{"operation":"document","citation":"PHMSA-2007-29078","title":"Kern River Gas Transmission Company — Pipeline Special Permit","source_type":"permit","agency":"Pipeline and Hazardous Materials Safety Administration","status":"current","official":true,"published_on":"2008-11-06","effective_on":"2008-11-06","summary":"PHMSA-2007-29078, issued 2008-11-06 for Kern River Gas Transmission Company's gas transmission system.","machine_formats":{"json":"https://regulus.evalyn.ai/document/phmsa-special-permit-phmsa-2007-29078.json","markdown":"https://regulus.evalyn.ai/document/phmsa-special-permit-phmsa-2007-29078.md"},"app_url":"https://regulus.evalyn.ai/document/phmsa-special-permit-phmsa-2007-29078","source_url":"https://www.regulations.gov/docket/PHMSA-2007-29078","body":"PHMSA pipeline special permit PHMSA-2007-29078. Operator: Kern River Gas Transmission Company. System: Gas Transmission. Issue date: 2008-11-06. Renewal: Mar 3, 2020.\n\n<<<PAGE 1>>>\n\nU.S. Department ofTransportation\nPipeline IJnd Hazardous Materials\nSafety Administration\n1200 New Jersey Ave, S.E.\nWashington, D.C. 20590\nJUL 3 0 l~l~\nMr. RobertS. Checketts\nVice President, Operations, IT and Engineering\nKern River Gas Transmission Company\n2755 E. Cottonwood Parkway, Suite 300\nSalt Lake City, Utah 84121\nRef: Special Permit PHMSA-2007-29078\nDear Mr. Checketts:\nThe Pipeline and Hazardous Materials Safety Administration (PHMSA), Office of Pipeline\nSafety hereby gives notice that the referenced alternative maximum allowable operating pressure\n(MAOP) special permit PHMSA-2007 -29078, granted to the Kern River Gas Transmission\nCompany (Kern River) on March 29, 2010, will expire on March 29, 2015.\nA Special Permit requiring renewal is defined as a special permit issued with an expiration date\nin the \"limitations\" section of the existing special permit. If Kern River wishes to renew this\nspecial permit, notice must be given to the PHMSA Associate Administrator for Pipeline Safety\nat least 180 days prior to the expiration date. The procedures for renewal are outlined on the\nfollowing pages.\nMy staff would be pleased to discuss this special permit or any other regulatory matter with you.\nMr. John Gale, Director of Standards and Rulemaking Division, may be contacted at\n202-366-0434 for regulatory matters, and Mr. Ken Lee, Director of Engineering and Research\nDivision, may be contacted at 202-366-2694, for technical matters specific to the renewal of this\nspecial permit.\nSincerely,\n~ .. ~[~p\nF Associate Administrator for Pipeline Safety\n\n<<<PAGE 2>>>\n\nThe Pipeline and Hazardous Materials Safety Administration (PHMSA)\nOffice of Pipeline Safety ( OPS)\nFederal Special Permit Renewal Requirements\nJune2014\nSpecial permits issued with an expiration date must be renewed prior to the expiration of the\nspecial permit. Special permits requiring renewal are defined as: special permits issued with\nan expiration date in the \"limitations\" section of the existing special permit. A notice of intent\nto renew the expiring special permit must be made at least 180 days prior to the expiration.\nRenewal requests sent by United States Postal Service mail, express mail, or overnight\ncourier. must be addressed to:\nThe Associate Administrator for Pipeline Safety\nPipeline and Hazardous Materials Safety Administration\n1200 New Jersey Avenue, SE, East Building\nWashington, DC 20590\nTo expedite the delivery of the renewal application and attachments, we encourage pipeline\noperators to provide us with an electronic copy of the renewal application. The electronic\ncopy renewal request must be sent by e-mail to John.Gale@dot.gov and kay.mciver@dot.gov.\nPlease do not fax PHMSA renewal requests or documents.\nPHMSA may seek additional operational, integrity or environmental assessment information\nprior to granting any request for special permit.\nThe renewal application must contain:\n(a) Special Permit: A copy of the original grant of the special permit.