{"operation":"document","citation":"0900006480e4a518","title":"U.S. DOT/PHMSA - Decision","source_type":"rulemaking","agency":"Pipeline and Hazardous Materials Safety Administration","status":"current","official":true,"published_on":null,"effective_on":null,"summary":"This document is PHMSA's special permit (Docket PHMSA-2007-27842) for the Midcontinent Express Pipeline (MEP). It: (1) grants a waiver from 49 CFR §§ 192.111 and 192.201 for the specified ~500-mile pipeline allowing Class 1 operation using a design factor up to 0.80 and stress levels up to 80% SMYS resulting in MAOPs stated for pipeline segments; (2) allows pressure relief/limiting devices sized so pressure in Class 1 segments will not exceed 104% MAOP (or hoop stress of 83.2% SMYS) in an overpressure event; (3) defines the “special permit area” and ties the grant to the analysis in the Special Permit Analysis and Findings; and (4) lists detailed conditions and limitations (material, manufacturing, testing, inspection, monitoring, reporting, and PHMSA's authority to revoke). The permit includes numerous technical and operational requirements and explicit limitations on PHMSA authority. (","machine_formats":{"json":"https://regulus.evalyn.ai/document/regulations-gov-attachment-0900006480e4a518.json","markdown":"https://regulus.evalyn.ai/document/regulations-gov-attachment-0900006480e4a518.md"},"app_url":"https://regulus.evalyn.ai/document/regulations-gov-attachment-0900006480e4a518","source_url":"https://downloads.regulations.gov/PHMSA-2007-27842-0005/attachment_1.pdf","body":"<<<PAGE 1>>>\n\n1\nU.S. DEPARTMENT OF TRANSPORTATION\nPIPELINE AND HAZARDOUS MATERIALS SAFETY ADMINISTRATION (PHMSA)\nSPECIAL PERMIT\nDocket Number:\nPHMSA-2007-27842\nRequested By:\nMidcontinent Express Pipeline, LLC\nDate Requested:\nApril 4, 2007\nCode Sections:\n49 CFR $§ 192.111 and 201\nGrant of Special Permit:\nThe Pipeline and Hazardous Materials Safety Administration (PHMSA) grants this special\npermit to the Midcontinent Express Pipeline, LLC (MEP), subject to the conditions and\nlimitations set forth below, waiving compliance from 49 CFR $§ 192.111 and 192.201 for a\nproposed 500-mile interstate natural gas transmission pipeline to be operated by MEP, a jointly\nowned subsidiary of Kinder Morgan Energy Partners, L.P. and Energy Transfer Partners L.P.\nThe new pipeline will consist of approximately 40 miles of 30-inch diameter and 257 miles of\n42-inch diameter pipeline in \"Zone 1\" and approximately 197 miles of 36-inch diameter pipeline\nin \"Zone 2.\" The pipeline will originate in Bryan County, Oklahoma and run southeasterly\nthrough Texas, Louisiana and Mississippi to existing facilities in Choctaw County, Alabama.\nThis special permit allows MEP to design, construct and operate the MEP pipeline in Class 1\nlocations only using a design factor in § 192.111 up to 0.80 and at stress levels up to 80% of the\nspecified minimum yield strength (SMYS). This would result in a maximum allowable operating\npressure (MAOP) of 1,480 pounds per square inch gauge (psig) for the 42-inch and 36-inch\nsegments and 1,440 psig for the 30-inch segment.\nThis special permit also allows MEP to design, install and operate pressure relief and limiting\ndevices on the MEP pipeline with a capacity that would ensure the pressure in Class 1 location\npipeline segments would not exceed 104% of the MAOP or the pressure that produces a hoop\nstress of 83.2% SMYS in the event an overpressure situation develops. The pipeline overpressure\ncriteria in Class 2 and 3 locations must conform to existing regulations.\n\n<<<PAGE 2>>>\n\n2\nFor the purpose of this special permit, the \"special permit area\" means the area consisting of the\nentire pipeline right-of-way for those segments of the pipeline that will operate above\n72% SMYS in Class 1 locations.\nPHMSA grants this special permit based on the findings set forth in the \"Special Permit Analysis\nand Findings\" document, which can be read in its entirety in Docket No. PHMSA-2007-27842\nin the Federal Docket Management System (FDMS) located on the Internet at\nwww.Regulations.gov.