# U.S. DOT/PHMSA - Signed Special Permit - **operation:** document - **citation:** 0900006480e91c2d - **title:** U.S. DOT/PHMSA - Signed Special Permit - **source type:** rulemaking - **agency:** Pipeline and Hazardous Materials Safety Administration - **status:** current - **official:** true - **published on:** Not available - **effective on:** Not available - **summary:** U.S. DEPARTMENT OF TRANSPORTATION 1 PIPELINE AND HAZARDOUS MATERIALS SAFETY ADMINISTRATION (PHMSA) SPECIAL PERMIT Docket Number: PHMSA - 2008-0330 Requested By: Columbia Gulf Transmission Company' Date Requested: November 13, 2008 Code Section(s): 49 CFR $ 192.611 Grant of Special Permit: By this order, subject to the terms and conditions set forth below the Pipeline and... 2 • Special Permit Segment 2: 36-inch Mainline 300 - 1600 feet, Sta. 3025+55 to Sta. 3041+55 Special permit inspection areas - means the area that extends 220 yards on each side of the centerline along the entire length of the 30-inch Mainline 200 and 36-inch Mainline 300 pipelines defined as follows: • Special Permit... - **machine formats:** - **json:** https://regulus.evalyn.ai/document/regulations-gov-attachment-0900006480e91c2d.json - **markdown:** https://regulus.evalyn.ai/document/regulations-gov-attachment-0900006480e91c2d.md - **app url:** https://regulus.evalyn.ai/document/regulations-gov-attachment-0900006480e91c2d - **source url:** https://downloads.regulations.gov/PHMSA-2008-0330-0004/attachment_1.pdf **body:** <<>> U.S. DEPARTMENT OF TRANSPORTATION 1 PIPELINE AND HAZARDOUS MATERIALS SAFETY ADMINISTRATION (PHMSA) SPECIAL PERMIT Docket Number: PHMSA - 2008-0330 Requested By: Columbia Gulf Transmission Company' Date Requested: November 13, 2008 Code Section(s): 49 CFR $ 192.611 Grant of Special Permit: By this order, subject to the terms and conditions set forth below the Pipeline and Hazardous Materials Safety Administration (PHMSA) grants this special permit to Columbia Gulf Transmission Company (Columbia Gulf) waiving compliance from 49 CFR § 192.611(a) for two natural gas transmission pipeline segments in the Mt. Juliet area, Wilson County, Tennessee as described below. Special Permit Segments and Inspection Areas: Williamson, Davidson, Wilson, Sumner and Trousdale Counties, Tennessee PHMSA waives compliance from 49 CFR § 192.611(a) for two natural gas transmission pipeline segments on the 30-inch Mainline 200 and 36-inch Mainline 300 pipelines, where a change has occurred from a Class 1 location to a Class 3- location in the Mt. Juliet area, Wilson County, TN. The Federal pipeline safety regulations in 49 CFR § 192.611(a) require natural gas pipeline operators to confirm or revise the maximum allowable operating pressure (MAOP) of a pipeline segment after a change in class location. This special permit allows Columbia Gulf to continue to operate each special permit segment at its current maximum allowable operating pressure (MAOP) of 1008 pounds per square inch gauge (psig) for the 30-inch Mainline 200 and 36-inch Mainline 300 pipelines. This special permit applies to the special permit segments defined as follows using the Columbia Gulf pipeline survey stationing (Sta.): • Special Permit Segment I: 30-inch Mainline 200 - 1600 feet, Sta. 3030+43 to Sta. 3046+43 'Columbia Gulf Transmission Company (Columbia Gulf) is owned and operated by NiSource Gas Transmission and Storage (NGT&S). location in accordance with § 192.611 (a) hydrostatic test. 2 The Class 3 location special permit segments were originally a Class 1 location that were upgraded to a Class 2 <<>> 2 • Special Permit Segment 2: 36-inch Mainline 300 - 1600 feet, Sta. 3025+55 to Sta. 3041+55 Special permit inspection areas - means the area that extends 220 yards on each side of the centerline along the entire length of the 30-inch Mainline 200 and 36-inch Mainline 300 pipelines defined as follows: • Special Permit Inspection Area 1: 30-inch Mainline 200 - Sta. 1710+43 to Sta. 4366+43 (50.30 miles) Special Permit Inspection Area 2: 36-inch Mainline 300 - Sta. 1705+55 to Sta. 4361+55 (50.30 miles) The special permit inspection areas are located in Williamson, Davidson, Wilson, Sumner and Trousdale Counties, TN. The special permit inspection areas start downstream of the Hampshire Compressor Station and ends upstream of the Hartsville Compressor Station for a total mileage of 50.30 miles. Note: The special permit inspection areas extend approximately 50.30 miles along each pipeline (Mainlines 200 and 300) with overlapping areas and includes the special permit segments. PHMSA grants this special permit based on the findings set forth in the "Special Permit Analysis and Findings" document, which can be read in its entirety in Docket No. PHMSA-2008-0330 in the Federal Docket Management System (FDMS) located on the internet at www.Regulations.gov. Conditions: PHMSA grants this special permit subject to the following conditions: 1) Columbia Gulf must continue to operate the special permit segments at or below their existing MAOP as follows: the 30-inch Mainline 200 and 36-inch Mainline 300 pipelines - MAOP 1008 psig. 2) Columbia Gulf must incorporate each of the special permit segments and special permit inspection areas into its written integrity management program (IMP) as a "covered segment" in a "high consequence area (HCA)" per § 192.903, except for the reporting requirements contained 3 "Each condition that requires Columbia Gulf to perform an action with respect to the Special Permit Inspection Area shall also require Columbia Gulf to perform that action on all Special Permit Segments within such Areas." <<>> in § 192.945. Columbia Gulf need not include the special permit segments described in this special permit in its IMP baseline assessment plan unless those segments are in HCAs, in accordance with § 192.905. 