# Southern Natural Gas Company, LLC — Pipeline Special Permit - **operation:** document - **citation:** PHMSA-2016-0006 - **title:** Southern Natural Gas Company, LLC — Pipeline Special Permit - **source type:** permit - **agency:** Pipeline and Hazardous Materials Safety Administration - **status:** current - **official:** true - **published on:** 2016-09-01 - **effective on:** 2016-09-01 - **summary:** PHMSA-2016-0006, issued 2016-09-01 for Southern Natural Gas Company, LLC's gas transmission system. - **machine formats:** - **json:** https://regulus.evalyn.ai/document/phmsa-special-permit-phmsa-2016-0006.json - **markdown:** https://regulus.evalyn.ai/document/phmsa-special-permit-phmsa-2016-0006.md - **app url:** https://regulus.evalyn.ai/document/phmsa-special-permit-phmsa-2016-0006 - **source url:** https://www.regulations.gov/docket/PHMSA-2016-0006 **body:** PHMSA pipeline special permit PHMSA-2016-0006. Operator: Southern Natural Gas Company, LLC. System: Gas Transmission. Issue date: 2016-09-01. Renewal: Mar 17, 2023. <<>> U.S. DEPARTMENT OF TRANSPORTATION PIPELINE AND HAZARDOUS MATERIALS SAFETY ADMINISTRATION SPECIAL PERMIT Special Permit Information: Docket Number: Requested By: Operator ID#: Date Requested: Original Issuance Date: Effective Dates: PHMSA-2016-0006 Southern Natural Gas Company, L.L.C. 18516 January 11 ,2016 September 1, 2016 Code Section(s): September 1, 2016 to September 1, 2021 49 CFR §§ 192.611 (a) and (d), 192.619(a), and 192.5 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) grants a special permit (PHMSA-20 16-0006) from September 1, 20 16 to September 1, 2021, to Southern Natural Gas Company, L.L.C. (SNG) 1 waiving compliance from 49 Code of Federal Regulations (CFR) §§ 192.6 11 (a) and (d), 192.619(a), and 192.5 for 26 special permit segments and 5.90 miles of natural gas transmission pipeline as described in Appendix A 2 of this special permit. I. Special Permit Segment and Special Permit Inspection Area: States of Alabama, Georgia, Louisiana, and Mississippi On the condition that SNG complies with the terms and conditions set forth below, this special permit waives compliance from 49 CFR § 192.611 (a) for 26 special permit segments and 5.90 miles of natural gas transmission pipeline as described in Appendix A. This special permit allows SNG to continue to operate each special permit segment listed in Appendix A at its 1 SNG is owned by Kinder Morgan, Inc. 2 Appendix A of this special permit lists the pipeline special permit segmetJt location (County and State), MAOP, class location, diameter, wall thickness, grade, seam type, boundaries, and other attributes. Special Permit: PHMSA-2016-0006- Southern Natural Gas Company Page 1 of27 <<>> current listed maximum allowable operating pressure (MAOP). The Federal pipeline safety regulations in 49 CFR § 192.611 (a) require natural gas pipeline operators to confirm or revise the MAOP of a pipeline segment after a change in class location. This special permit applies to the special permit segments listed in Appendix A. Special permit segments shall be divided into two (2) categories: Type A special permit segments and Type B special permit segments. Type A special permit segments include those special permit segments where there is a cluster, as described in 49 CFR § 192.5(c), ofmore than 10 buildings intended for human occupancy in a "class location unit" and for which the MAOP has not been confirmed in accordance with 49 CFR § 192.611 (a). Type A special permit segments must be replaced or pressure tested so that the MAOP is commensurate with the present class location within three (3) years of issuance of this special permit. Type A special permit segments3 total 1.54 mites of pipe as described in Attachment A. Type A special permit segments with pipe with integrity issues as determined by Conditions 6(c) and 14 or that have not been pressure tested in accordance with 49 CFR Part 192, Subpart J to 1.25 times MAOP of this special permit must be replaced within two and one-half (2Y 2) years of the grant of this special permit or within two (2) years of assessment finding. Type B special permit segments include those special permit segments where there is a cluster, as described in 49 CFR § 192.5(c), of I 0 or fewer buildings intended for human occupancy in a "class location unit" and for which the MAOP has not been confirmed in accordance with 49 CFR § 192.611 . Type B special permit segments4 total 4.36 miles of pipe as described in Attachment A. 3 There are 1.54 miles of Type A special permit segments and of this total 1.50 miles must be replaced and 0.04 miles must be pressure tested as listed on Attachment A, see Condition 16 for pressure test requirements. 