# Gulf South Pipeline Co LP — Pipeline Special Permit - **operation:** document - **citation:** PHMSA-2006-26533 - **title:** Gulf South Pipeline Co LP — Pipeline Special Permit - **source type:** permit - **agency:** Pipeline and Hazardous Materials Safety Administration - **status:** current - **official:** true - **published on:** 2007-08-24 - **effective on:** 2007-08-24 - **summary:** PHMSA-2006-26533, issued 2007-08-24 for Gulf South Pipeline Co LP's gas transmission system. - **machine formats:** - **json:** https://regulus.evalyn.ai/document/phmsa-special-permit-phmsa-2006-26533.json - **markdown:** https://regulus.evalyn.ai/document/phmsa-special-permit-phmsa-2006-26533.md - **app url:** https://regulus.evalyn.ai/document/phmsa-special-permit-phmsa-2006-26533 - **source url:** https://www.regulations.gov/docket/PHMSA-2006-26533 **body:** PHMSA pipeline special permit PHMSA-2006-26533. Operator: Gulf South Pipeline Co LP. System: Gas Transmission. Issue date: 2007-08-24. <<>> U.S. Department of Transportation Administrator Washington, DC 20590 1200 New Jersey Ave. SE Pipeline and Hazardous Materials Safety Administration CERTIFIED MAIL - RETURN RECEIPT REQUESTED AUG 2 4 2007 Mr. Walt Bennett Vice President - Operations Gulf South Pipeline Company, LP 20 East Greenway Plaza, Suite 900 Houston, Texas 77046 Docket No. PHMSA-2006-26533 Dear Mr. Bennett: On November 16, 2006 you wrote to the Pipeline and Hazardous Materials Safety Administration (PHMSA) requesting a waiver of compliance from PHMSA's pipeline safety regulations in 49 CFR 192.111, 192.201 and 192.619 for the Gulf South Pipeline Company (GSP) East Texas to Mississippi Expansion Project. The regulations establish the design factor for steel pipe and the required capacity of pressure relieving and limiting stations. PHMSA determined that a waiver of 192.619 is unnecessary. The PHMSA is granting this waiver through a special permit, which is enclosed with this letter. This special permit allows GSP to design, construct and operate the pipeline with design factors of 0.80 in Class 1 locations, 0.67 in Class 2 locations and 0.56 in Class 3 locations in accordance with the conditions specified in the special permit. The special permit provides some relief from the Federal pipeline safety regulations for GSP while ensuring that pipeline safety is not compromised. My staff would be pleased to discuss this special permit or any other regulatory matter with you. Florence Hamn, Director of Regulations (202-366-4595), would be pleased to assist you. Sincerely, Buriese Jeffrey D. Wiese Acting Associate Administrator for Pipeline Safety Enclosure (Special Permit) <<>> Administrator 400 Seventh Street, S.W. Washington, D.C. 20590 Pipeline and Hazardous Materials Safety Administration DEPARTMENT OF TRANSPORTATION PIPELINE AND HAZARDOUS MATERIALS SAFETY ADMINISTRATION (PHMSA) SPECIAL PERMIT Docket Number: PHMSA-2006-26533 Pipeline Operator: Gulf South Pipeline Company, LP Date Requested: November 16, 2006 Code Section(s): 49 CFR 192.111 and 192.201 Grant of Special Permit: The Pipeline and Hazardous Materials Safety Administration (PHMSA) grants this special permit to Gulf South Pipeline Company, LP (GSP). The Federal pipeline safety regulations in 49 CFR 192.111 limit the design factors and operating stress levels for natural gas transmission steel pipelines to 72 percent of the specified minimum yield strength (SMYS) in class 1 locations, 60 percent SMYS in class 2 locations and 50 SMYS percent in class 3 locations. This special permit allows GSP to design, construct and operate the East Texas to Mississippi Expansion Project pipeline using design factors and operating stress levels of up to 80 percent SMYS in class 1 locations, 67 percent SMYS in class 2 locations and 56 percent SMYS in class 3 locations. This special permit also allows GSP to operate up to 67 percent SMYS at class 1 location road crossings and up to 56 percent SMYS at class 2 location road crossings. This special permit covers approximately 255.4 miles of 42-inch pipe and 3 miles of 36-inch pipe in class 1 locations, 3.5 miles of 42-inch pipe in class 2 locations and 468 feet of 42-inch pipe in class 3 locations. The 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 # PHMSA-2007- 26533 in the DOT's Docket Management System (DMS) located on the internet at http://dms.dot.gov. <<>> 2 Because the proposed operating stress level of 80 percent SMYS is higher than the upper limit of the required overpressure protection under existing regulations [1.e., ten