3) Columbia Gulf must perform a close interval survey (CIS) of the Mainline 200 & 300 pipelines along the entire length of all special permit segments and special permit inspection areas and remediate any areas of inadequate cathodic protection no later than one year after the grant of this special permit. A CIS and remediation need not be performed if Columbia Gulf has performed a CIS and remediation on the Mainlines 200 & 300 pipelines along the entire length of all special permit inspection areas less than two years prior to the grant of this special permit. If factors beyond Columbia Gulf's control prevent the completion of the CIS and remediation within one year, a CIS and remediation must be completed as soon as practicable and a letter justifying the delay and providing the anticipated date of completion must be submitted to the Director, PHMSA Southern Region* no later than one year after the grant of this special permit. 4) Columbia Gulf must perform periodic CIS of the special permit segments and special permit inspection areas at least once every 5 calendar years at reassessment intervals not exceeding 63 months. CGTC must also integrate CIS data with in-line inspection (ILI) data, and data on any other threats, in accordance with 49 CFR §§ 192.937 (a) and (b), and 192.917. 5) Within one year of the grant of this special permit Columbia Gulf must perform a Direct Current Voltage Gradient (DCVG) survey or an Alternating Current Voltage Gradient (ACVG) survey of each special permit segment to determine the pipeline coating conditions and must then remediate any integrity issues in the special permit segments. A DCVG or ACG survey and remediation need not be performed on the special permit segments if Columbia Gulf has performed a DCVG or ACVG and remediation in accordance with this special permit condition on the Mainline 200 & 300 pipelines along the entire length of all special permit inspection areas less than two years prior to the grant of this special permit. Columbia Gulf must remediate any damaged coating indications found during these assessments that are classified as moderate (i.e. 35% IR and above for DCVG or 50 dBuV and above for ACVG) or severe based on NACE 4 "In the case of any Special Permit condition that requires Columbia Gulf to provide documentation to the PHMSA Region, Columbia Gulf must also send a copy of such documentation to the appropriate state authorities, in states that have interstate agent agreements with PHMSA." <<>> International Recommended Practice 0502-2002, "Pipeline External Corrosion Direct 4 Assessment Methodology, " (NACE RP 0502-20025). A minimum of two coating survey assessment classifications must be excavated, classified and/or remediated per each survey crew per each time the survey is performed. If factors beyond Columbia Gulf's control prevent the completion of the DCVG or ACVG survey and remediation within one year, a DCVG or ACVG survey and remediation must be performed as soon as practicable and a letter justifying the delay and providing the anticipated date of completion must be submitted to the Director, PHMSA Southern Region no later than one year after the grant of this special permit. 6) Columbia Gulf must evaluate the Mainline 200 & 300 pipelines for stress corrosion cracking (SCC) as follows: a) Columbia Gulf must perform a stress corrosion cracking direct assessment (SCCDA) or other appropriate assessment method for SCC [such as pressure test or ILI with a crack detection tool] of the Mainline 200 & 300 pipelines along the entire length of the special permit inspection areas, according to the requirements of § 192.929 and/or NACE SP 0204-2008 and remediate any SCC found, no later than one year after of the grant of this special permit. The SCCA or other approved method must address both high pH SCC and near neutral pH SCC. A SCCA need not be performed if Columbia Gulf has performed a SCCA of the Mainline 200 & 300 pipelines along the entire length of the special permit inspection areas less than two years prior to the grant of this special permit. If factors beyond Columbia Gulf's control prevent the completion of the SCCA survey and remediation within one year, a SCCA and remediation must be performed as soon as practicable and a letter justifying the delay and providing the anticipated date of completion must be submitted to the Director, PHMSA Southern Region no later than one year after the grant of this special permit. Columbia Gulf may eliminate this Condition 6 (a), provided Columbia Gulf provides an engineering assessment showing that the pipeline does not meet any of the criteria for both near neutral and high pH SCC per the applicable edition of the American Society of Mechanical Engineers Standard B31.8S, "Managing System Integrity of Gas Pipelines" (ASME B31.8S) Appendix A3, or NACE SP 0204-2008, "Stress Corrosion Cracking (SCC) Direct Assessment Methodology", ", Section 1.2.1.1 and 1.2.2]. 