4 There are 4.36 miles of Type B special permit segme11ts and 0.72 miles of this total must be pressure tested as listed on Attachment A, see Condition 16 for pressure test requirements. One (I ) Type B special permit segment (KM segment number 352) is a § 192.6 19(c) Grandfathered segment and wi ll require pressure testing. PHMSA-2016-0006- Southern Natural Gas Company Special Permit Page 2 of27 <<>> Subsequent to the issuance of this special permit, those special permit segments that have been pressure tested or replaced such that the MAOP has been made commensurate with the present class location as defined in 49 CFR § 192.6 11 would no longer be included in this special permit. 5 Special permit inspection area - is defined as a one ( I) mile continuous segment on both sides of the special permit segment (Type A and Type B) plus the footage in the special permit segment. Appendix A lists the boundaries for the special permit inspection area associated with each special permit segment. The SNG special permit inspection area totals 57.90 miles of pipe as described in Attachment A. PHMSA hereby grants this special permit for the pipeline special permit segments listed in Appendix A 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-2016-0006 in the Federal Docket Management System (FDMS) located on the internet at www.Regulations.gov. II. Conditions: PHMSA OPS grants this special permit subject to the following conditions: l) Maximum Allowable Operating Pressure: SNG must continue to operate the special permit segments at or below their existing MAOP as noted in Appendix A. 2) Integrity Management Program: SNG must incorporate the special permit inspection areas into its written integrity management program (IMP) as a "covered segment " in a "high consequence area (HCA) " in accordance with 49 CFR § 192.9036 . 3) Close Interval Surveys: SNG must perform a close interval survey (CIS) along the entire 5 Special permit inspection areas throughout these conditions include special permit segme11ts unless specifically defined as not applicable or if the special permit segment has more stringent conditions. 6 SNG is not required to report the mileage included as part of this special permit in its annual report per the requirements of 49 CFR § 191. 17, unless it is in a high consequence area. PHMSA-2016-0006- Southern Natural Gas Company Special Permit Page 3 of27 <<>> length of all special permit inspection areas 7 and remediate any areas of inadequate cathodic protecti on no later than three (3) years after the issuance of this special permit. However, a CIS need not be performed if SNG has performed a CIS and completed remediation8 including damaged coating repair along the entire length of all special permit inspection areas Jess than seven (7) years9 prior to the issuance of this special permit. If environmental permitting or right-of-way factors beyond SNG control should prevent the completion of the CIS within three (3) years from the issuance of this special permit, a CIS and subsequent remediation including coating repair 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 appropriate PHMSA OPS Region Director no later than three (3) months pri or to the end of three (3) years after the issuance of this special permit and must receive a "no objection" from the PHMSA OPS Region Director for a delay. CIS remediation activities must be completed within one (1) year of the finding. Any extended evaluation and remediation schedules submitted to PHMSA from SNG must receive a "no objection" from the appropriate PHMSA OPS Region Director to implement an extended CIS and remediation interval. 4) Close Interval Surveys- Reassessment Interval: SNG must perform a periodic close interval survey (CIS) of the special permit inspection areas at the applicable reassessment interval(s) for a "covered segment" in accordance with 49 CFR Part 192, Subpart 0, for reassessment intervals as contained in 49 CFR §§ 192.937(a) and (b) and 192.939, not to exceed a seven (7) year reassessment interval10 • CIS data shall be integrated with in-line inspection (ILl) data. Condition I5(b)- Data Integration - gives a complete description of 7 Each condition that requires SNG to perform an action with respect to the special permit inspection areas shall also require SNG to perform that action on all special permit segments within such areas. T ype A special permit segments that will be replaced within three (3) years of this special permit issuance do not require a CIS. 8 The terms "remediate" or "remediation" of pipe coating shall include repair of damaged external pipe coating, where required to maintain cathodic protection of the pipeline in accordance with 49 CFR § 192.463. 9 lf49 CFR § 1 92.939(a) integrity management reassessment interval sho uld change·from seven (7) years to some other reassessment interval under eig ht (8) years, SNG may use that reassessment interval instead of seven (7) years. 