49 CFR 192.620 per existing special permit PHMSA-2008-0077. 5 The “MAOP” defined in Table 1 – Special Permit Segments and used throughout this document is an “Alternative MAOP” as defined in 49 CFR 192.620. PHMSA-2023-0022 – Florida Gas Transmission Company, LLC Draft Special Permit – Class 1 and 2 to Class 3 Locations – Florida Page 2 of 53 <<>> Table 1 – Special Permit Segments Special Permit Start Seam Outside Design Pressure Diameter Line Name Length (feet) Survey Station End Survey Station County, State Class Summary No. Year Dwellings Installed Type/ External MAOP Segment Number (psig)6 / Test (inches) (SS) (SS) Coating Factor 201350 18 703 277+47 284+50 Hillsborough, FL 1 to 3 2 1992 DSAW/ FBE 188251 30 783 4105+18 4113+00 Hillsborough, FL 2 to 3 8 2000 FBE DSAW/ 188253 30 1,255 4200+34 4212+89 Hillsborough, FL 1 to 3 2 2000 FBE DSAW/ 188257 30 394 4445+98 4449+92 Hillsborough, FL 1 to 3 36 2000 DSAW/ FBE St. Petersburg Sarasota Connector (18”, 0.309”, X70) West Leg Station 27 to Ft Myers (30”, 0.515”, X70) West Leg Station 27 to Ft Myers (30”, 0.429”, X70) West Leg Station 27 to Ft Myers (30”, 0.515”, X70) Note: DSAW is a double submerged arc welded pipe longitudinal seam. FBE is fusion bonded epoxy external pipe coating. Special Permit Inspection Areas: The special permit inspection areas are defined as the area that extends 220 yards on each side of the centerline as listed in Table 2 – Special Permit Inspection Areas. 1,333 0.56 / 1.42 1,333 0.56 / 1.43 1,333 0.67 / 1.43 1,333 0.56 / 1.43 Table 2 – Special Permit Inspection Areas Special Special Permit Outside Start Survey End Survey Permit Length7 Inspection Diameter Line Name Station Station Segment(s) (miles) Area Number (inches) (SS) (SS) Included 1 201350 18 FLBVW 8+99 1951+01 36.9 2 188251, 188253, 188257 30 FLMEE27 3670+75 7924+64 80.4 Extended Special Permit Segments: The extended special permit segment is defined as the special permit segment and the five (5) contiguous miles past each endpoint. Attachment B contains general maps that include the pipeline route map showing the special permit segment(s) and special permit inspection area(s) and a more detailed maps showing the area near the special permit segment(s). 6 Pressure tests were conducted after July 1, 1965, see 49 CFR 192.619(a)(3) for applicability. 7 If the special permit inspection area footage does not extent from launcher to receiver then the special permit inspection area would need to be extended. PHMSA-2023-0022 – Florida Gas Transmission Company, LLC Draft Special Permit – Class 1 and 2 to Class 3 Locations – Florida Page 3 of 53 <<>> 8 PHMSA proposes to grant this special permit based on the findings set forth in the “Draft Environmental Assessment and Proposed Finding of No Significant Impact” documents, which can be read in their entirety in Docket No. PHMSA-2023-0022 in the Federal Docket Management System (FDMS) located on the internet at www.regulations.gov. III. Conditions PHMSA proposes to grant this special permit subject to FGT implementing the following conditions on the special permit segments and special permit inspection areas. FGT must continue to implement all applicable conditions of Special Permit – PHMSA-2008-0077 unless the condition is less stringent than Special Permit – PHMSA-2023-0022. Each condition detailed in this section applies to the special permit inspection areas and the corresponding special permit segment(s) unless otherwise noted in the condition: 1) Condition 1 - Maximum Allowable Operating Pressure a) Maximum Allowable Operating Pressure: FGT must continue to operate each special permit segment and special permit inspection area at or below the existing MAOP as defined in Table 1 – Special Permit Segments. b) Pressure Test: FGT must identify previous pressure tests for each special permit segment. Pressure test records for each special permit segment must meet 49 CFR 192.517(a) and be traceable, verifiable, and complete (TVC)9 as required in 49 CFR 192.624(a)(1).10 i) FGT must furnish TVC pressure test records to the Director, PHMSA Engineering and Research Division, and to the Director, PHMSA Southwest Region, within 60 days of the grant of the special permit. The pressure test records must be compliant with Condition 1(b). 11 FGT must receive a “no objection” letter from the Director, PHMSA Southwest 8 If this application is granted, PHMSA may merge these special permit segments with existing special permit PHMSA- 2020-0044. 