\n(b) Docket: PHMSA Docket Number of the issued special permit\n(c) Summary Report: A summary report that defines the following information from the\nissuance of the special permit to present.\n(i) Special Permit Number\n(ii) Grantee, or Pipeline Owner or Operator:\n1) Parent Company:\n2) Executive Contact: Mailing Address, Phone Number and e-mail\naddress; and\n3) Technical or Operational Contact: Mailing Address, Phone\nNumber and e-mail address.\n(iii) Location of Special Permit: areas on the pipeline where the special\npermit is applicable including: diameter, mile posts, county, and state.\nKern River Gas Transmission Company- PHMSA-2007-29078\nPage 2 of 4\n\n<<<PAGE 3>>>\n\n(iii) Location of Special Permit: areas on the pipeline where the special permit\nis applicable including: diameter, mile posts, county, and state.\n(iv) Applicable Usage or Need of the Special Permit: original and future\nincluding applicable Federal Code sections for special permit.\n(v) Annual Report: A copy of each special permit annual report (Condition 47)\ngenerated since the issuance of the special permit (maximum of 5 reports).\nAnnual reports may be consolidated into a single report. [Annual reports\non file. Not needed at this time.]\n(vi) Operating Pressure for Special Permit Segment: Maximum allowable\noperating pressure (MAOP).\n(vii) High Consequence Areas (HCAs) for Special Permit Segment: HCA\nboundaries on aerial photography; (If new HCAs have been added since the\nspecial permit was granted.)\n(viii) In-line inspection (ILl) for Special Permit Segments and Areas: ILl\nsurvey summary results from all ILl tools used on the special permit\nsegments and areas during the previous four ( 4) years. The summary\nshould include any actionable anomalies or dents found, and all cracks in\npipe body, pipe seam or girth weld.\n(ix) Integrity Data Integration Summary for Special Permit: Integrity data\nintegration summary must be based upon threats as identified in Condition\n35(c) of the special permit.\n(x) In-service incidents for Special Permit Segments and Areas: Any in-\nservice ruptures or leaks including repair type and failure investigation\nfindings; aerial photography of area, within the special permit segment and\nspecial permit inspection area, if applicable.\n(xi) Certification: A signed certification letter by a senior executive officer\nstating that Kern River is meeting the requirements of Condition 55\nrequirements at time of the renewal request.\n(xii) Special Permit Conditions: any suggested condition modifications required\nto maintain safety and the environment.\n(xiii) Summary Report: The summary report must demonstrate that the special\npermit is still consistent with pipeline safety.\n(d) Renewals: For renewal requests made at least 180 days before expiration and\nconforming to the requirements of the renewal process, the special permit will\ncontinue to be in effect until PHMSA takes a final administrative action on the\napplication. After all documents are reviewed and the Associate Administrator of\nPipeline Safety determines that the renewal of the Special Permit is consistent with\nfederal regulations for public safety and the environment, a letter of decision and an\nupdated special permit will be mailed to the operator. The renewal special permit letter\nof decision, conditions, and analysis and findings will be placed in the corresponding\ndocket at www.Regulations.gov.\nKern River Gas Transmission Company- PHMSA-2007-29078\nPage 3 of 4\n\n<<<PAGE 4>>>\n\n(e) State Partners: State partners in the affected state(s) will be notified of the renewal\napplication. A Federal Register Notice of the renewal application will be initiated for a\n30-day comment period.\n(f) Environmental Assessment: An Environmental Assessment (EA) may not be needed if\none was conducted and noticed for the original special permit. If an EA must be\nconducted, then the renewal process will be lengthier. The operator will be responsible\nfor development and submission of the EA requirements. PHMSA will review the EA\nfor conformity to National Environmental Policy Act and federal pipeline regulations.