10 If 49 CFR § 192.939(a) integrity management reassessment interval should change from seven (7) years to some other reassessment interval under eight (8) years, SNG may use that reassessment interval instead of seven (7) years. PHMSA-2016-0006- Southern Natural Gas Company Special Permit Page 4 of27 <<>> data integration information that an operator must maintain for a special permit in the special permit inspection areas which includes CIS and ILl data. CIS assessments within the reassessment interval are not required to be performed in the same year as ILl reassessments. 5) Cathodic Protection Reliability Improvement Plan: SNG shall implement a plan to improve cathodic protection reliability and perform inspections for stress corrosion cracking (SCC). a) Cathodic Protection Reliability Improvement Plan i) SNG must perform a periodic CIS of special permit inspection areas as part of Condition 4, Close Interval Surveys, with reassessment intervals at an increased frequency, not to exceed a seven (7) year reassessment interval with CIS data integrated with the most-recent in-line inspection data 11 ; ii) SNG must integrate the most current CIS data with in-line inspection results in the special permit inspection area in accordance with Condition 15(b) timing requirements: iii) Within 90 days of the issuance of this special permit, SNG must amend applicable sections of its operations and maintenance (O&M) manual(s) to prohibit future use of coating that is known to shield cathodic protection along the entire length of the special permit inspection areas; and iv) SNG must perform a run comparison analysis of in-line inspection results subsequent to the baseline inspection in the special permit inspection areas to identify areas of external corrosion growth after each new tool run when the same in-line inspection vendor is used for consecutive inspections. Areas with corrosion growth over 30% in depth must be remediated within one ( 1) year of the finding or direct current voltage gradient (DCVG) survey run to locate problem coating areas within six (6) months of the finding with remediation completed within six (6) months of the DCVG survey. 11 lf49 CFR § 192.939(a) integrity management reassessment interval should change fTom seven (7) years to some other reassessment interval under eight (8) years, SNG may use that reassessment interval instead of seven (7) years. PHMSA-2016-0006- Southern Natural Gas Company Special Permit Page 5 of27 <<>> v) Within one ( 1) year of the issuance of this special permit, SNG must install cathodic protection remote monitoring units (RMUs) at all impressed current sources directly influencing the special permit segments; vi) SNG must configure the RMUs in the special permit segments with alarms to notify SNG immediately in the event of any interruption in cathodic protection current output; and vii)SNG must respond and correct any interruption in cathodic protection current output immediately (within two (2) working days). If a systemic issue is present, then SNG must investigate and remediate the problem within one ( 1) month or less or SNG must receive a "no objection" from the appropriate PHMSA OPS Region Director for issues that require longer to remediate. b) Stress Corrosion Cracking Inspections i) SNG must review historical records to determine if SCC inspections have been performed in the special permit segments and from these inspections evaluate the threat of stress-corrosion cracking as part of the SCCDA Pre- Assessment Step in Condition 6(a). ii) SNG must perform magnetic particle inspection on any pipe (with the exception of pipe coated with fusion-bonded or liquid-applied epoxy coatings, which are not at risk for SCC) excavated in the special permit inspection areas to evaluate the pipe for sec where disbonded coating is removed in order to perform the inspection. 6) Stress Corrosion Cracking Direct Assessment: SNG must evaluate pipelines along the entire length of the special permit inspection areas for sec as follows: a) SNG must perform a stress corrosion cracking direct assessment (SCCDA) or other appropriate assessment method for sec [such as pressure test or in-line inspection (ILl) with a crack detection tool] of pipelines along the entire length of all special permit inspection areas according to the requirements of 49 CFR § 192.929 and/or NACE SP 0204-2008 no later than three (3) years after of the issuance of this special PHMSA-2016-0006- Southern Natural Gas Company Special Permit Page 6 of27 <<>> permit. The SCCDA or other approved method must address high pH SCC and near neutral pH SCC. The SCCDA Pre-Assessment Step will include the results of all close-interval surveys and coating surveys required in Conditions 3, 4, and 5. i) If environmental permitting or right-of-way factors beyond SNG control prevent the completion of the SCCDA survey and remediation within three (3) years from the issuance ofthis special permit, a SCCDA 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 appropriate PHMSA OPS Region Director no later than three (3) months prior to the end of three (3) years after the issuance of this special permit and must receive a "no objection" from the PHMSA OPS Region Director for a delay. ii) SNG may eliminate this Condition 6(a), provided SNG provides an engineering assessment showing that the pipeline does not meet the criteria for either near neutral or high pH SCC in accordance with the applicable edition of the American Society of Mechanical Engineers Standard B31.8S, "Managing System Integrity of Gas Pipelines " (ASME B3 1.8S), Appendix A3, or NACE SP 0204-2008, "Stress Corrosion Cracking (SCC) Direct Assessment Methodology ", Section 1.2. 