\nConditions\nPHMSA grants this special permit subject to the following conditions:\n1)\nSteel Properties: The skelp/plate must be micro alloyed, fine grain, fully killed steel with\ncalcium treatment and continuous casting.\n2) Manufacturing Standards: The pipe must be manufactured according to American\nPetroleum Institute Specification 5L, Specification for Line Pipe (API 5L), product\nspecification level 2 (PSL 2), supplementary requirements (SR) for maximum operating\npressures and minimum operating temperatures. Pipe carbon equivalents must be at or\nbelow 0.23% based on the material chemistry parameter (Pcm) formula.\nFracture Control: API 5L, the American Society of Mechanical Engineers B31.8 Standard\n(ASME B31.8) and other specifications and standards address the steel pipe toughness\nproperties needed to resist crack initiation, crack propagation and to ensure crack arrest\nduring a pipeline failure caused by a fracture. MEP must institute an overall fracture\ncontrol plan addressing steel pipe properties necessary to resist crack initiation and crack\npropagation and to arrest a fracture within 8 pipe joints with a 99% occurrence probability\nor within 5 pipe joints with a 90% occurrence probability. The plan must include\nacceptable Charpy Impact and Drop Weight Tear Test values, which are measures of a steel\npipeline's toughness and resistance to fracture. The fracture control plan, which must be\nsubmitted to PHMSA headquarters, must be in accordance with API 5L, Appendix F and\nmust include the following tests:\na) SR 5A - Fracture Toughness Testing for Shear Area: Test results must indicate at least\n85% minimum average shear area for all X- 70 heats and 80% minimum shear area for\nall X- 80 heats with a minimum result of 80% shear area for any single test. The test\n\n<<<PAGE 3>>>\n\n3\nresults must also ensure a ductile fracture and arrest;\nb) SR SB - Fracture Toughness Testing for Absorbed Energy; and\nc) SR 6 - Fracture Toughness Testing by Drop Weight Tear Test: Test results must be at\nleast 80% of the average shear area for all heats with a minimum result of 60% of the\nshear area for any single test. The test results must also ensure a ductile fracture and\narrest.\nThe above fracture initiation, propagation and arrest plan must account for the entire range\nof pipeline operating temperatures, pressures and gas compositions planned for the pipeline\ndiameter, grade and operating stress levels, including maximum pressures and minimum\ntemperatures for shut-in conditions associated with the special permit area. Where the use\nof stress factors, pipe grade, operating temperatures and gas composition make fracture\ntoughness calculations non-conservative, correction factors must be used. If the fracture\ncontrol plan for the pipe in the special permit area does not meet these specifications, MEP\nmust submit to PHMSA headquarters an alternative plan providing an acceptable method to\nresist crack initiation, crack propagation and to arrest ductile fractures in the special permit\narea.\n4)\nSteel Plate Quality Control: The steel mill and/or pipe rolling mill must incorporate a\ncomprehensive plate/coil mill and pipe mill inspection program to check for defects and\ninclusions that could affect the pipe quality. This program must include a plate or rolled\npipe ultrasonic testing (UT) inspection program to check for imperfections such as\nlaminations. UT inspection must be conducted on all factory beveled pipe ends. In\naddition, pipe body UT inspection must be conducted on a minimum of 100% of pipe joints\nand all ends, with a minimum coverage of 35% of the pipe body for those joints inspected.