9 TVC procedures and records must follow the following: 1) “Pipeline Safety: Safety of Gas Transmission Pipelines: MAOP Reconfirmation, Expansion of Assessment Requirements and Other Related Amendments”; 84 FR 52218 to 52219; October 1, 2019; and 2) PHMSA Advisory Bulletin: Pipeline Safety: Verification of Records; 77 FR 26822; May 7, 2012; https://www.gpo.gov/fdsys/pkg/FR-2012-05-07/pdf/2012-10866.pdf. 10 If PHMSA determines that FGT has not furnished TVC pressure test records to PHMSA for each special permit segment FGT must meet Condition 1(b). 11 The pressure test records must cover the entire length of the special permit segment, regardless of when the pipeline, single or multiple pipe joints, or other pipeline components were installed. Affidavits for a pressure test are not acceptable TVC pressure test records. PHMSA-2023-0022 – Florida Gas Transmission Company, LLC Draft Special Permit – Class 1 and 2 to Class 3 Locations – Florida Page 4 of 53 <<>> Region, that the TVC pressure test records are compliant with 49 CFR 192.517(a) and 192.620(a)(2) for Class 1, 2, or 3 locations with a pressure test at or above 1.42-times the MAOP, or FGT must pressure test each special permit segment in accordance with Condition 1(b)(ii). ii) If FGT does not have a TVC record of a 1.42-times the MAOP hydrotest in accordance with Subpart J, or the special permit segment requires an updated pressure test, the special permit segment must be hydrostatically tested12 to a minimum of 1.50 times the MAOP for eight (8) continuous hours in accordance with 49 CFR Part 192, Subpart J, within 18 months of the grant of this special permit.13 c) MAOP Restoration or Uprating of Previously De-rated Pipe: MAOP restoration or uprating is not approved for this special permit. 2) Condition 2 - Procedure Updates Within 90 days of the grant of the special permit, FGT must develop and maintain procedures in accordance with 49 CFR 192.603 and 192.605 that incorporate the special permit condition requirements as follows: a) Operations and Maintenance Manual: FGT must amend the applicable sections of its Operations and Maintenance (O&M) manual(s) and procedures to incorporate the special permit conditions. b) Integrity Management Program: i) FGT must incorporate each special permit segment into its written integrity management program (IMP) procedures as if the special permit segment is a “covered segment” as defined in 49 CFR 192.903, except for the reporting requirements contained in 49 CFR 192.945.14 A special permit inspection area outside of a special permit segment is not required to be included as a “covered segment” in accordance with 49 CFR 192.903. 12 For all in-service and pressure test failures, FGT must perform a root cause analysis, including the metallurgical examination of the failed pipe, to determine if the failure is caused by a systemic or non-systemic issue. FGT must provide the written results of this root cause analysis to the Director, PHMSA Southwest Region, within 90 days of the failure and must submit a copy of the root cause analysis to the Director, PHMSA Engineering and Research Division. 13 The grant of this special permit, as used throughout, is the signed issuance date of the special permit. 14 FGT must follow the reporting requirements in Condition 15 – Annual Report as well as those noted throughout the conditions contained herein. PHMSA-2023-0022 – Florida Gas Transmission Company, LLC Draft Special Permit – Class 1 and 2 to Class 3 Locations – Florida Page 5 of 53 <<>> ii) The special permit inspection area and special permit segment must have integrity threats identified, assessed, and remediated in accordance with these special permit conditions, 49 CFR 192.917, and 49 CFR Part 192, Subpart O. iii) Any high consequence area (HCA) in either a special permit segment or a special permit inspection area must be assessed and remediated for threats in accordance with these special permit conditions and 49 CFR Part 192, Subpart O. iv) All permit conditions that are applicable to a special permit segment or to a special permit inspection area are applicable to HCAs where the HCA overlaps a special permit segment or a special permit inspection area. v) All special permit conditions that are applicable to a special permit inspection area are also applicable to the special permit segment. A special permit segment must meet the requirements of 49 CFR 192, Subpart O, if Subpart O is more stringent than the special permit conditions. vi) The special permit inspection area must be able to be assessed using inline inspection (ILI) tools, including tethered or remotely controlled tools, in accordance with 49 CFR 192.150 and 192.493. c) Damage Prevention Program: FGT must incorporate within a special permit inspection area the applicable best practices of the Common Ground Alliance (CGA)15 in its damage prevention (DP) program. 