1.1 and 1.2.2. iii) A SCCDA need not be performed ifSNG has performed a SCCDA of pipelines along the entire length of the special permit inspection areas within the timeframe for SCCDA re-assessments specified in 49 CFR Part 192, Subpart 0 , not to exceed seven (7) years 1 2 prior to the issuance of this special permit. b) If the SCCDA required in Condition 6(a) demonstrates SCC, SNG must directly examine pipe in the special permit inspection areas for sec using an accepted industry detection practice, such as dry or wet magnetic particle tests, anytime the pipelines are exposed for any reason, including damage prevention activities. Poor coating is coating losing adhesion to the pipe which is shown by falling off the pipe, 1 2 If 49 CFR § 1 92.939(a) integrity management reassessment interval should change from seven (7) years to some other reassessment interval under eight (8) years, SNG may use that reassessment interval instead of seven (7) years. PHMSA-2016-0006- Southern Natural Gas Company Special Permit Page 7 of27 <<>> and/or shields the cathodic protection. SNG must keep coating records13 of all excavation locations for the special permit inspection areas to demonstrate the coating condition. c) If SCC14 activity is discovered by any means within the special permit inspection area in similar pipe and pipe coating vintage [in accordance with 49 CFR § 192.917(e)], or has had an in service or hydrostatic test sec failure or leak; the special permit segment must be further assessed and mitigated, using one of the following methods, within one ( I) year of finding SCC: i) Hydrostatic test program A. The SCC hydrostatic test program must be performed at a reassessment interval no greater than seven (7) calendar years (but may be at a lesser interval in accordance with the results of an engineering critical assessment) in the special permit segment. B. If pipe in the special permit segment leaks or ruptures during a hydrostatic test due to sec, all pipe in the special permit segment must be replaced with new pipe within 18 months of the completion of a successful SCC hydrostatic test. A successful SCC hydrostatic test must be completed prior to returning the special permit segment to operational service. ii) Crack detection tool assessment A. sec detection tool must be run in the special permit inspection area, B. All SCC 15 cracking found in the special permit segment must be replaced with new pipe within one (I ) year of finding sec, iii) Operating pressure lowered to 60% of the specified minimum yield strength (SMYS), iv) Replace all affected pipe to meet 49 CFR § 192.6 11 in the special permit segment. 1 3 The records must include, at a minimum, a description of the SNG 's detectio n procedures, records of finding, and mitigation procedures implemented for the excavation. 14 " SCC" activity shall be defined as over both I 0 percent wall thickness depth and 2-inches in length. 15 ··sec· activity shall be defined as over both I 0 percent wall thickness depth and 2-inches in length. PHMSA-2016-0006- Southern Natural Gas Company Special Permit Page 8 of27 <<>> d) If any SCC activity is discovered in the special permit inspection area, SNG must submit a SCC remediation plan to the appropriate PHMSA OPS Region Director with a copy to the Director, PHMSA OPS Engineering and Research Division no later than 60 days after the finding of SCC: i) That meets Condition 6(c), including a SCC remediation/repair plan with sec characterization and timing, or ii) Technical justification that shows that the threat for SCC in the special permit segment is being addressed. 