5 "When PHMSA adopts a revised edition of a referenced NACE or ASME standard into 49 CFR Part 192, the referenced requirements of those revised standards are automatically incorporated into these special permit conditions." <<>> b) When the Columbia Gulf Mainline 200 or 300 pipelines are exposed for any reason in the special permit segments and special permit inspection areas and the coating has been identified as poor during the pipeline examination, then Columbia Gulf must directly examine the pipe for SCC using an accepted industry detection practice such as dry or wet magnetic particle tests. Poor coating is a coating that has become damaged and is losing adhesion to the pipe which is shown by falling off the pipe, is porous, has pin holes, and/or shields the cathodic protection. Visual inspection is not sufficient to determine if the coating is damaged and a holiday detection test at the correct voltage must be performed. Columbia Gulf must keep coating records of all excavation locations in the special permit segments and special permit inspection areas to demonstrate the coating condition. 7) Columbia Gulf must submit the DCVG or ACVG, CIS and SCCDA [or other PHMSA approved methods of determining SCC] findings including remediation actions in a written report to the Director, PHMSA Southern Region, no later than one year after the grant of this special permit. 8) Columbia Gulf must amend applicable sections of its operations and maintenance (O&M) manual(s) to incorporate the inspection and reassessment intervals by in-line inspection (ILI) including both metal loss and geometry tools of the Mainline 200 & 300 pipelines along the entire length of the special permit segments and special permit inspection areas at a frequency consistent with 49 CFR Part 192, Subpart O. [Deformation tools may be substituted for geometry tools, in accordance with Condition 20 (c). J Condition 20(c) requires Columbia Gulf to run deformation tools on the pipelines. 9) Columbia Gulf must amend applicable sections of its O&M manual(s) to require CIS inspection and reassessment intervals of the Mainlines 200 & 300 special permit segments and special permit inspection areas at a frequency consistent with 49 CFR Part 192, Subpart O, but at least once every five (5) calendar years at reassessment intervals not exceeding 63 months. 10) Columbia Gulf must perform an ILI assessment along the entire length of the special permit segments and special permit inspection areas using high resolution MFL and deformation in-line inspection tools within 6 months of issuance of this permit and must remediate discovered conditions in accordance with Condition 20 of this permit. Subsequent ILI assessments of the Mainline 200 & 300 pipelines along the entire length of the special permit inspection areas must <<>> conform to the required maximum reassessment intervals specified in § 192.93, but at least once 6 every 5 calendar years at reassessment intervals not exceeding 63 months. 11) Columbia Gulf must schedule ILI reassessment dates for the Mainline 200 & 300 pipelines along the entire length of the special permit segments and special permit inspection areas according to $ 192.939 by adding the required time interval to the previous assessment date, but reassessments must be at least once every 5 calendar years at intervals not exceeding 63 months. 12) Columbia Gulf must incorporate the applicable best practices of the Common Ground Alliance (CGA) into its damage prevention program within the special permit segments and special permit inspection areas. 13) Columbia Gulf must give a minimum of 14 days notice to the Director, PHMSA Southern Region to enable him/her to observe the excavations relating to Conditions 5, 6 (b), 19, 20, 21, 22, 23 and 24 in the special permit segments and special permit inspection areas. Immediate response conditions do not require a 14-day notice, but the PHMSA Region Director must be notified by Columbia Gulf no later than two business days after the immediate condition is discovered. 