\nAny laminations identified by the UT inspection program must be evaluated in accordance\nwith the acceptance criteria defined in ASTM International Standard ASTM A578/A578M\n\"Standard Specification for Straight-Beam Ultrasonic Examination of Rolled Steel Plates\nfor Special Applications (ASTM A578), \" Level B or API 5L Paragraph 7.8.10. An\ninspection protocol for centerline segregation evaluation using a test method referred to as\nslab macro-etching must be employed to check for inclusions that may form as the steel\nplate cools after it has been cast. A minimum of one macro-etch or a suitable alternative\ntest must be performed from the first or second heat (manufacturing run) of each sequence\n\n<<<PAGE 4>>>\n\n4\n(approximately 4 heats) and graded on the Mannesmann scale or equivalent. Test results\nwith a Mannesmann scale rating of one or two out of a possible four or five scale are\nacceptable.\n5)\nPipe Seam Quality Control: A quality assurance program must be instituted for pipe weld\nseams. The pipe weld seam tests must meet the minimum requirements for tensile strength\nin API 5L for the appropriate pipe grade properties. A pipe weld seam hardness test using\nthe Vickers hardness testing of a cross-section from the weld seam must be performed on\none length of pipe from each heat. The maximum weld seam and heat affected zone\nhardness must be a maximum of 280 Vickers hardness (Hv10). The hardness tests must\ninclude a minimum of 3 readings for each heat affected zone, 3 readings in the weld metal\nand 2 readings in each section of pipe base metal for a total of 13 readings. The pipe weld\nseam must be 100% UT inspected after expansion and hydrostatic testing per API 5L.\n6) Mill Hydrostatic Test: The pipe must be subjected to a mill hydrostatic test to achieve a\nminimum stress level of 95% SMYS in the pipe for a minimum duration of 10 seconds.\nThe 95% stress level may be achieved using a combination of internal test pressure and the\napplication of end loads imposed by the hydrostatic testing equipment as allowed by API\n5L, Appendix K\n7)\nPipe Coating: The application of a corrosion resistant coating to the steel pipe must be\nsubject to a coating application quality control program. The program must address pipe\nsurface cleanliness standards, blast cleaning, application temperature control, adhesion,\ncathodic disbondment, moisture permeation, bending, minimum coating thickness, coating\nimperfections and coating repair.\n8)\nField Coating: A field girth weld joint coating application specification and quality\nstandards to ensure pipe surface cleanliness, application temperature control, adhesion\nquality, cathodic disbondment, moisture permeation, bending, minimum coating thickness,\nholiday detection and repair quality must be implemented in field conditions. Field joint\ncoatings must be non-shielding to cathodic protection (CP). Field coating applicators must\nuse valid coating procedures and be trained to use these procedures.\n9) Coatings for Trenchless Installation: Coatings used for directional bore, slick bore and\nother trenchless installation methods must resist abrasions and other damages that may\noccur due to rocks and other obstructions encountered in this installation technique.\n\n<<<PAGE 5>>>\n\n10) Bends Quality: Certification records of factory induction bends and/or factory weld bends\nmust be obtained and retained. All bends, flanges and fittings must have carbon\nequivalents (CE) below 0.42 or a pre-heat procedure must be applied prior to welding for\nCE above 0.42.\nI1) Fittings: All pressure rated fittings and components (including flanges, valves, gaskets,\npressure vessels and compressors) must be rated for a pressure rating commensurate with\nthe MAOP and class location of the pipeline. Designed fittings (including tees, elbows and\ncaps) must have the same design factor as the adjacent pipe.\n12) Design Factor - Pipelines: Pipe installed under this special permit in Class 1 location may\nuse a design factor of 0.80.\n13) Temperature Control: The compressor station discharge temperature must be limited to\n120° Fahrenheit. A temperature above this maximum temperature of 120° Fahrenheit may\nbe approved if MEP technical coating operating tests show that the pipe coating will\nproperly withstand the higher operating temperature for long term operations. If the\ntemperature exceeds 120° Fahrenheit MEP must also institute a coating monitoring\nprogram in these areas using ongoing Direct Current Voltage Gradient (DCVG) surveys or\nAlternating Current Voltage Gradient (ACVG) surveys or other testing to demonstrate the\nintegrity of the coating. This program will be approved by and results provided to the\nregional offices of PHMSA where the pipe is in service.