7) O&M Manual- In-line Inspections, Close Interval Survey Inspections, and Reassessment Intervals: SNG must amend applicable sections of its operations and maintenance (O&M) manual(s) to incorporate the in-line inspection (ILl), close interval inspections (CIS), and reassessment intervals by the appropriate integrity assessment method including both high resolution metal loss and deformation/geometry tools along the entire length of the special permit inspection areas at a frequency consistent with 49 CFR Part 192, Subpart 0 , but not to exceed a seven (7) year reassessment interval1 6 • 8) In-Line Inspection Initial Assessment: SNG must perform integrity assessments along the entire length of the special permit inspection areas using appropriate assessment methods based on threats identified during the risk assessment process including both high resolution magnetic flux leakage (HR-MFL) and either HR-geometry or HR-deformation tools. If integrity assessments have not been performed within seven (7) years prior to the issuance of this special permit, SNG must complete initial integrity assessments along the entire length of the special permit inspection areas within three (3) years of the issuance of this special permit. Subsequent integrity assessments along the entire length of the special permit inspection areas must conform to the required maximum reassessment intervals specified in 49 CFR § 192.939, but may not exceed a seven (7) year reassessment interval17 . 1 6 If 49 CFR § 1 92.939(a) integrity management reassessment interval should change from seven (7) years to some other reassessment interval under eight (8) years, SNG may use that reassessment interval instead of seven (7) years. 17 If 49 CFR § 192.939(a) integrity management reassessment interval should change from seven (7) years to some other reassessment interval under eight (8) years, SNG may use that reassessment interval instead of seven (7) years. PHMSA-2016-0006 - Southern Natural Gas Company Special Permit Page 9 of27 <<>> 9) Integrity Reassessment Intervals: SNG must schedule integrity reassessment dates for the entire length of the special permit inspection areas according to 49 CFR § 192.939 by adding the required time interval to the previous assessment date, but may not exceed a seven (7) year reassessment interval 18 • 1 0) High Consequence Area Assessments: SNG must not let this special permit be a basis fo r deferring any of its assessments for HCAs in accordance with 49 CFR Part 192, Subpart 0. 11) Annual Reports to PHMSA: Within three (3) months following the issuance of this special permit and annually 1 9 thereafter, SNG must report the following to the appropriate PHMSA OPS Region Director with copies to the Deputy Associate Administrator, PHMSA Field Operations; Deputy Associate Administrator, PHMSA Policy and Programs; Director, PHMSA Engineering and Research Division; and Director, PHMSA Standards and Rulemaking Division: a) The number of new residences, other structures intended for human occupancy and public gathering areas built within the special permit segment and also within one ( I) mile on either end of the special permit segment. b) Any new integrity threats identified during the previous year and the results of any ILl or direct assessments performed (including any un-remediated anomalies over 30% wall loss, cracking found in the pipe body, weld seam or girth welds, and dents with metal loss, cracking or stress riser) during the previous year in the special permit inspection segment. c) Any reportable incident or 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 inspection areas. 18 If 49 CFR § 192.939(a) integrity management reassessment interval should change from seven (7) years to some other reassessment interval under eight (8) years, SNG may use that reassessment interval instead of seven (7) years. 1 9 Annual reports must be received by PHMSA by the last day of the month in which the Special Permit is dated. For example, the annual report for a modified Special Permit dated November, 20 1 2, must be received by PHMSA no later than November 30, each year beginning in 20 13. PHMSA-2016-0006- Southern Natural Gas Company Special Permit Page 10 of27 <<>> d) Summary report of any fatigue analysis performed on all in-service, non-remediated dents over 6% and with total strain :S 5%, as required in Condition 13(b ). e) Annual data integration information, as required in Condition l5(b) - Data Integration must be submitted beginning with the 2"d annual report that includes an annual overview of any new threats, or if requested by PHMSA a fu ll information package. f) Any mergers, acquisitions, transfer of assets, or other events affecting the regulatory responsibility of the company operating the pipeline. g) An updated Appendix A reflecting changes in Special Permit Segment boundaries including extensions, deletions, or modifications. h) In the first annual report, SNG must describe the estimated economic benefits of the special permit including both the capital and operational costs avoided from not replacing the pipe and the estimated incremental operational costs of any inspection program requirements of the special permit for the 5-year grant period that are not already being conducted by SNG through their operational procedures. i) In the first annual report, SNG must describe whether the public benefits from energy availability. This should address the benefits of any avoided disruptions as a consequence of pipe replacement and the benefits of maintaining system capacity. 