14) Columbia Gulf shall not use this special permit as a basis for deferring any of it's assessments for HCAs under 49 CFR Part 192, Subpart O. 15) Within three months following the grant of this special permit and annually thereafter, Columbia Gulf must report the following to the Director, PHMSA Southern Region: a) In the first annual report, Columbia Gulf must describe the economic benefits of the special permit including both the costs avoided from not replacing the pipe and the added costs of the inspection program. Subsequent annual reports should address any changes to these economic benefits. b) In the first annual report, fully describe whether the public benefits from energy availability. This should address the benefits of avoided disruptions as a consequence of pipe replacement Annual reports must be received by PHMSA by the last day of the month in which the Special Permit is dated. For each year beginning in 2011. example, the annual report for a Special Permit dated January, 2010, must be received by PHMSA no later than January <<>> and the benefits of maintaining system capacity. Subsequent reports must indicate any changes to this initial assessment. c) The number of new residences, other structures intended for human occupancy and public gathering areas built within the special permit segments and special permit inspection areas. d) Any new integrity threats identified during the previous year and the results of any ILl or direct assessments performed during the previous year in the special permit segments and special permit inspection areas. e) Any reportable incident, any leak normally indicated on the DOT Annual Report and all repairs on the pipeline that occurred during the previous year in the special permit segments and special permit inspection areas. f) Any on-going damage prevention initiatives affecting the special permit segments and special permit inspection areas and a discussion of the success of the initiatives. g) Any mergers, acquisitions, transfer of assets, or other events affecting the regulatory responsibility of the company operating the pipeline. 16) At least one cathodic protection (CP) pipe-to-soil test station must be located within each HCA with a maximum spacing between test stations of one-half mile within an HCA. In cases where obstructions or restricted areas prevent test station placement, the test station must be placed in the closest practical location. This requirement applies to any HCA within the special permit segments and special permit inspection areas. 17) If any annual CP test station readings on the Mainline 200 & 300 within the special permit segments and special permit inspection areas fall below 49 CFR Part 192, Subpart I requirements, remediation must occur within six months and include a CIS on each side of the affected test station to the next test station and perform any identified corrosion system modifications to ensure acceptable corrosion control. If factors beyond Columbia Gulf's control prevent the completion of remediation within six months, remediation must be completed as soon as practicable and a letter justifying the delay and providing the anticipated date of completion must be submitted to the Director, PHMSA Southern Region, no later than the end of the six months completion date. 18) Interference Currents Control: Columbia Gulf must address induced AC from parallel electric transmission lines and other interference issues in the special permit segments and special permit <<>> inspection areas that may affect the pipeline. An induced AC program and remediation to 8 protect the pipeline from corrosion caused by stray currents must be in place within one year of the date of this special permit. 19) Field Coating: The coatings used on the pipeline and girth weld joints in the special permit segments and special permit inspection areas must be non-shielding to CP. In the event that the coating type is unknown or is known to shield CP for girth weld joints then Columbia Gulf must take special care to: a) Analyze ILl logs in the areas of girth welds for potential corrosion indications. b) Any ILI corrosion indications above 30% wall loss at girth welds where the coating type is unknown or is known to shield CP, girth weld joints must be exposed and evaluated each time the ILI is run or until the girth weld coating is replaced c) A minimum of two girth weld joints at locations most likely to have shielding and corrosion shall be exposed and evaluated each time ILl is run. If corrosion is found, the next most likely joint is to be exposed and evaluated until no corrosion is found. 20) Anomaly Evaluation and Repair: a) General: Columbia Gulf must account for ILI tool tolerance and corrosion growth rates in scheduled response times and repairs and document and justify the values used. Columbia Gulf must demonstrate ILI Tool tolerance accuracy for each ILI Tool run by usage of calibration excavations (minimum of 5 excavations for each ILI Tool run) and unity plots that demonstrate ILI Tool accuracy for depth within +/-10% accuracy for 80% of the time. The unity plots must show: a) actual anomaly depth versus predicted depth and b) actual failure pressure/MAOP versus predicted failure pressure/MAOP. Discovery date must be within 60 days of an ILI Tool run for each type ILI Tool (geometry, deformation or high resolution MFL). b) Dents: Columbia Gulf must repair dents to the Mainline 200 & 300 pipelines in the special permit inspection areas in accordance with § 192.933 repair criteria. Special permit segments and special permit inspection areas must have a geometry tool inspection as part of the initial ILI and all dent repairs made in accordance with § 192.933 repair criteria. The geometry tool can be from past ILI inspections. The timing for these dent