\nThe EA will be publicized in the Federal Register for a comment period of 30 days.\nPHMSA will notify the operator of any EA requirements after receipt of the renewal\napplication.\n(g) Special Permit Decision Process: - Denial of renewal reqnest: If the Special Permit\nrequest is denied, the denial will be handled in accordance with the denial procedures\nincluding the appeal process outlined in 49 CFR § 190.341.\nKern River Gas Transmission Company- PHMSA-2007-29078\nPage4 of4\n\n<<<PAGE 1>>>\n\nU.S. Department of Transportation\nPipeline and Hazardous Materials\nSafety Administration\n1200 New Jersey Ave, S.E.\nWashington, D.C. 20590\nFEB 1 2 2015\nMr. RobertS. Checketts\nVice President, Operations, IT and Engineering\nKern River Gas Transmission Company\n2755 E. Cottonwood Parkway, Suite 300\nSalt Lake City, Utah 84121\nRef: Special Permit Renewal March 29, 2015 to March 29, 2020\nPHMSA-2007 -29078\nPHMSA-2009-0377\nDear Mr. Checketts:\nBy letter dated July 30, 2014, the Pipeline and Hazardous Materials Safety Administration\n(PHMSA), Office of Pipeline Safety (OPS) notified the Kern River Gas Transmission\nCompany (Kern River) that the special permit granted to Kern River on March 29, 2010, to\nwaive compliance with certain federal regulations in 49 CFR §§ 192.111, 192.201, 192.505,\nand 192.619 for the 1,380-mile Kern River pipeline system would expire on March 29, 2015,\nunless renewed. The special permit allows Kern River to operate above the normal pipeline\n72 percent of specified minimum yield strength (SMYS) operating pressures of 1,200 pounds\nper square inch gauge (psig) up to 1,333 psig (80 percent SMYS) on the 36-inch mainline and\nloop pipelines, and up to 1,350 psig in its compressor stations.\nBy letter dated August 29, 2014, and supplemented by additional correspondence, Kern River\napplied for the renewal of the special permit and provided operational documentation to\njustify the special permit renewal. On November 4, 2014, PHMSA published a Federal\nRegister notice announcing the renewal request (79 FR 65477). No public comments were\nreceived. The special permit renewal request letter and all other pertinent documents are\navailable for review in Docket No. PHMSA-2007-29078 in the Federal Docket Management\nSystem (FDMS) located at www.Regulations.gov.\nPHMSA reviewed all operational and maintenance data submitted by Kern River for the\n1,380 mile Kern River facilities that spans from the discharges of the Muddy Creek and\nPainter Compressor stations, and at the Anschutz meter in Lincoln County, WY, to the outlet\nside of the Daggett meter station in San Bernardino County, CA, to the mainline. PHMSA\nfinds that Kern River continues to meet the terms of the special permit and there has been no\nmaterial change in conditions. Based on the information provided by Kern River, PHMSA\nhas determined that renewal of the special permit would not be inconsistent with pipeline\nsafety.\n\n<<<PAGE 2>>>\n\nAccordingly, by this Order, and as described in the original special permit, PHMSA\ngrants the Kern River Gas Transmission Company a special permit renewal for\nPHMSA-2007-29078 (PHMSA-2009-0377) to operate from March 29,2015, through\nMarch 29, 2020, for the 1,380-mile Kern River pipeline system facilities. This special\npermit renewal Order waives compliance with certain Federal regulations in 49 CFR\n§§ 192.111, 192.201, 192.505, and 192.619, for the 1,380-mile Kern River pipeline system\nfacilities.\nMy staff would be pleased to discuss these special permits or any other regulatory matter with\nyou. Mr. Chris Hoidal, Director, PHMSA, OPS, Western Region, may be contacted at\n720-963-3160, for operational matters specific to the renewal of this special permit. Mr. John\nGale, Director of Standards and Rulemaking Division, may be contacted at 202-366-0434 for\nregulatory matters, and Mr. Ken Lee, Director of Engineering and Research Division, may be\ncontacted at 202-366-2694, for technical matters.