3) Condition 3 – Corrosion Control FGT must promptly address any corrosion control deficiencies in a special permit segment that are indicated by the inspection and testing programs required under 49 CFR 192.463 and 192.465. a) Cathodic Protection Test Station Spacing: At least one (1) cathodic protection (CP) pipe-to- soil test station must be located within each special permit segment, with a spacing not to exceed ½ mile between CP pipe-to-soil test stations. In cases where obstructions or restricted areas prevent such test station placement, the test station must be placed in the closest practical location, not to exceed a 3,000-foot spacing. CP pipe-to-soil test stations must be installed within 12 months of the grant of this special permit. 15 Common Ground Alliance. (March 2020). Best Practices Guide. Retrieved from: https://commongroundalliance.com/BPguide. PHMSA-2023-0022 – Florida Gas Transmission Company, LLC Draft Special Permit – Class 1 and 2 to Class 3 Locations – Florida Page 6 of 53 <<>> b) Annual Monitoring of Test Station Potential Measurements: At least once every calendar year, not to exceed 15 months, FGT must monitor CP pipe-to-soil test stations to meet 49 CFR 192.463 and 192.465 for the special permit segment and must include “on and off” potential measurements. Test station readings (pipe-to-soil potential measurements) must comply with Appendix D – Section I.A. (1) of 49 CFR Part 192 or remediation detailed in paragraph (c) of this condition is required. For hard spots identified with a Brinell Hardness (HB) of 300 HB or greater, CP voltage levels must be maintained more electro-positive than minus 1.2 volts direct current (DC). c) Inadequate Cathodic Protection Level Determination: i) In instances where inadequate potentials are a result of an electrical short to an adjacent foreign structure, a rectifier malfunction, an interruption of power source, or an interruption of CP current due to other non-systemic or location-specific causes, FGT must document and repair these instances. A close interval survey (CIS) will not be required. ii) All other instances must be assessed as detailed in Condition 4 – Close Interval Surveys. d) Remedial Action Plans: i) Within six (6) months of identifying a deficiency, FGT must develop a remedial action plan to restore CP to meet 49 CFR 192.463. Within two (2) months of the finding, FGT must apply for any necessary environmental permits (Federal or state). ii) FGT must complete the remediation and confirm restoration of adequate CP over the entire area where inadequate CP levels were detected within 12 months of the deficiency finding or as soon as practicable after obtaining the necessary permits. 4) Condition 4 – Close Interval Surveys a) Survey Methodology and Boundaries: i) FGT must perform an “on and off” current CIS at a maximum 5-foot spacing along the entire length of each special permit segment. 16 ii) FGT must evaluate each special permit segment in accordance with 49 CFR 192.463. 16 Each condition in this special permit that requires FGT to perform an action with respect to the special permit inspection area also requires FGT to perform that action on each special permit segment within the area. PHMSA-2023-0022 – Florida Gas Transmission Company, LLC Draft Special Permit – Class 1 and 2 to Class 3 Locations – Florida Page 7 of 53 <<>> iii) For inadequate CP level determination described in Condition 3(c)(ii), FGT must conduct a CIS in both directions from the test station with an inadequate CP reading with the CIS ending at the adjacent test stations. b) Survey Intervals: FGT must perform the CIS within the following timeframes: i) Initial assessment must be completed for each newly incorporated and extended special permit segment within 12 months after the grant of the special permit. For a special permit segment renewal, the CIS may be conducted at the next reassessment interval.17 ii) Reassessments must be conducted every five (5) years not to exceed 66 months. CIS assessments within the reassessment interval are