\n14) Overpressure Protection Control: Mainline pipeline overpressure protection must be\nlimited to a maximum of 104% MAOP.\n15) Welding Procedures: For automatic or mechanized welding the 20th Edition, of API 1104,\n\"Welding of Pipelines and Related Facilities, \" will be used for welding procedure\nqualification, welder qualification and weld acceptance criteria. Operator must use the\n19th Edition of API 1104 for all other welding processes. The appropriate PHMSA\nregional office must be notified within 14 days of the beginning of welding procedure\nqualification activities. Automated or manual welding procedure documentation must be\nsubmitted to the same PHMSA regional office.\n16) Depth of Cover: The soil cover must be a minimum depth of 36 inches in all areas. In\nareas where threats from chisel plowing or other activities are threats to the pipeline, the\ntop of the pipeline must be installed at least one foot below the deepest penetration above\n\n<<<PAGE 6>>>\n\nthe pipeline. If routine patrols or other observed conditions indicate the possible loss of\ncover over the pipeline, MEP will perform a depth of cover study and replace cover as\nnecessary to meet the minimum depth of cover requirements specified herein.\n17) Construction Quality: A construction quality assurance plan to ensure quality standards\nand controls must be maintained throughout the construction phase with respect to:\ninspection, pipe hauling and stringing, field bending, welding, non-destructive examination\n(NDE) of girth welds, field joint coating, pipeline coating integrity tests, lowering of the\npipeline in the ditch, padding materials to protect the pipeline, backfilling, alternating\ncurrent (AC) interference mitigation and CP systems. All girth welds must be non-\ndestructively examined by radiography or alternative means. The NDE examiner must\nhave all required and current certifications.\n18) Interference Currents Control: Control of induced AC from parallel electric transmission\nlines and other interference issues that may affect the pipeline must be incorporated into the\ndesign of the pipeline and addressed during the construction phase. Issues identified and\nnot originally addressed in the design phase must be brought to PHMSA's attention by\nnotifying the appropriate regional office. An induced AC program to protect the pipeline\nfrom corrosion caused by stray currents must be in place within six months after placing\nthe pipeline in service.\n19) Test Level: The pre-in service hydrostatic test must be to a pressure producing a hoop\nstress of at least 100% SMYS and 1.25 X MAOP in areas to operate to 80% SMYS. Short\nsegments of pipe (up to one mile in length) having a design factor between 72% SMYS and\nless than 80% SMYS may be tested with 80% SMYS pipe provided the test pressure\nproduces a hoop stress of at least 1.25 X MAOP for all pipe tested.\n20) Assessment of Test Failures: Any pipe failure occurring during the pre-in service\nhydrostatic test must undergo a root cause failure analysis to include a metallurgical\nexamination of the failed pipe. The results of this examination must preclude a systemic\npipeline material issue and the results must be reported to PHMSA headquarters and the\nappropriate PHMSA regional office.\n21) Supervisory Control and Data Acquisition (SCADA) System Capabilities: A SCADA\nsystem to provide remote monitoring and control of the pipeline system must be employed.\n22) SCADA Procedures: A detailed procedure for establishing and maintaining accurate\n\n<<<PAGE 7>>>\n\n7\nSCADA set points must be established to ensure the pipeline operates within acceptable\ndesign limits at all times.