percent over maximum allowable operating pressure (MAOP) or 75 percent SMYS], this special permit also allows GSP to establish the overpressure protection limit up to 104 percent of the pipeline MAOP in Class 1 locations, which corresponds to 83.2 percent SMYS. The pipeline overpressure criteria in Class 2 and 3 locations must conform to existing regulations. The pipeline MAOP will be 1,333 psig. For the purpose of this special permit, the "special permit area" means the area consisting of the entire pipeline right-of-way for those segments of the pipeline that will operate above 72 percent of SMYS in Class 1 locations, 60 percent SMYS in Class 2 locations and 50 percent SMYS in Class 3 locations. This special permit is subject to the conditions set forth below. Conditions: The grant of this special permit is subject to the following conditions: 1) Steel Properties: The skelp/plate must be micro alloyed, fine grain, fully killed steel with calcium treatment and continuous casting. 2) Manufacturing Standards: The pipe must be manufactured according to American Petroleum Institute Specification 5L, Specification for Line Pipe (API SL), product specification level 2 (PSL 2), supplementary requirements (SR) for maximum operating pressures and minimum operating temperatures. Pipe carbon equivalents must be at or below 0.23 percent based on the material chemistry parameter (Pcm) formula. Fracture Control: API 5L, the American Society of Mechanical Engineers B31.8 Standard (ASME B31.8) and other specifications and standards address the steel pipe toughness properties needed to resist crack initiation, crack propagation and to ensure crack arrest during a pipeline failure caused by a fracture. GSP must institute an overall fracture control plan addressing steel pipe properties necessary to resist crack initiation and crack propagation and to arrest a fracture within eight pipe joints with a 99 percent occurrence probability or within five pipe joints with a 90 percent occurrence probability. The plan must include acceptable Charpy Impact and Drop Weight Tear Test values, which are measures of a steel pipeline's toughness and resistance to fracture. The fracture control plan, which must be submitted to PHMSA headquarters, must be in accordance with API 5L, Appendix F and must include the following tests: <<>> a) SR SA - Fracture Toughness Testing for Shear Area: Test results must indicate at least 85 percent minimum average shear area for all X- 70 heats and 80 percent minimum shear area for all X- 80 heats with a minimum result of 80 percent shear area for any single test. The test results must also ensure a ductile fracture and arrest; b) SR 5B - Fracture Toughness Testing for Absorbed Energy; and c) SR 6 - Fracture Toughness Testing by Drop Weight Tear Test: Test results must be at least 80 percent of the average shear area for all heats with a minimum result of 60 percent of the shear area for any single test. The test results must also ensure a ductile fracture and arrest. The above fracture initiation, propagation and arrest plan must account for the entire range of pipeline operating temperatures, pressures and gas compositions planned for the pipeline diameter, grade and operating stress levels, including maximum pressures and minimum temperatures for shut-in conditions associated with the special permit area. Where the use of stress factors, pipe grade, operating temperatures and gas composition make fracture toughness calculations non-conservative, correction factors must be used. If the fracture control plan for the pipe in the special permit area does not meet these specifications, GSP must submit to PHMSA headquarters an alternative plan providing an acceptable method to resist crack initiation, crack propagation and to arrest ductile fractures in the special permit area. 4) Steel Plate Quality Control: The steel mill and/or pipe rolling mill must incorporate a comprehensive plate/coil mill and pipe mill inspection program to check for defects and inclusions that could affect the pipe quality. This program must include a plate or rolled pipe (body and all ends) ultrasonic testing (UT) inspection program per ASTM A578 to check for imperfections such as laminations. An inspection protocol for centerline segregation evaluation using a test method referred to as slab macro-etching must be employed to check for inclusions that may form as the steel plate cools after it has been cast. A minimum of one macro-etch or a suitable alternative test must be performed from the first or