not required to be performed in the same year as ILI reassessments. c) Survey Remediation and Remedial Action Plans: i) If a special permit segment requires the use of 100 millivolt shift criteria18 or the installation of linear anodes along the special permit segment to meet the CP requirements of 49 CFR 192.463, it is not eligible to operate with a Class 1 pipe in a Class 3 location. FGT must either: (1) replace the pipe in the special permit segment with Class 3 location standard (design factor) pipe (see 49 CFR 192.111(a)); (2) recoat the pipe with non- shielding external coating within 12 months of the finding; or (3) lower the MAOP to meet 49 CFR 192.611. ii) Within four (4) months of identifying a deficiency, FGT must develop a remedial action plan to restore CP to meet 49 CFR 192.463. Within two (2) months of the remedial action plan being developed, FGT must apply for any necessary environmental permits (Federal or state). 17 A CIS survey conducted in 2020 for a special permit segment that is permit condition compliant would not need to be resurveyed in 2021 but could wait until the next CIS survey reassessment time. 18 A.W. Peabody, “Peabody’s Control of Pipeline Corrosion,” second edition, “Criteria for Cathodic Protection.” “The 100mV polarization criterion should not be used in areas subject to stray current because 100 mV of polarization may not be sufficient to mitigate corrosion in these areas. This criterion also should not be used in areas where the intergranular form of external SCC, also referred to as high-pH or classical SCC, is suspected. The potential range for cracking lies between the native potential and -850 mV (CSE) such that application of the 100mV polarization criterion may place the potential of the structure in the range for cracking.” PHMSA-2023-0022 – Florida Gas Transmission Company, LLC Draft Special Permit – Class 1 and 2 to Class 3 Locations – Florida Page 8 of 53 <<>> iii) FGT must complete remediation of each special permit segment and confirm restoration of adequate CP over the entire area where inadequate CP levels were detected within 12 months of the survey or as soon as practicable after obtaining the necessary permits.19 5) Condition 5 – Inline Inspection a) Threat Identification: FGT must implement data integration and identify integrity threats in the special permit inspection area at least once each calendar year, with intervals not to exceed 15 months, in accordance with 49 CFR 192.917 and Condition 13(c) – Data Integration. The stress corrosion cracking (SCC) threat assessment for the extended special permit segment, 20 must be conducted using the current incorporated by reference (IBR) edition of the American Society of Mechanical Engineers (ASME) Standard B31.8S, "Managing System Integrity of Gas Pipelines" (ASME B31.8S) Appendix A3 and National Association of Corrosion Engineers (NACE) Standard Practice (SP) 0204-2008, "Stress Corrosion Cracking Direct Assessment Methodology," Sections 1.2.1.1 and 1.2.2. b) Inline Inspection Methodology: FGT must conduct instrumented ILI integrity assessments in accordance with 49 CFR 192.493, for each special permit inspection area for all threats identified in accordance with 49 CFR 192.919 and 192.921. i) At a minimum, FGT must conduct ILI assessments for corrosion and denting with high- resolution (HR) magnetic flux leakage (HR-MFL) and HR deformation tools with deformation-extended sensor arms not limited by pig cups. ii) For near-neutral or high-pH SCC (cracking threat), FGT must use an ILI tool21 that will identify tight cracks. 22 iii) A special permit segment with electric flash welded (EFW) pipe must have an ILI tool assessment run for hard spots and cracking from hard spots. 19 If remediation based upon the findings of the CIS is not practicable within 12 months of the CIS survey, FGT must submit a schedule and justify the delay 60 days prior to the 12-month completion requirement to the Director, PHMSA Southwest Region. FGT must receive a “no objection” letter from the Director, PHMSA Southwest Region, prior to a pipe coating remediation schedule extension. 20 The extended special permit segment is defined as the special permit segment and the five (5) contiguous miles past each endpoint. 