\n23) Mainline Valve Control: Mainline valves located on either side of a pipeline segment\ncontaining a High Consequence Area (HCA) where personnel response time to the valve\nexceeds one hour must be remotely controlled via the SCADA system. The SCADA\nsystem must be capable of closing these mainline valves and monitoring the valve position,\nas well as upstream pressure and downstream pressure at the mainline valve. As an\nalternative, a leak detection system for mainline valve control is acceptable.\n24) Pipeline Inspection: The pipeline must be capable of passing in-line inspection (ILI) tools.\nAll headers and other segments covered under this special permit that do not allow the\npassage of an ILI device must have a corrosion mitigation plan.\n25) Gas Quality Monitoring: An acceptable gas quality monitoring and mitigation program\nmust be instituted to not exceed the following limits:\na) H¿S (1.0 grain per 100 standard cubic feet or 16 parts per million (ppm), maximum);\nb) CO2 (3% maximum);\nc) H2O (less than or equal to 7 pounds per million standard cubic feet and no free water);\nand\nd) Other deleterious constituents that may impact the integrity of the pipeline.\n26) The pipeline must have an ongoing pigging and liquids sampling plan to identify, mitigate\nand remove deleterious constituents where applicable.\n27) If H¿S is above 8 ppm up to a maximum of 16 ppm, the gas stream constituents must be\nreviewed for implementation of a quarterly pigging/inhibitor injection program, including\nfollow up sampling of liquids at receipt points.\n28) Gas Quality Control: Separators or Filters/separators must be installed at locations where\ngas is received into the pipeline where the incoming gas stream quality includes potentially\ndeleterious free liquids and/or particulates to minimize the entry of contaminants and to\nprotect the integrity of downstream pipeline segments.\n29) Gas Quality Monitoring Equipment: Equipment, including moisture analyzer,\nchromatograph and semi-annual H¿S sampling (quarterly sampling where H¿S is above\n8 ppm), must be installed to permit the operator to manage and limit the introduction of\ncontaminants and free liquids into the pipeline.\n\n<<<PAGE 8>>>\n\n8\n30) Cathodic Protection: The initial CP system must be operational within 12 months of\nplacing any pipeline segment in service.\n31) Interference Current Surveys: Interference surveys must be performed within six months\nof placing the pipeline in service to ensure compliance with applicable NACE International\nStandard Recommended Practices 0169 and 0177 (NACE RP 0169 and NACE RP 0177)\nfor interference current levels. If interference currents are found, MEP will determine if\nthere have been any adverse affects to the pipeline and mitigate the affects as necessary.\nMEP will report the results of any negative finding and the associated mitigative efforts to\nthe appropriate PHMSA regional office.\n32) Corrosion Surveys: Corrosion surveys of the affected pipeline must be completed within\nsix months of placing the respective CP systems) in operation to ensure adequate external\ncorrosion protection per NACE RP 0169. The survey will also address the proper number\nand location of CP test stations as well as AC interference mitigation and AC grounding\nprograms per NACE RP 0177.\n33) Verification of Cathodic Protection: An interrupted close interval survey (CIS) must be\nperformed in concert and integrated with ILl in accordance with 49 CFR Part 192 Subpart\nO reassessment intervals for all HCA pipeline mileage. At least one CP test station must be\nlocated within each HCA with a maximum spacing between test stations of one-half mile\nwithin an HCA. If any annual test station reading fails to meet 49 CFR Part 192, Subpart I\nrequirements, remedial actions must occur within six months. Remedial actions must\ninclude a CIS on each side of the affected test station and all modifications to the CP\nsystem necessary to ensure adequate external corrosion control.\n34) Initial Close Interval Survey (CIS) - Initial: A CIS must be performed on the pipeline\nwithin two years of the pipeline in-service date. The CIS results must be integrated with\nthe baseline ILI to determine whether further action is needed.