repairs should follow Columbia Gulf's O&M Manual but must not be longer than 1 year after discovery. c) Deformation Tool: Columbia Gulf must run a deformation tool through all special permit <<>> 9 segments and special permit inspection areas within 6 months of the grant of this special permit and remediate all expanded pipe in accordance with PHMSA's "Interim Guidelines for Confirming Pipe Strength in Pipe Susceptible to Low Yield Strength", dated September 10, 2009, within 12 months of grant date of this special permit. d) Investigation and Repair Criteria: Investigation, evaluation, and repair criteria apply to all anomalies located on the Mainline 200 & 300 pipelines within the special permit segments and special permit inspection area when they have been excavated, investigated, and remediated in accordance with §$ 192.485 and 192.933 incorporating appropriate class location design factors in the anomaly repair criteria, including HAs as follows: • Special permit segments - Repair any anomaly within a special permit segment that meets either: (1) a failure pressure ratio? (FPR) less than or equal to 1.39 for original Class 1 location pipe in a Class 3 location operating up to 72% of the specified minimum yield strength (SMYS); (2) an anomaly depth greater than or equal to 40% of pipe wall thickness. • Special permit inspection area - Repair any anomaly within a special permit inspection area that meets either: (1) an FPR less than design factor - for Class 1 location - FPR equal to or less than 1.39; for Class 2 location - FPR equal to or less than 1.67; and for Class 3 location - FPR equal to or less than 2.0; (2) an anomaly depth equal to or greater than 60% wall thickness loss. - Repair anomalies in original Class 1 location pipe that are now in a Class 2 location in accordance with §§ 192.5 and 192.611 that meets either: (1) is equal to or less than the Class 1 location FPR of 1.39; (2) an anomaly depth equal to or greater than 50% wall thickness loss for anomaly repairs. - Repair anomalies in original Class 2 location pipe that is now in a Class 3 location in accordance with § 192.611 that meets either: (1) is equal to or less than the Class 2 location FPR of 1.67; (2) an anomaly depth equal to or greater than 50% wall thickness loss for anomaly repairs. e) Response Time for ILI Results: The following guidelines provide the required timing for excavation, investigation, and remediation of anomalies based on ILI data results in accordance with §§ 192.485 and 192.933, and must incorporate appropriate class location design factors in the anomaly repair criteria for special permit segments and special permit " Failure pressure ratio (FPR) is based upon the class location where the special permit segment or special permit inspection area pipe is located in accordance with § 192.5 and is the reciprocal of the class location design factor in § 192.111(a). <<>> inspection area including all HCAs. Reassessment by ILI will reset the timing for 10 anomalies not already investigated and/or repaired. CGTC must evaluate ILI data by using either the ASME Standard B31G, "Manual for Determining the Remaining Strength of Corroded Pipelines" (ASME B31G), the modified B31G (0.85dL) or R-STRENG for calculating the predicted FPR to determine anomaly responses. • Special permit segments: - Immediate response: Any anomaly within a special permit segment operating up to 72% SMYS that meets either: (1) an FPR equal to or less than 1.1; (2) an anomaly depth equal to or greater than 80% wall thickness loss. - One-year response: Any anomaly within a special permit segment with original Class 1 location pipe in a Class 3 location operating up to 72% SMYS that meets either: (1) an FPR equal to or less than 1.39; (2) an anomaly depth equal to or greater than 40% wall thickness loss. - Monitored response: Any anomaly within a special permit segment with original Class 1 location pipe in a Class 3 location operating up to 72% SMYS that meets both: (1) an FPR greater than 1.39; (2) an anomaly depth less than 40% wall thickness loss. The schedule for the response must take tool tolerance and corrosion growth rates into account. • Special permit inspection areas: - Immediate response: Any anomaly within a special permit inspection area operating up to 72% SMYS that meets either: (1) an FPR equal to or less than 1.1; (2) an anomaly depth equal to or greater than 80% wall thickness loss. - One-year response: Any anomaly within a special permit inspection area that meets either: (1) an FPR less than design factor - for Class 1 location- FPR equal to or less than 1.39; Class 2 location - FPR equal to or less than 1.67; and for Class 3 location - FPR equal to or less than 2.0; (2) an anomaly depth equal to or greater than 60% wall thickness loss. Any anomaly for Class location changes from original Class 1 to 2 location or original Class 2 to 3 location in accordance with §§ 192.5 and 192.611 that meets either: (1) an anomaly FPR equal to or less than the FPR of the original Class location ; (2) an anomaly depth equal to or greater than 50% wall thickness loss. - Monitored response: Any anomaly within a special permit inspection area that meets both: (1) an FPR less than design factor - for Class 1 location - FPR greater <<>> than 1.39; Class 2 location - FPR greater than 1.67; and for Class 3 location - FPR greater than 2.0; (2) an anomaly depth less than 60% wall thickness loss. Any anomaly repairs for Class location changes from original Class 1 to 2 location or original Class 2 to 3 location in accordance with §§ 192.5 and 192.611 that meets both: (1) an anomaly FPR greater than the FPR of the original Class location; (2) an anomaly depth less than 50% wall thickness loss. The schedule for the response must take tool tolerance and corrosion growth rates into account. 