21 The crack ILI tool must be comparable to an electro-magnetic acoustic transducer (EMAT) ILI tool. 22 FGT may propose an alternative assessment method for SCC (such as spike hydrostatic testing in accordance with 49 CFR 192.506) to the Director, PHMSA Southwest Region, with a copy of the proposal to the Director, PHMSA Engineering and Research Division. FGT must receive a “no objection” letter from the Director, PHMSA Southwest Region, prior to implementing any alternative assessment methods for SCC. PHMSA-2023-0022 – Florida Gas Transmission Company, LLC Draft Special Permit – Class 1 and 2 to Class 3 Locations – Florida Page 9 of 53 <<>> iv) In a special permit inspection area that has experienced pipe or girth weld leaks or ruptures due to soil movement or the threat has been identified, FGT must run inertial measurement unit (IMU) and HR-deformation ILI tools for detection and remediation of strains and denting of the pipe body and girth welds from soil or pipe movements that impair pipeline integrity. Remediation must be conducted as determined by Condition 13(j) – Pipe and Soil Movement. c) Inline Inspection Assessment Intervals: FGT must conduct initial assessments and reassessments for the special permit inspection area in accordance with the following: i) Initial ILI assessments must be conducted as follows: (1) If the special permit segment has EFW pipe, it must be assessed for hard spots within 18 months of the special permit grant date. (2) If cracking has been identified as a threat for the extended special permit segment, it must be assessed within 18 months of the special permit grant date. (3) All other identified threats must be assessed within two (2) years of the special permit grant date. (4) For newly identified threats, assessments must be completed within two (2) years of identification. (5) Previous ILI assessments may be applied if Condition 8 – Anomaly Evaluation and Remediation is completed, and the Condition 5(c)(ii) reassessment interval is maintained. ii) Reassessments must be completed in accordance with the shortest interval of the following: (1) 49 CFR 192.939(a); (2) Intervals of five (5) calendar years not to exceed 66 months, if the special permit segment contains any of the following: (a) low-frequency electric resistance welded (LF-ERW) or EFW pipe, (b) hard spots, (c) shorted carrier pipe to the casing, (d) susceptible to SCC, or (e) pipe or soil movement; or PHMSA-2023-0022 – Florida Gas Transmission Company, LLC Draft Special Permit – Class 1 and 2 to Class 3 Locations – Florida Page 10 of 53 <<>> (3) The engineering critical assessment (ECA) determined interval, if applicable, iii) After conducting two (2) assessments of a threat, one (1) of which must be after the grant of this special permit, FGT may request reassessment intervals up to seven (7) years for that threat assessment. FGT must submit for and receive a “no objection” letter from the Director, PHMSA Southwest Region, prior to implementing this change. iv) If factors beyond FGT’s control prevent the completion of an assessment within the required timeframe or reassessment interval, FGT must perform the assessment as soon as practicable, and FGT must submit a letter justifying the delay and provide the anticipated date of completion to the Director, PHMSA Southwest Region, no later than two (2) months prior to the end the timeframe or interval. FGT must receive a “no objection” letter from the Director, PHMSA Southwest Region, for the delay or must lower the MAOP of the special permit segment in accordance with 49 CFR 192.611. d) Remediation: Anomaly assessments must be evaluated and remediated in accordance with Condition 8 – Anomaly Evaluation and Remediation. 6) Condition 6 - Girth Welds a) Construction Girth Weld Non-Destructive Test Records: FGT must provide records to PHMSA that demonstrate the girth welds in the special permit inspection area were either: i) Non-destructively tested (NDT) at the time of construction in accordance with the Federal pipeline safety regulations at the time the pipelines were constructed, or ii) At least 1% of the girth welds and a minimum of two (2) girth welds in each special permit segment were NDT after initial construction and prior to the special permit application. FGT must demonstrate these welds were excavated, NDT, and repaired, if the welds do not meet Federal pipeline safety regulations at the time the pipelines were constructed. b) Missing Records: If FGT cannot provide girth weld records to PHMSA to demonstrate compliance with Condition 6(a), FGT must complete either Condition 6(b)(i) or both Conditions 6(b)(ii) and (iii) within 12 months of the grant of this