\n35)\nInitial Coating Assessment - MEP must assess the integrity of the pipeline coating after\ncompletion of padding and backfill during construction through use of coating indirect\nassessment methods such as DCVG or ACV surveys or equivalent methods. MEP must\nremediate any damaged coating found during these assessments that are classified as minor\nand at or above 15% IR for DCVG or at or above 30 dBuV for ACVG, moderate or severe\nbased on NACE International Recommended Practice 0502-2002, Pipeline External\n\n<<<PAGE 9>>>\n\n9\nCorrosion Direct Assessment Methodology, (NACE RP 0502-2002). A minimum of two\ncoating survey assessment classifications must be excavated, classified and/or remediated\nper each survey crew and compressor station discharge pipeline section to verify survey\nresults.\n36) Pipeline Markers: MEP must employ line-of-sight markings on the pipeline in the special\npermit area except in agricultural areas or large water crossings such as lakes where line-\nof-sight markers are not practical. The marking of pipelines is also subject to Federal\nEnergy Regulatory Commission orders or environmental permits and local restrictions.\n37) Pipeline Patrolling: Pipeline patrolling must be conducted at least monthly (12 times per\ncalendar year), not to exceed 45 days, to inspect for excavation activities, ground\nmovement, wash-outs, leakage or other activities and conditions affecting the safe\noperation of the pipeline.\n38) Monitoring of Ground Movement: An effective monitoring/mitigation plan must be in\nplace to monitor for and mitigate issues of unstable soil and ground movement.\n39) Initial ILI: MEP must perform a baseline ILI in association with the construction of the\npipeline using a high-resolution Magnetic Flux Leakage (MFL) tool to be completed within\nthree years of placing a pipeline segment in service. MEP must perform a baseline\ngeometry tool run after completion of the hydrostatic strength test and backfill of the\npipeline, (just prior to placing the pipeline in service) but no later than six months after\nplacing the pipeline in service in accordance with the conditions allowed by the special\npermit.\n40) Future ILI: A second high-resolution MFL inspection must be performed and completed\non the pipe subject to this special permit within the first reassessment interval required by\n49 CFR Pat 192, Subpart O, regardless of HCA classification. Future ILI must be\nperformed on a frequency consistent with Subpart O for the entire pipeline covered by this\nspecial permit.\n41) Direct Assessment Plan: Headers, mainline valve bypasses and other sections in the\nspecial permit area that cannot accommodate IL tools must be part of a Direct Assessment\n(DA) plan or other acceptable integrity monitoring method using External and Internal\nCorrosion Direct Assessment criteria (ECDA/ICDA).\n42) Damage Prevention Program: The Common Ground Alliance's (CGA) damage prevention\n\n<<<PAGE 10>>>\n\n10\nbest practices applicable to pipelines must be incorporated into the MEP damage\nprevention program.\n43) Anomaly Evaluation and Repair: Anomaly evaluations and repairs in the special permit\narea, regardless of HCA status, must be performed based upon the following:\na) Anomaly Response Time: Repair Immediately\n- Any anomaly within a special permit area operating up to 80% SMYS with a\nfailure pressure ratio (FPR) equal to or less than 1.1 and/or an anomaly depth equal\nto or greater than 80% wall thickness.\nb) Anomaly Response Time: Repair Within One Year\n- Any anomaly within a special permit area operating at up to 80% SMYS with a\nFPR equal to or less than 1.25.\nc) Anomaly Response Time: Monitored Conditions\n- Anomalies not requiring immediate or one year repairs per paragraphs a and b\nabove must be reassessed according to 49 CFR Part 192, Subpart O reassessment\nintervals.\n- Each anomaly not repaired under the immediate repair requirements must have a\ncorrosion growth rate and ILI tool tolerance assigned per the Gas Integrity\nManagement Program (IMP) to determine the maximum re-inspection interval.