second heat (manufacturing run) of each sequence (approximately 4 heats) and graded on the Mannesmann scale or equivalent. Test results with a Mannesmann scale rating of one or two out of a possible four or five scale are acceptable. <<>> 4 Pipe Seam Quality Control: A quality assurance program must be instituted for pipe weld seams. The pipe weld seam tests must meet the minimum requirements for tensile strength in API 5L for the appropriate pipe grade properties. A pipe weld seam hardness test using the Vickers hardness testing of a cross-section from the weld seam must be performed on one length of pipe from each heat. The maximum weld seam and heat affected zone hardness must be a maximum of 280 Vickers hardness (Hv10). The hardness tests must include a minimum of three readings for each heat affected zone, three readings in the weld metal and two readings in each section of pipe base metal for a total of 13 readings. The pipe weld seam must be 100 percent UT inspected after expansion and hydrostatic testing per APL 5L. Puncture Resistance: Steel pipe must be puncture resistant to an excavator weighing up to 65 tons. Puncture resistance will be calculated based on industry established calculations such as the Pipeline Research Council International's "Reliability Based Prevention of Mechanical Damage to Pipelines" calculation method. 7) Mill Hydrostatic Test: The pipe must be subjected to a mill hydrostatic test pressure of 94 percent SMYS or greater for ten seconds. 8) Pipe Coating: The application of a corrosion resistant coating to the steel pipe must be subject to a coating application quality control program. The program must address pipe surface cleanliness standards, blast cleaning, application temperature control, adhesion, cathodic disbondment, moisture permeation, bending, minimum coating thickness, coating imperfections and coating repair. Field Coating: A field girth weld joint coating application specification and quality standards to ensure pipe surface cleanliness, application temperature control, adhesion quality, cathodic disbondment, moisture permeation, bending, minimum coating thickness, holiday detection and repair quality must be implemented in field conditions. Field joint coatings must be non-shielding to cathodic protection (CP). Field coating applicators must use valid coating procedures and be trained to use these procedures. 10) Coatings for Trenchless Installation: Coatings used for directional bore, slick bore and other trenchless installation methods must resist abrasions and other damages that may occur due to rocks and other obstructions encountered in this installation technique. <<>> 5 11) Bends Quality: Certification records of factory induction bends and/or factory weld bends must be obtained and retained. All bends, flanges and fittings must have carbon equivalents (CE) below 0.42 or a pre-heat procedure must be applied prior to welding for CE above 0.42. 12) Fittings: All pressure rated fittings and components (including flanges, valves, gaskets, pressure vessels and compressors) must be rated for a pressure rating commensurate with the MAOP and class location of the pipeline. Designed fittings (including tees, elbows and caps) must have the same design factors as the adjacent pipe class location. 13) Design Factor - Pipelines: Pipe installed under this special permit in Class 1, 2 and 3 locations may use design factors of 0.80, 0.67 and 0.56 respectively. Road crossings in Class 1 and 2 areas may use design factors of 0.67 and 0.56 respectively. 14) Design Factor - Stations: The following compressor and measurement and regulation stations may use a design factor of 0.54: The affected stations are Carthage Junction Compressor Station, Vixen Compressor Station, Energy Transfer Corporation Measurement and Regulation Station. Design of future stations associated with this pipeline must follow 49 CFR § 192.111. 15) Temperature Control: The compressor station discharge temperature must be limited to 120° Fahrenheit. A temperature above this maximum temperature of 120° Fahrenheit may be approved, if GSP technical coating operating tests show that the pipe coating will properly with-stand the higher operating temperature for long term operations. 16) Overpressure Protection Control: Mainline pipeline overpressure protection must be limited to a maximum of 104 percent MAOP. 17) Welding Procedures: The appropriate PHMSA regional office must be notified within 14 days of the beginning of welding procedure qualification activities. Automated or manual welding procedure documentation must be submitted to the same PHMSA regional office. 