special permit as follows: i) Certify to PHMSA, in writing, that there have been no in-service leaks or breaks in the girth welds in the special permit inspection area for the life of the pipeline; or PHMSA-2023-0022 – Florida Gas Transmission Company, LLC Draft Special Permit – Class 1 and 2 to Class 3 Locations – Florida Page 11 of 53 <<>> ii) Evaluate the terrain along each special permit segment for threats to girth weld integrity from soil or settlement stresses, perform NDT, and remediate all such integrity threats;23 and iii) Excavate,24 visually inspect, and perform NDT on at least two (2) girth welds on each special permit segment in accordance with the applicable American Petroleum Institute Standard 1104, “Welding of Pipelines and Related Facilities” (API 1104) as follows: (1) Using the edition of API 1104 current at the time the pipeline was constructed; (2) Using the edition of API 1104 IBR in the Federal pipeline safety regulations at the time the pipeline was constructed; or (3) Using the edition of API 1104 currently IBR in 49 CFR 192.7. c) Defective Girth Welds: If any girth weld in a special permit segment is found unacceptable in accordance with the API 1104 IBR Edition at the time of pipeline construction, FGT must repair the girth weld immediately and then prepare an inspection and remediation plan for all remaining girth welds in the special permit segment based upon the repair findings and the threat to the special permit segment. FGT must submit the inspection and remediation plan for girth welds to the Director, PHMSA Southwest Region, and must receive a “no objection” letter for the girth weld remediation plan prior to its implementation.25 FGT must remediate girth welds in the special permit segment in accordance with the inspection and remediation plan within 90 days of the “no objection” letter receipt.26 7) Condition 7 - Stress Corrosion Cracking Threat FGT must evaluate the entire length of each special permit inspection area27 for SCC as follows: 23 If a special permit segment has not had girth weld NDT to meet Condition 6 – Girth Welds and has experienced pipe or girth weld leaks or ruptures due to soil movement or the threat has been identified, then Condition 5(b)(iv) must be conducted within 12 months of the finding. 24 FGT must evaluate the pipe for SCC any time the special permit inspection area is uncovered or excavated in accordance with Condition 8(b) or (c) of this special permit. Pipe with fusion bonded epoxy coating does not require SCC evaluation when excavated unless SCC has been identified as a threat in the special permit inspection area. 25 The Director, PHMSA Southwest Region, must respond to FGT's submittal letter within 90 days of receipt with a decision letter, or either give FGT a request for additional information or a need of additional time for PHMSA to review the request. 26 FGT must include any plan requirements or comments received from the Director, PHMSA Southwest Region, into the remediation plan. 27 FGT has documented 0 occurrences of SCC or cracking in the [special permit segment/special permit inspection area]. PHMSA-2023-0022 – Florida Gas Transmission Company, LLC Draft Special Permit – Class 1 and 2 to Class 3 Locations – Florida Page 12 of 53 <<>> a) Threat Assessments: FGT must complete the SCC threat assessment as detailed in Condition 5(a) – Threat Assessment. b) SCC Integrity Assessment: If the threat assessment required under Condition 7(a) indicates the extended special permit segment28 is susceptible to either near-neutral or high-pH SCC, FGT must perform an SCC assessment on the extended special permit segment in accordance with Condition 5 – Inline Inspection. SCC integrity assessment using spike pressure testing is not approved for this special permit.29 c) Examination of Pipe: If the threat of SCC exists in the extended special permit segment as determined in Condition 7(a), FGT must directly examine the pipe for SCC when the coating has been identified as poor during the pipeline examination. The examination must be conducted using an accepted crack detection practice in accordance with 49 CFR 192.710(c)(4), (d), and Condition 7(d) when the extended special permit segment is uncovered for any reason to comply with the special permit and integrity management activities, not including One Call activities (49 CFR 192.614). d) Inspection of Pipe at Excavations: Except for pipe coated with non-shielding coatings (fusion-bonded