\nd) Anomaly Assessment Methods\n- MEP must confirm the remaining strength (R-STRENG) effective area method,\n0.85dL and ASME B31G assessment methods are valid for the pipe diameter, wall\nthickness, grade, operating pressure, operating stress level and operating\ntemperature. MEP must also use the most conservative method until confirmation\nof the proper method is made to PHMSA Headquarters.\n- Dents in the pipe in the special permit area must be evaluated and repaired per\n49 CFR § 192.309(b) for the baseline geometry tool run and per 49 CFR\n§ 192.933(d) for future ILI.\n44) Potential Impact Radius Calculation Updates: If the pipeline operating pressures and gas\nquality are determined to be outside the parameters of the C-FER Study, a revised study\nwith the updated parameters must be incorporated into the IMP.\n45) Reporting - Immediate: MEP must notify the appropriate PHMSA regional office within\n\n<<<PAGE 11>>>\n\n11\n24 hours of any non-reportable leaks occurring in the special permit area.\n46)\nReporting - 30 Day: At least thirty (30) days prior to the pipeline in- service date under\nthis special permit, MEP must report on its compliance with special permit conditions to\nPHMSA headquarters and the appropriate regional offices.\na) Special Permit Conditions 1 through 25, 28, 29, 35, 36, 44 and 46 must be completed\nand implemented with documentation available for PHMSA review prior to operating\nat the Special Permit MAOP.\nb) Special Permit Conditions 3, 13, 14, 16, 18, 21, 22 through 34, 36 through 43, 45 and\n47 must be included in the operator's written operating and maintenance (O&M)\nprocedures manual concerning permit condition requirements with documentation\navailable for PHMSA review prior to operating at the Special Permit MAOP.\n47) Annual Reporting: MEP must report the following to the appropriate PHMSA regional\noffices annually:\na) The results of any ILl or direct assessment results performed within the special permit\narea during the previous year;\nb) Any new integrity threats identified within the special permit area during the previous\nyear;\nc) The number of new residences, other structures intended for human occupancy and\npublic gathering areas built within the special permit area;\nd) Any class or HCA changes in the special permit area during the previous year;\ne) Any reportable incidents associated with the special permit area that occurred during\nthe previous year;\nf Any leaks on the pipeline in the special permit area that occurred during the previous\nyear;\ng) A list of all repairs on the pipeline in the special permit area made during the previous\nyear;\nh) On-going damage prevention initiatives on the pipeline in the special permit area and a\ndiscussion of their success or failure;\ni) Any changes in procedures used to assess and/or monitor the pipeline operating under\n'Annual reports must be received by PHMSA by the last day of the month in which the Special Permit is dated. For\nMarch 31 each year beginning in 2009.\nexample, the annual report for a Special Permit dated March 4, 2008, must be received by PHMSA no later than\n\n<<<PAGE 12>>>\n\n12\nthis special permit; and\nj) Any company mergers, acquisitions, transfers of assets, or other events affecting the\nregulatory responsibility of the company operating the pipeline to which this special\npermit applies.\nLimitations:\nPHMSA grants this special permit subject to the following limitations:\n1) PHMSA has the sole authority to make all determinations on whether MEP has complied\nwith the specified conditions of this special permit.\n2) Should MEP fail to comply with any of the specified conditions of this special permit,\nPHMSA may revoke this special permit and require MEP to comply with the regulatory\nrequirements in 49 CFR §§ 192.111 and 192.201.\n3) PHMSA may revoke, suspend or modify a special permit based on any finding listed in\n49 CFR § 190.341(h)(1) and require MEP to comply with the regulatory requirements in\n49 CFR §§ 192.111 and 192.201.