12) Interference Currents Control: SNG must address induced alternating current (AC) from parallel electric transmission lines and other interference issues such as direct current (DC) in the special permit inspection areas that may affect the pipeline. An induced AC or DC program and remediation plan to protect the pipeline from corrosion caused by stray currents must be in place within one (l) year of the date of this special permit. a) At least once every seven (7) years not exceeding 90 months, SNG must perform an engineering analysis on the effectiveness of the AC and DC mitigation measures and must evaluate any AC interference between 20 and 50 Amps per meter squared. In evaluating such interference, SNG must integrate AC interference data with the most recent ILl results to determine remediation measures. Any AC interference between 20 and 50 Amps per meter squared must be remediated within six (6) months of the finding. If SNG does not remediate AC interference between 20 and 50 Amps per PHMSA-2016-0006- Southern Natural Gas Company Special Permit Page 11 of27 <<>> meter squared, SNG must provide an engineering justification for not remediating such interference to the appropriate PHMSA OPS Region Director, who may accept or reject the justification and require remediation. b) In special permit inspection areas with co-located high voltage alternating current c) d) (HYAC) power lines, SNG must take interference readings (continuous 24 hour recordings) during the calendar quarter of the known or anticipated highest voltage reading. If there are any significant increases to the amount of electricity/current flowing in any co-located high voltage alternating current (HY AC) power li nes, such as from additional generation, a voltage up-rating, additional lines, or new or enlarged substations, SNG must perform an AC mitigation survey along the entire co-located pipeline special permit inspection area right of way within six (6) months of any such change. Within six (6) months of the engineering analysis, SNG must remediate any AC interference greater than 50 Amps per meter squared. Remediation means the implementation of performance measures including, but not limited to, additional grounding along the pipeline to reduce interference currents. Any DC interference that results in CP levels that do not meet the requirements of 49 CFR Part 192, Subpart I, must be remediated within six (6) months of this evaluation. If environmental permitting or right-of-way factors " beyond SNG control" prevent the completion of remediation within six ( 6) months of the interference evaluation. 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 appropriate PHMSA OPS Region Director no later than one ( 1) month prior to the end of the six (6) months completion date. Any extended evaluation and remediation schedules submitted to PHMSA from SNG must recei ve a "no objection" from the appropriate PHMSA OPS Region Director. 13) Anomaly Evaluation and Repair: a) General: SNG must account for ILl tool tolerance and corrosion growth rates in scheduled response times and repairs and document and justify the values used. SNG must demonstrate ILl Tool tolerance accuracy for each ILl Tool run by usage of PHMSA-2016-0006- Southern Natural Gas Company Special Permit Page 12 of 27 <<>> b) calibration excavations and unity plots that demonstrate ILl Tool accuracy to meet the tool accuracy specification provided by the vendor (typical 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 120 days of an ILl Tool run for each type ILl Tool (HR-geometry, HR-defonnation, or HR-MFL). i) ILl tool evaluations for metal loss must use "6t x 6t" interaction cri teria (or more conservative criteria) for detennining anomaly failure pressures and remediation response timing with " 61" being pipe wall thickness times six. Dents: SNG must repair dents in the special permit segment and special permit inspection area in accordance with 49 CFR § 192.933 if it is located in a HCA and in accordance with 49 CFR §§ 192.933(a)-(c) repair criteria and "Table 1 - Special Requirements for Scheduling Remediation" if it is not located in an HCA. Table 1 -Special Requirements for Scheduling Remediation Required Response Required Response Defect Type Orientation Special Permit Special Permit Segment Inspection Area Top or Bottom Immediate Immediate Dent Associated with Cracks or Stress Risers Dent Associated with Top or Bottom l Year Scheduled 2 Year Scheduled Metal Loss Plain Dent > 6 % OD Deep or that exhibits Top 1 Year Scheduled 2 Year Scheduled total strain > 5 % Plain Dent > 2% OD Deep Associated with Top or Bottom l Year Scheduled 2 Year Scheduled Girth or Seam Weld Plain Dent > 6 % OD Deep and that exhibits Top or Bottom Monitored Monitored total strain ~ 5 % Plain D ent ~ 2% OD Deep Associated with Top or Bottom Monitored Monitored Girth or Seam Weld PHMSA-2016-0006- Southern Natural Gas Company Special Permit Page 13 of 27 <<>> Definitions I. Plain Dent - Dent without metal loss, crack or stress riser. 