21) Columbia Gulf must comply with the following provisions: a) Columbia Gulf must provide records to PHMSA to demonstrate that the girth welds on the Mainline 200 & 300 pipelines were non-destructively tested at the time of construction in accordance with the Federal pipeline safety regulations at the time the pipelines were constructed. If not, show that at least 10% of the girth welds in each special permit segment were non-destructively tested after construction, but prior to the application for this special permit provided at least two girth welds in each special permit segment were excavated and inspected. If Columbia Gulf cannot provide girth weld records to PHMSA to demonstrate either of the above, Columbia Gulf must accomplish either: (i); (ii) and (ili), or (ii) and (iv) of the following: 1) Certify to PHMSA in writing that there have been no in-service leaks or breaks in the girth welds on the Mainline 200 & 300 pipelines within the entire special permit inspection areas for the entire life of the pipelines. ii) Evaluate the terrain along the special permit segments for threats to girth weld integrity from soil or settlement stresses and remediate all such integrity threats. ili) Excavate® , visually inspect and nondestructively test at least two girth welds on the Mainlines 200 & 300 pipelines in each special permit segment in accordance with the American Petroleum Institute Standard 1104, "Welding of Pipelines and Related Facilities" (API 1104) as follows: A. Use the edition of API 1104 current at the time the pipelines were constructed; or B. Use the edition of API 1104 recognized in the Federal pipeline safety regulations at the time the pipelines were constructed; or & Columbia Gulf must evaluate for SCC any time the Mainline 200 & 300 pipelines are uncovered in accordance with Condition 6 (b) of this special permit. <<>> C. Use the edition of API 1104 currently recognized in the Federal pipeline 12 safety regulations. iv) As an alternative to Condition 21 (a) (iii), Columbia Gulf may perform an HRMFL in-line inspection capable of identifying girth weld anomalies. If this technique is employed, Columbia Gulf must develop a technical basis for evaluating the serviceability of the girth welds based on HRMFL ILI data. The girth weld ILI inspection plan including ILI findings, technical determination for identifying weld anomalies and confirmation excavations must be submitted to Director, PHMSA Southern Region for approval 14 days prior to confirmation excavations. b) If any girth weld in any of the special permit segments does not comply with API 1104, Columbia Gulf must repair the girth weld immediately and then prepare an inspection and remediation plan for all remaining girth welds in the special permit segments based upon the repair findings and the threat to the special permit segments. Columbia Gulf must submit the inspection and remediation plan for girth welds to the Director, PHMSA Southern Region and remediate girth welds in the special permit segments in accordance with the inspection and remediation plan within 60 days of finding girth welds that do not meet this Condition 21 (c). c) All oxy-acetylene girth welds, mechanical couplings, and wrinkle bends in special permit segments must be removed. d) Columbia Gulf must complete the girth weld testing, and the girth weld inspection and remediation plan, within six months after the grant of this special permit. If factors beyond Columbia Gulf's control prevent the completion of these tasks within six months, the tasks must be completed as soon as practicable and a letter justifying the delay and providing the anticipated date of completion must be submitted to the Director, PHMSA Southern Region no later than six months after the grant of this special permit. 