\n4) Should PHMSA revoke, suspend or modify a special permit based on any finding listed in\n49 CFR § 190.341(h)(1), PHMSA will notify MEP in writing of the proposed action and\nprovide MEP an opportunity to show cause why the action should not be taken unless\nPHMSA determines that taking such action is immediately necessary to avoid the risk of\nsignificant harm to persons, property or the environment (see 49 CFR § 190.341(h)(2)).\n5) The terms and conditions of any corrective action order, compliance order or other order\napplicable to a pipeline facility covered by this special permit will take precedence over the\nterms of this special permit in accordance with 49 CFR § 190.341(h) (4).\nAUTHORITY: 49 U.S.C. 60118(c) and 49 CFR § 1.53.\nIssued in Washington, DC on\nDEC\n5 2008\nBittese\nJeffrey D. Wiese,\nAssociate Administrator for Pipeline Safety\n\n<<<PAGE 13>>>\n\nof Transportation\nU.S. Department\n1200 New Jersey Avenue, SE\nMaterials Safety\nPipeline and Hazardous\nDEC 5 2008\nWashington, D.C. 20590\nAdministration\nMr. M. Dwayne Burton\nVice President, Gas Pipeline Operations and Engineering\nKinder Morgan, Inc.\nOne Allen Center\n500 Dallas Street, Suite 1000\nHouston, TX 77002\nDocket No. PHMSA-2007-27842\nDear Mr. Burton:\nOn April 4, 2007, you wrote to the Pipeline and Hazardous Materials Safety Administration\n(PHMSA) requesting a waiver of compliance from the Federal pipeline safety regulations in\n49 CFR §§ 192.111 and 192.201 for approximately 500-miles of proposed interstate natural gas\ntransmission pipeline. This pipeline will be operated by Midcontinent Express Pipeline, LLC\n(MEP), a jointly owned subsidiary of Kinder Morgan Energy Partners, L.P., and Energy\nTransfer Partners L.P. The new pipeline will originate in Bryan County, Oklahoma, and run\nsoutheasterly through Texas, Louisiana and Mississippi to existing facilities in Choctaw County,\nAlabama.\nOn October 13, 2008, PHMSA published the final rule, Standards for Increasing the Maximum\nAllowable Operating Pressure for Gas Transmission Pipelines, which becomes effective 30 days\nafter publication. The rule covers the requirements for any pipeline to operate at a design factor\nof up to 0.80 in Class 1 areas. PHMSA is proceeding with issuing the Midcontinent Express\nPipeline special permit as a result of the thorough analysis contained in the Special Permit\nAnalysis and Findings document, prepared well in advance of the final rule. Moreover, since\nthe Midcontinent Express pipeline varies from certain provisions of the final rule, this special\npermit is necessary to cover all requested variances from regulations and required conditions,\nand is consistent with, or more stringent than, prior grants of special permit for existing\npipelines.\nPHMSA is granting this waiver through the enclosed special permit, which allows MEP to\ndesign, construct and operate the MEP pipeline in Class 1 locations, using a design factor in\n§ 192.111 up to 0.80 and at stress levels up to 80% of the specified minimum yield strength\n(SMYS). This would result in a maximum allowable operating pressure (MAOP) of 1,480 psig.\nThis special permit also allows MEP to design, install and operate pressure relief and limiting\ndevices on the MEP pipeline, with a capacity that would ensure the pressure in Class 1 location\npipeline segments would not exceed 104% of the MAOP, or the pressure that produces a hoop\nstress of 83.2% SMYS in the event an overpressure situation develops. This special permit has\nconditions and limitations and provides some relief from the Federal pipeline safety regulations\nfor the MEP pipeline, while ensuring that pipeline safety is not compromised.\n\n<<<PAGE 14>>>\n\nPage 2\nMr. M. Dwayne Burton\nDocket No. PHMSA-2007-27842\nMy staff would be pleased to discuss this special permit or any other regulatory matter with\nyou. John Gale, Director of Regulations, (202-366-0434), may be contacted on regulatory\nmatters and Alan Mayberry, Director of Engineering and Emergency Support (202-366-5124),\nmay be contacted on matters specific to this special permit.\nSincerely,\nDirese\nJeffrey D. Wiese\nAssociate Administrator for Pipeline Safety\nEnclosure: Special Permit","truncated":false,"body_characters":30858}