2. Immediate Response - Reduce pressure to 80% of recent maximum pressure. Immediate dents require an immediate pressure reduction and I or restriction and examination and remediation as required in conformance with SNG requirements within fi ve (5) calendar days from the date of discovery. If the remediation cannot be met according to the response schedule, a technical justification must be prepared that explains the reasons why the schedule cannot be met and indicate how the changed schedule will not jeopardize public safety. Any extended response schedules must be submitted to PHMSA from SNG within 14 days of pressure reduction after discovery and must receive a "no objection" from the appropriate PHMSA OPS Region Director. 3. Scheduled Response - Schedule excavation within an appropriate time frame based on the opinion of the SME (not to exceed 365 days for special permit segments and 730 days for special permit inspection areas). 4. Monitored - Catalog data for future monitoring. 5. Top - located between 8 o'clock and 4 o'clock positions (upper 2/3 of the pipe). 6. Bottom - located between 4 o'clock and 8 o'clock positions (bottom 1/3 of pipe). Special permit segments and special permit inspection areas must have a HR- geometry or HR-deformation tool inspection as part of the initial ILI or these ILI inspections must be completed within two (2) years after issuance of this special permit. All dent repairs must be made in accordance with 49 CFR §§ 192.933(a) through (c) repair criteria and "Table 1 - Special Requirements for Scheduling Remediation" on page 13 of 24. SNG must conduct the following fatigue analysis of dents in special permit segments and special permit inspection areas: i) SNG must conduct a fatigue analysis of all in-service, non-remediated dents above 6% and with total strain $ 5% after each high resolution MFL and high resolution caliper or deformation ILl evaluations. Dent fati gue analysis must include as a minimum the following: gross geometry of dent; orientation of dent; soil cover and type; pressure and temperature; including cycles; and stress and strains caused by terrain. The fatigue analysis must be completed within the time frames in "Table 1 -Special Requirements for Scheduling Remediation" of this special permit. ii) The overall remaining fatigue life of all in-service, non-remediated dents over 6% and with total strain $ 5% must be either twice the designated PHMSA-2016-0006- Southern Natural Gas Company Special Permit Page 14 of27 <<>> remaining life of the pipeline or at least 500 years. c) Investigation and Repair Criteria: In-line inspection anomalies in the special permit inspection areas with a safe pressure less than MAOP (e.g. Failure Pressure Ratio (FPR) < 1.39) or an anomaly depth greater than 80% of pipe wall thickness require an immediate pressure reduction and/or restriction and continuous action until the anomaly is examined, evaluated, and remediated. d) Response Time for ILl Results: SNG will follow Kinder Morgan O&M Procedure 916 (In-Line Inspections)20 for excavating, investigating, and remediating anomalies21 based on ILl data results in accordance with 49 CFR §§ 192.485 and 192.933. SNG must evaluate ILl data by using either the ASME Standard B31 G, "Manual for Determining the Remaining Strength of Corroded Pipelines " (ASME 831 G), the modified 831 G (0.85dL), or R-STRENG for calculating the predicted FPR to determine anomaly responses .. • Special permit segments and special permit inspection areas: - Immediate response: Any anomaly within a special permit segment and special permit inspection areas operating up to 72% SMYS that meets either: (I) an FPR equal to or less than 1.1 ; or (2) an anomaly depth equal to or greater than 80% wall thickness loss. - One-year response: Any anomaly within a special permit segment and special permit inspection areas with original Class I location pipe in a Class 3 location (cluster area) operating up to 72% SMYS that meets either: (1) an FPR less than 1.39; or (2) an anomaly depth greater than 40% wall thickness loss. - Monitored response: Any anomaly within a special permit segment and special permit inspection areas with original Class 1 location pipe in a Class 3 location (cluster area) operating up to 72% SMYS that meets both: (1) an FPR equal to or greater than 1.39; or (2) an anomaly depth less than or equal to 40% wall thickness loss. e) Special permit segments and special permit inspection areas: Upon issuance of this 20 The requirements of this Special Permit and 49 CFR §§ 192.485 and 192.933 supersedes Kinder Morgan O&M Procedure 916 (In-Line Inspections). 