22) Columbia Gulf must identify all shorted casings (metallic or electrolytic) within the special permit segments and special permit inspection areas no later than six months after the grant of this special permit and classify any shorted casings as either having a "metallic short" (the carrier pipe and the casing are in metallic contact) or an "electrolytic short" (the casing is filled with an electrolyte) using a commonly accepted method such as the Panhandle Eastern, Pearson, DCVG, ACVG or AC Attenuation. <<>> a) Metallic Shorts: Columbia Gulf must clear any metallic short on a casing in the special 13 permit segments and special permit inspection areas no later than six months after the short is identified. b) Electrolytic Shorts: Columbia Gulf must remove any electrolyte from the casing/pipe annular space on any casing in the special permit segments and special permit inspection areas that has an electrolytic short no later than six months after the short is identified. c) All Shorted Casings: Columbia Gulf must install external corrosion control test leads on both the carrier pipe and the casing in accordance with § 192.471 to facilitate the future monitoring for shorted conditions and may then choose to fill the casing/pipe annular space with a high dielectric casing filler or other material which provides a corrosion inhibiting environment provided an assessment and all repairs were completed. If Columbia Gulf identifies any shorted casings within the special permit segments and special permit inspection areas, they must monitor' all casings within the special permit segments and special permit inspection areas for shorts at least once each calendar quarter, but at intervals not to exceed 100 days, for four consecutive calendar quarters after the grant of this special permit. The intent is to identify through monitoring the calendar quarters) when electrolytic casing shorts are most likely to be identified. Columbia Gulf must then monitor all casings for shorts within the special permit segments and special permit inspection areas at least once each calendar year during the calendar quarters) when electrolytic casing shorts are most likely to be identified. Any casing shorts found in the special permit segments and special permit inspection areas at any time must be classified and cleared as explained above. 23) Pipe Seam Evaluations: Columbia Gulf must identify any pipeline in the special permit segments and special permit inspection area that may be susceptible to pipe seam issues because of the vintage of the pipe, the manufacture of the pipe, or other issues. Once Columbia Gulf has identified such issues, they must complete one or all of the following: a) Columbia Gulf must perform an engineering analysis to determine if there are any pipe seam threats on the Mainline 200 & 300 pipelines located in the special permit segments and special permit inspection area. This analysis must include the documentation that the processes in 'M Charts' in "Evaluating the Stability of Manufacturing and Construction Defects in Natural Gas Pipelines" by Kiefner and Associates updated April 26, 2007, ' Monitoring of casings in this situation means an acceptable test method in accordance with 49 CFR Part 192 to determine if the casing and carrier pipe have either a metallic or electrolytic short (connection or contact). <<>> 14 under PHMSA Contract DTFAA-COSPO2120 and Figure 4.2, 'Framework for Evaluation with Path for the Segment Analyzed Highlighted' from TTO-5 "Low Frequency ERW and Lap Welded Longitudinal Seam Evaluation" by Michael Baker Jr., and Kiefner and Associates, et. al. under PHMSA Contract DTRS56-02-D-70036 were utilized along with other relevant materials. If the engineering analysis shows that the pipe seam issues on the Mainline 200 & 300 pipelines located in the special permit segments and special permit inspection area are not a threat to the integrity of the pipeline, Columbia Gulf does not have to complete Conditions 23 (b) through 23 (e). If there is a seam integrity threat to the integrity of the pipeline, then one or more of Conditions 23 (b) through 23 (e) must be completed; b) The special permit segment pipeline must be hydrostatically tested to a minimum pressure of 100 percent SMYS, per 49 CFR Part 192, Subpart J requirements for eight continuous hours, within one year of issuance of this special permit if no 49 CFR Part 192, Subpart J test has been performed since 1971. The hydrostatic test must confirm no systemic issues with the weld seam or pipe. A root cause analysis, including metallurgical examination of the failed pipe, must be performed for any failure experienced to verify that it is not indicative of a systemic issue. The results of this root cause analysis must be reported to each PHMSA pipeline safety region office where the pipe is in service within 60 days of the failure; or c) If the pipeline in the special permit inspection area has experienced a seam leak or failure in the last five years and no hydrostatic test meeting the conditions per 49 CFR Part 192, Subpart J was performed after the seam leak or failure, then a hydrostatic test must be performed within one year after the grant of this special permit on the special permit segment pipeline; and d) If the pipeline in the special permit segment has any LF ERW seam or EFW seam conditions as noted in (i), (ii), or (il) below, the special permit segment pipeline must be replaced: i) constructed or manufactured prior to 1954 and has had any pipe seam leaks or ruptures in the special permit inspection area, ii) has unknown manufacturing processes, or iii) has known manufacturing or construction issues that are unresolved [such as concentrated hard spots, hard heat-affected weld zones, selective seam corrosion, pipe movement that has led to buckling, have had past leak and rupture issues, or any other <<>> other systemic issues]. 