18) Depth of Cover: The soil cover must be a minimum depth of 36 inches in all areas. In areas where threats from chisel plowing or other activities are threats to the pipeline, the top of the pipeline must be installed at least one foot below the deepest penetration above <<>> 6 the pipeline. If routine patrols or other observed conditions indicate the possible loss of cover over the pipeline, GSP will perform a depth of cover study and replace cover as necessary to meet the minimum depth of cover requirements specified herein. 19) Construction Quality: A construction quality assurance plan to ensure quality standards and controls must be maintained throughout the construction phase with respect to: inspection, pipe hauling and stringing, field bending, welding, non-destructive examination (NDE) of girth welds, field joint coating, pipeline coating integrity tests, lowering of the pipeline in the ditch, padding materials to protect the pipeline, backfilling, alternating current (AC) interference mitigation and CP systems. All girth welds must be non-destructively examined (NDE) by radiography or alternative means. The NDE examiner must have all required and current certifications. 20) Interference Currents Control: Control of induced AC from parallel electric transmission lines and other interference issues that may affect the pipeline must be incorporated into the design of the pipeline and addressed during the construction phase. Issues identified and not originally addressed in the design phase must be brought to PHMSA's attention. An induced AC program to protect the pipeline from corrosion caused by stray currents must be in place within six months after placing the pipeline in service. 21) Test Level: The pre-in service hydrostatic test must be to a pressure producing a hoop stress of: 100 percent SMYS and 1.25 X MAOP in areas to operate to 80 percent SMYS; at least 1.5 X MAOP in areas to operate to 67% SMYS; and at least 1.5 X MAOP in areas to operate to 56% SMYS. 22) Assessment of Test Failures: Any pipe failure occurring during the pre-in service hydrostatic test must undergo a root cause failure analysis to include a metallurgical examination of the failed pipe. The results of this examination must preclude a systemic pipeline material issue and the results must be reported to PHMSA headquarters and the appropriate PHMSA regional office. 23) Supervisory Control and Data Acquisition (SCADA) System Capabilities: A SCADA system to provide remote monitoring and control of the entire pipeline system must be employed <<>> 7 24) SCADA Procedures: A detailed procedure for establishing and maintaining accurate SCADA set points must be established to ensure the pipeline operates within acceptable design limits at all times. 25) Mainline Valve Control: Mainline valves located on either side of a pipeline segment containing a High Consequence Area (HCA) where personnel response time to the valve exceeds one hour must be remotely controlled by the SCADA system. The SCADA system must be capable of opening and closing the valve and monitoring the valve position, upstream pressure and downstream pressure. As an alternative, a leak detection system for mainline valve control is acceptable. 26) Pipeline Inspection: The pipeline must be capable of passing ILI tools. All headers and other segments covered under this special permit that do not allow the passage of an ILI device must have a corrosion mitigation plan. 27) Gas Quality Monitoring: An acceptable gas quality monitoring and mitigation program must be instituted to not exceed the following limits: a) H¿S (1 grain per 100 standard cubic feet or 16 parts per million (ppm), maximum); b) CO2 (3 percent maximum); c) H2O (less than or equal to 7 pounds per million standard cubic feet and no free water); and d) Other deleterious constituents that may impact the integrity of the pipeline must be instituted. e) The pipeline must have an ongoing pigging and liquids sampling plan to identify, mitigate and remove deleterious constituents. f) When H¿S is above eight parts ppm, the gas stream constituents must be reviewed for implementation of a quarterly pigging/inhibitor injection program including follow up sampling of liquids at receipt points. 29) Gas Quality Control: Filters/separators must be installed at locations where gas is received into the pipeline where the incoming gas stream quality includes potentially deleterious constituents to minimize the entry of contaminants and to protect the integrity of downstream pipeline segments. 