or liquid-applied epoxy coatings) and excavations performed in accordance with 49 CFR 192.614(c), FGT must directly examine the pipe for SCC using non-destructive examination methods appropriate for the type of pipe and integrity threat conditions in the ditch. FGT must use appropriate methods for crack detection, such as phased array ultrasonic testing (PAUT), inverse wavefield extrapolation (IWEX), or magnetic particle inspection (MPI), 30 when an extended special permit segment is uncovered, and the coating has been identified as poor during the pipeline examination. Visual inspection is not sufficient to determine “poor coating.” FGT must “jeep” the excavated segment to determine the coating condition. Examples of “poor coating” include, but are not limited to, a coating that has become damaged and is losing adhesion to the pipe which is shown by falling off the pipe 28 The extended special permit segment is defined as the special permit segment and the five (5) contiguous miles past each endpoint. 29 FGT may propose an alternative assessment method for SCC (such as spike hydrostatic testing in accordance with 49 CFR 192.506) to the Director, PHMSA Southwest Region, with a copy of the proposal to the Director, PHMSA Engineering and Research Division. FGT must receive a “no objection” letter from the Director, PHMSA Southwest Region, prior to implementing any alternative assessment methods for SCC. 30 When MPI finds cracking, another method must be used to size the crack unless the crack can be completely ground out and still meet the pipeline Alternative MAOP. PHMSA-2023-0022 – Florida Gas Transmission Company, LLC Draft Special Permit – Class 1 and 2 to Class 3 Locations – Florida Page 13 of 53 <<>> and/or shields the CP. FGT must keep coating records31 at all excavation locations in the special permit inspection area to demonstrate the coating condition. e) Discovery of SCC: If FGT discovers SCC32 activity by any means within the extended special permit segment in similar pipe vintage (manufacturer, manufacturing time or age, diameter, wall thickness, grade, and seam type) and pipe coating vintage (in accordance with 49 CFR 192.917(e)), or the extended special permit segment has had an in-service or hydrostatic test SCC failure or leak, 33 the special permit segment must be further assessed and mitigated, within 18 months of finding SCC and reassessed every five (5) calendar years or less34 based upon the evaluated growth of the SCC, using one (1) of the following methods: i) Spike Hydrostatic Test Program:35 (1) FGT must perform its SCC spike hydrostatic test program in an extended special permit segment in accordance with 49 CFR 192.506 and include an ECA of the results that includes a determination of the reassessment interval, and (2) If a joint of pipe in an extended special permit segment leaks or ruptures during a hydrostatic test due to SCC, FGT must replace the pipe joint that does not meet 49 CFR 192.611 in the extended special permit segment with new pipe. FGT must complete a successful SCC hydrostatic test prior to returning the extended special permit segment to operational service; 31 The records must include, at a minimum, a description of FGT’s detection procedures, records of finding, and mitigation procedures implemented for the excavation. 32 “SCC” activity shall be defined as greater than 20 percent wall thickness depth and 2-inches in length. 33 For all in-service and pressure test failures, FGT must perform a root cause analysis, including the metallurgical examination of the failed pipe, to determine if the failure is caused by a systemic or non-systemic issue. FGT must provide the written results of this root cause analysis to the Director, PHMSA Southwest Region, within 90 days of the failure and must submit a copy of the root cause analysis to the Director, PHMSA Engineering and Research Division. 34 FGT has the option to submit a written request to the Director, PHMSA Southwest Region, with a copy to the Director, PHMSA Engineering and Research Division, for extension of the crack assessment interval to seven (7) years, as defined in 49 CFR 192.939(a), if the ECA shows that five (5) calendar year assessments are not required. FGT must receive a “no objection” letter from the Director, PHMSA Southwest Region, prior to extending the assessment interval to seven (7) calendar years. 