15 e) If the pipeline in the special permit segment has a reduced longitudinal joint seam factor, below 1.0, as defined in § 192.113 the special permit segment pipeline must be replaced. f) All pipe in special permit segments and special permit inspection areas must have all weld seam or girth weld repairs that have been made by the usage of fittings such as weldolets, threadolets, repair clamps and pipe sleeves removed and replaced with pipe in accordance with 49 CFR Part 192 requirements. 24) Columbia Gulf must comply with the following requirements. a) Columbia Gulf must mechanically and hydrostatically test pipe in each special permit segment that does not meet Condition 25 (b) as follows: i) Test a minimum of 10% of pipe lengths/joints, or at least 2 pipe lengths/joints when the percentage is less than 2 pipe lengths/joints, in accordance with §§ 192.109 and 192.107(b). ii) Special permit segments pipe must meet the requirements of § 192.107 (b). iii) Special permit segments pipe must be tested for mechanical and chemical properties (properties) as required in § 192, Appendix B, Section III (B) and (C). iv) Pipe that is tested for properties in accordance with Condition 24 (a) (i),(a) (ii) and (a)(iii), must meet the hydrostatic test requirements of 49 CFR Part 192, Appendix B, Section III (C)(2). Original Class 1 location pipe that is approved for Class 3 locations per this special permit must be tested to a minimum of 100% SMYS for 8 continuous hours in accordance with 49 CFR Part 192, Subpart J. v) The requirements in Condition 24 (a) must be completed within one year of issuance of this special permit and must meet pipe properties requirements for the pipe designed class location factor in accordance with §§ 192.103. 192.105, 192.107, 192.109, 192.111 and 192.113. b) Columbia Gulf must complete within six (6) months of the grant of this special permit a depth of cover survey of the special permit segments. For any pipe in the special permit segments that does not meet § 192.327(a), Columbia Gulf must implement additional safety measures in areas with reduced depth of cover. Columbia Gulf must submit to the Director, PHMSA Southern Region remedial measures to implement based upon the threat, such as lowering the pipeline, increased pipeline patrols and/or additional line markers. <<>> c) Columbia Gulf must install and maintain line-of-sight markings on the pipeline in the 16 special permit segments and special permit inspection areas except in agricultural areas or large water crossings such as lakes where line-of-sight signage is not practical. d) Columbia Gulf must install pipeline warning tape above the pipe for the length of the excavation in all integrity excavations in the special permit segments and special permit inspection areas. 25) Columbia Gulf must maintain the following records for each special permit segment: a) Documentation showing that each special permit segment has received a § 192.505, Subpart J, hydrostatic test for 8 continuous hours and at a minimum pressure of 1.25 X MAOP. If Columbia Gulf does not have hydrostatic test documentation, then the special permit segment must be hydrostatically tested to meet this requirement within one year of receipt of this special permit. b) Documentation (mill test reports) showing that the pipe in each special permit segments meets the wall thickness, yield strength, tensile strength and chemical composition of either the American Petroleum Institute Standard 5L, 5LX or 5LS, "Specification for Line Pipe" (API 5L) referenced in 49 CFR Part 192 at the time of manufacturing or if pipe was manufactured and placed in-service prior to the inception of 49 CFR Part 192 then the pipe meets the API 5L standard in usage at that time. Any special permit segment that does not have mill test reports for the pipe can not be authorized per this special permit unless it is qualified in accordance with Condition 24 (a) above. c) Documentation of compliance with all conditions of this special permit must be kept for the applicable life of this special permit for the referenced special permit segments and special permit inspection areas. 26) PHMSA may extend the original special permit segments to include contiguous segments of the Mainline 200 & 300 pipelines up to the limits of the special permit inspection areas pursuant to the following conditions. Columbia Gulf must: a) Provide notice to the Director, PHMSA Southern Region, and PHMSA Headquarters of an extension request of the Mainline 200 & 300 special permit segments based on actual class location change, and include a schedule of inspections and of any anticipated remedial actions. All requests for special permit segment extensions must be submitted in the first nine (9) months of the § 192.611(d) timing limits. If PHMSA Headquarters or <<>> Region Director makes a written objection before the effective date of the requested 17 special permit segments extension (90 days from receipt of the above notice), the requested special permit extension does not b - **truncated:** true - **body characters:** 48779