30) Gas Quality Monitoring Equipment: Equipment, including moisture analyzer, chromatograph and semi-annual H¿S sampling (quarterly sampling where H¿S is above <<>> 8 eight ppm), must be installed to permit the operator to manage and limit the introduction of contaminants and free liquids into the pipeline. 31) Cathodic Protection: The initial CP system must be operational within 12 months of placing any pipeline segment in service. 32) Interference Current Surveys: Interference surveys must be performed within six months of placing the pipeline in service to ensure compliance with applicable NACE International Standard Recommended Practices 0169 and 0177 (NACE RP 0169 and NACE RP 0177) for interference current levels. If interference currents are found, GSP will determine if there have been any adverse affects to the pipeline and mitigate the affects as necessary. GSP will report to PHMSA the results of any negative finding and the associated mitigative efforts to the appropriate PHMSA regional office. 33) Corrosion Surveys: Corrosion surveys of the affected pipeline must be completed within six months of placing the respective CP system (s) in operation to ensure adequate external corrosion protection per NACE RP 0169. The survey will also address the proper number and location of CP test stations as well as AC interference mitigation and AC grounding programs per NACE RP 0177. 34) Verification of Cathodic Protection: An interrupted close interval survey (CIS) must be performed in concert and integrated with ILI in accordance with 49 CFR 192 Subpart O reassessment intervals for all HCA pipeline mileage. At least one CP test station must be located within each HCA with a maximum spacing between test stations of one-half mile within an HCA. If any annual test station reading fails to meet 49 CFR 192 Subpart I requirements, remedial actions must occur within six months. Remedial actions must include a close interval survey (CIS) on each side of the affected test station and all modifications to the CP system necessary to ensure adequate external corrosion control. 35) Initial Close Interval Survey (CIS) - Initial: A CIS must be performed on the pipeline within two years of the pipeline in- service date. The CIS results must be integrated with the baseline ILI to determine whether further action is needed. 36) Pipeline Markers: GSP must employ line-of-sight markings on the pipeline in the special permit area except in agricultural areas or large water crossings such as lakes where line of sight markers are not practical. The marking of pipelines is also subject to Federal Energy Regulatory Commission orders or environmental permits and local restrictions. <<>> 9 37) Pipeline Patrolling: Pipeline patrolling must be conducted at least monthly (12 times per calendar year), not to exceed 45 days, to inspect for excavation activities, ground movement, wash-outs, leakage or other activities and conditions affecting the safe operation of the pipeline. 38) Monitoring of Ground Movement: An effective monitoring/mitigation plan must be in place to monitor for and mitigate issues of unstable soil and ground movement. 39) Initial ILI: GSP must perform a baseline ILI in association with the construction of the pipeline using a high-resolution Magnetic Flux Leakage (MFL) tool to be completed within three years of placing a pipeline segment in service. GSP must perform a baseline geometry tool run after completion of the hydrostatic strength test and backfill of the pipeline, (just prior to placing the pipeline in service) but no later than six months after placing the pipeline in service under a special permit. 40) Future ILI: A second high-resolution MFL inspection must be performed and completed on the pipe subject to this waiver within the first reassessment interval required by 49 CFR Subpart O, regardless of HCA classification. Future ILI must be performed on a frequency consistent with Subpart O for the entire pipeline covered by this waiver. 41) Direct Assessment Plan: Headers, mainline valve bypasses and other sections covered by this special permit that cannot accommodate ILI tools must be part of a Direct Assessment (DA) plan or other acceptable integrity monitoring method using External and Internal Corrosion Direct Assessment criteria (ECDA/ICDA). 42) Damage Prevention Program: The Common Ground Alliance (CGA) Alliance's damage prevention best practices applicable to pipelines must be incorporated into the GSP damage prevention program. 