35 FGT may propose an alternative assessment method for SCC (such as spike hydrostatic testing in accordance with 49 CFR 192.506) to the Director, PHMSA Southwest Region, with a copy of the proposal to the Director, PHMSA Engineering and Research Division. FGT must receive a “no objection” letter from the Director, PHMSA Southwest Region, prior to implementing any alternative assessment methods for SCC. PHMSA-2023-0022 – Florida Gas Transmission Company, LLC Draft Special Permit – Class 1 and 2 to Class 3 Locations – Florida Page 14 of 53 <<>> ii) Crack Detection Tool Assessment: FGT must run an electro-magnetic acoustic transducer (EMAT) ILI tool or other equivalent crack detection ILI tool in the extended special permit segment; iii) MAOP Lowered: FGT must lower the MAOP of the special permit segment to 60% specified minimum yield strength (SMYS). iv) Pipe Replacement: FGT must replace all pipe and comply with 49 CFR 192.611 and 192.619 in the special permit segment; or v) Operating Pressure Lowered: FGT must lower the operating pressure of the special permit segment to 20% below the maximum pressure during the preceding 90-day operating interval until FGT conducts an ECA and remediates the special permit segment. f) SCC Remediation Plan: If FGT discovers any SCC activity in the extended special permit segment, FGT must submit an SCC remediation plan to the Director, PHMSA Southwest Region, and send a copy to the Director, PHMSA Engineering and Research Division, no later than 90 days after the finding of SCC.36 The plan must: i) Meet Condition 7(e) and include an SCC remediation/repair plan with SCC characterization and timing; or ii) Include a technical justification that shows that FGT is addressing the threat for SCC in the special permit segment. 8) Condition 8 - Anomaly Evaluation and Remediation a) General: FGT must use the procedures specified in the special permit conditions, 49 CFR 192.712, and Attachment A when evaluating anomalies. FGT must account for ILI tool tolerance and corrosion growth rates in determining scheduled response times and repairs and must document and justify the values used. i) ILI Tool Accuracy: FGT must demonstrate ILI tool tolerance accuracy for each ILI tool run by using calibration excavations and unity plots that demonstrate ILI tool accuracy to meet the tool accuracy specification provided by the vendor (typical for depth within +10% accuracy for 80% of the time). FGT must incorporate ILI tool accuracy by ensuring that each ILI tool service provider determines the tolerance of each tool and includes that 36 For FGT to go forward with the technical justification for addressing the SCC threat, FGT must receive a “no objection” letter from the Director, PHMSA Southwest Region. PHMSA-2023-0022 – Florida Gas Transmission Company, LLC Draft Special Permit – Class 1 and 2 to Class 3 Locations – Florida Page 15 of 53 <<>> tolerance in determining the size of each anomaly feature reported to FGT. FGT must compare previous indications to current indications that are significantly different. If a trend is identified where the tool has been consistently overcalling or under-calling, the remaining ILI features must be re-graded accordingly. ILI tools used must be calibrated as follows: (1) General ILI Tool Calibration: ILI tool calibrations must use ILI tool run results and anomaly calibrations from either the special permit inspection area or from the complete ILI tool run segment if the continuous ILI segment is longer than the special permit inspection area. ILI calibration excavations may include previously excavated anomalies or recent anomaly excavations with known dimensions that were field measured for length, depth, and width, externally re-coated, CP maintained, and documented for ILI calibrations prior to the ILI tool run. A minimum of four (4) calibration excavations must be used for unity plots.37 (2) EMAT ILI Tool Calibration: (a) ILI calibration for EMAT ILI Tools must be based upon excavation results of a minimum of the two (2) most severe anomalies from a combined review of crack depth and length. If the EMAT tool identifies only one (1) anomaly, the anomaly must be excavated and assessed. FGT can propose alternative EMAT ILI Tool evaluation procedures to the Director, PHMSA Southwest Region, but must receive a “no objection” letter prior to usage of these procedures. (b) If the EMAT ILI tool does not identify any cracking anomalies above the minimum length and depth criteria for 90% probabilit - **truncated:** true - **body characters:** 156564