21 The timing intervals for dent remediation in non-HCAs are in Condition 6(b). PHMSA-2016-0006- Southern Natural Gas Company Special Permit Page 15 of27 <<>> special permit, SNG must implement the repair and remediation of any pipe anomalies or dents that are not in compliance with Condition 13 based upon existing ILl assessment results from the high resolution MFL and geometry/deformation tools used to previously assess pipelines in the special permit segments and special permit inspection areas. SNG must review existing ILl assessment results within 18 months from the issuance of this special permit according to the following schedule: 30% of pipelines in the special permit segments and special permit inspection areas must be reviewed within six (6) months of the issuance of this Special Permit, 65% of pipelines in the special permit segments and special permit inspection areas must be reviewed within 12 months of the issuance this special permit, and I 00% of pipelines in the special permit segments and special permit inspection areas must be reviewed within 18 months of the issuance of this Special permit. Anomalies and dents discovered during this review must be remediated in accordance with Condition 13 timing requirements. 14) Pipe Seam Evaluations: a) SNG must identify any pipe in the special permit segment that may be susceptible to pipe seam issues because of the vintage of the pipe, the manufacturing process of the pipe, or other issues. Once SNG has identified such issues, SNG must complete Condition 14(a). If the engineering analysis required in Condition 14(a) reveals that there is a threat to the pipeline, then SNG must complete all of the applicable condition requirements in Condition 14(a)(ii), (a)(iii), (a)(iv), (a)(v), (a)(vi), (a)(vii), and (a)(viii): i) SNG must perform an engineering analysis to determine if there are any pipe seam threats on pipelines located in the special permit segment. 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, under PHMSA Contract DTFAA-COSP02120 and Figure 4.2, ' Framework for Evaluation with Path for the Segment Analyzed Highlighted· from TT0- 5 "Low Frequency ERW and Lap Welded Longitudinal Seam Evaluation" by PHMSA-2016-0006 - Southern Natural Gas Company Special Permit Page 16 of 27 <<>> Michael Baker Jr., and Kiefner and Associates, et. at. 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 pipelines located in the special permit segment are not a threat to the integrity of the pipeline, SNG does not have to complete Conditions l4(a) (ii) through (vii), but must complete Conditions 14(a)(viii) and (ix). ii) If a 49 CFR Part 192, Subpart J hydrostatic test has not been performed, the special permit segments must be hydrostatically tested to a minimum pressure of 100 percent SMYS, in accordance with 49 CFR Part 192, Subpart J requirements for eight (8) continuous hours, within two and one- half (21 /2) years of issuance of this special permit. 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 22 experienced to verify that it is not indicative of a systemic issue. The results of this root cause analysis must be reported to the appropriate PHMSA Region Director with a copy to the Director, PHMSA Engineering and Research Division, within 60 days of the failure. iii) Special permit segments with low frequency electric resistance welded (LF- ERW) pipe with a history of leaks or failures without a "spike test" within the special permit inspection area must be pressure tested23 with a "spike test" within two and one-half (2 Y2) years of the issuance of this special permit. iv) Special permit segments24 with pressure tests less than 1.25 times MAOP that may be susceptible to pipe seam issues must be tested with a Subpart J pressure test within two and one-half (2 Y2) years of issuance of this special 22 A root cause analysis, including metallurg ical examination of the pipe, must be performed for any leaks that are removed from the special permit segment. 23 A root cause analysis, including metallurgical examination of the pipe, must be performed for any pressure test fai lures or leaks from the special permit segment. 24 SNG must implement the replacement of all Type A special permit segments as defined on page 2 of this special permit as noted: " Type A special permit segments with pipe with integrity issues as determined by Conditions 6 and 14 or that have not been pressure tested in accordance with 49 CFR Part 192, Subpart J to 1.25 times MAOP of this special permit must be replaced within two and one-half (2 Y:z) years of the grant of this special permit or within two (2) years of assessment finding." PHMSA-2016-0006- Southern Natural Gas Company Special Permit Page 17 of27 <<>> permit or the pipe must be replaced with pipe that meets§ 192.619 within two and one-half (2 \12) years of issuance of this special permit. If the pipe is then commensurate with the Class location in accordance with § 192.6 1l(a)(3)(i i) the segment is no longer part of this Special Permit. v) If the pipeline in the special permit inspection area has experienced a seam leak or failure in the last f - **truncated:** true - **body characters:** 91762