43) Anomaly Evaluation and Repair: Anomaly evaluations and repairs in the special permit area must be performed based upon the following: a) Anomaly Response Time: Repair Immediately - Any anomaly within a waiver area operating up to 80% SMYS with a failure pressure ratio (FPR) equal to or less than 1.1 - Any anomaly within a waiver area operating up to 67% SMYS with a FPR equal to or less than 1.25 <<>> 10 - Any anomaly within a waiver area operating up to 56% SMYS with a FPR equal to or less than 1.4 b) Anomaly Response Time: Repair Within One Year - Any anomaly within a waiver area operating at up to 80% SMYS with a FPR equal to or less than 1.25 - Any anomaly within a waiver area operating at up to 67% SMYS with a FPR equal to or less than 1.5 - Any anomaly within a waiver area operating at up to 56% SMYS with a FPR equal to or less than 1.8 c) Anomaly Response Time: Monitored Conditions - Anomalies not requiring immediate or one year repairs must be reassessed according to CFR 49, Part 192, Subpart O and the American Society of Mechanical Engineers (ASME) standard B31.8S requirements and class location factor. - Each anomaly not repaired under the immediate repair requirements must have a corrosion growth rate and ILI tool tolerance assigned per the Gas Integrity Management Program (IMP) to determine the maximum re-inspection interval. d) Anomaly Assessment Methods - GSP must confirm the remaining strength (R-STRENG) effective area method, R- STRENG - 0.85dL, and ASME B31G assessment methods are valid for the pipe diameter, wall thickness, grade, operating pressure, operating stress level and operating temperature. GSP must also use the most conservative method until confirmation of the proper method is made to PHMSA headquarters. - Dents in the pipe in the waiver area must be evaluated and repaired per 49 CFR § 192.309(b) for initial ILI and per 49 CFR 192.933(d) for future ILI. 44) Potential Impact Radius Calculation Updates: If the pipeline operating pressures and gas quality are determined to be outside the parameters of the C-FER Study, a revised study with the updated parameters must be incorporated into the IMP. 45) Reporting - Immediate: GSP must notify the appropriate PHMSA regional office within 24 hours of any non-reportable leaks occurring in the special permit area. <<>> 11 46) Reporting - 180 Day: Within 180 days of the pipeline in- service date under a special permit, GSP shall report on its compliance with special permit conditions to PHMSA headquarters and the appropriate regional office. 47) Annual Reporting: Following approval of the special permit, GSP must annually report the following: a) The results of any in-line inspection (ILI) or direct assessment results performed within the special permit area during the previous year; b) Any new integrity threats identified within the special permit area during the previous year, c) Any encroachment in the special permit area, including the number of new residences or public gathering areas; d) Any class or HCA changes in the special permit area during the previous year; e) Any reportable incidents associated with the special permit area that occurred during the previous year; f) Any leaks on the pipeline in the special permit area that occurred during the previous year; g) A list of all repairs on the pipeline in the special permit area made during the previous year; h) On-going damage prevention initiatives on the pipeline in the special permit area and a discussion of their success or failure; i) Any changes in procedures used to assess and/or monitor the pipeline operating under this special permit; and j) Any company mergers, acquisitions, transfers of assets, or other events affecting the regulatory responsibility of the company operating the pipeline to which this special permit applies. Limitations: The PHMSA has the sole authority to make all determinations on whether GSP has complied with the specified conditions. Should GSP fail to comply with any conditions of this special permit, or should PHMSA determine this special permit is no longer appropriate or that this <<>> 12 special permit is inconsistent with pipeline safety, PHMSA may revoke this special permit and require GSP to comply with the regulatory requirements in 49 CFR §§ 192.111 and 192.201. AUTHORITY: 49 U.S.C. 60118(c) and 49 CFR § 1.53. AUG 2 4 2007 Issued in Washington, DC on Jeffrey D. Wiese, Associate Administrator for Pipeline Safety - **truncated:** false - **body characters:** 26700