\nSincerely,\n-BXJ~\nJeffrey D. Wiese\nAssociate Administrator for Pipeline Safety\nPage 2 of2\nPHMSA-2007-29078 (PHMSA-2009-0377) Kern River Gas Transmission Company\nMarch 29, 2015 to March 29, 2020\n\n<<<PAGE 1>>>\n\nNOV 6 2008\nU.S. DEPARTMENT OF TRANSPORTATION\n1\nPIPELINE AND HAZARDOUS MATERIALS SAFETY ADMINISTRATION (PHMSA)\nSPECIAL PERMIT\nDocket Number: PHMSA-2007-29078\nRequested By:\nKern River Gas Transmission Company\nDate Requested: August 20, 2007\nCode Sections:\n49 CFR $$ 192.111, 192.201, 192.505, and 192.619\nGrant of Special Permit:\nBy this order, The Pipeline and Hazardous Materials Safety Administration (PHMSA) grants this\nspecial permit to the Kern River Gas Transmission Company (Kern River) subject to the\nconditions and limitations set forth below. This special permit waives compliance from 49 CFR\n§$ 192.111, 192.201, 192.505 and 192.619 for the 1,380-mile Kern River pipeline system. For\nthe purposes of this special permit, the Kern River pipeline system means pipeline facilities\nbeginning at the discharges of the Muddy Creek and Painter compressor stations, and at the\nAnschutz meter in Lincoln County, WY, to the outlet side of the Daggett meter station in San\nBernardino County, CA to the mainline. The Kern River pipeline system consists of 682 miles of\na 36-inch diameter mainline, 635 miles of 36-inch diameter loop lines, 10 compressor stations,\n48 meter stations, 6 receipt laterals, and 7 delivery laterals.\nThe Federal pipeline safety regulations in § 192.111 limit the design factors' for steel natural gas\ntransmission pipelines for Class locations 1, 2 and 3 to the values in the following table:\nClass\nMaximum\nLocation\nDesign\nClass\nMaximum\nClass\nMaximum\nFactor\nLocation\nDesign\nFactor\nLocation\nDesign\nGeneral\n1\nFactor\n0.72\n2\n0.60\n3\n0.50\nUn-cased\nroad\n0.60\n2\n0.50\n3\ncrossings\n0.50\nFabricated\nAssembly\n1\n0.60\n2\n0.60\n3\n0.50\nSupported\non Bridge\n1\n0.60\n2\n0.60\n3\n0.50\nStations\n1\n0.50\n2\n0.50\n3\n0.50\nPecied ministim yiche rength iS of tine pipe for examine. a rain pres or 102 were lame ore pipelin\nessure to a value that results in a hoop stress level of 72% SMY.\n\n<<<PAGE 2>>>\n\n2\nThis special permit allows Kern River to raise the maximum allowable operating pressure\n(MAOP) of the Kern River pipeline system from 1200 pounds per square inch gauge (psig) to\n1333 psig in the mainline and loop lines and to 1350 psig in the compressor station pipe.\nAccordingly, this special permit allows Ker River to operate the Kern River pipeline in Class\nlocations 1, 2 and 3 using the design factors in the following table:\nClass\nMaximum\nLocation\nDesign\nClass\nMaximum\nDesign\nClass\nMaximum\nFactor\nLocation\nFactor\nLocation\nDesign\nFactor\nGeneral\n1\n0.80\n2\n0.67\n3\n0.56\nUn-cased\nroad\n1\n0.67\n2\n0.56\n3\ncrossings\n0.56\nFabricated\n1\nAssembly\n0.67\n2\n0.67\n3\n0.56\nSupported\non Bridge\n1\n0.67\n2\n0.67\n3\n0.56\nStations\n1\n0.56\n2\n0.56\n3\n0.56\nBecause the proposed operating stress level of 80% specified minimum yield strength (SMYS) is\nhigher than the upper limit of the required overpressure protection under the existing Federal\npipeline safety regulations [i.e. 10% over MAOP or 75% SMYS], this special permit also allows\nKern River to design, install and operate pressure relief and limiting devices on the applicable\nsegment of the Kern River pipeline with a capacity that would ensure the pressure in Class\nlocations 1, 2 and 3 pipeline segments would not exceed 104% of the MAOP or the pressure that\nproduces a hoop stress of 83.2% SMYS in Class 1 locations, 69.7% SMYS in Class 2 locations\nor 58.2% SMYS in Class 3 locations in the event an overpressure situation develops.\nThis special permit also waives the strength test requirements in § 192.505 and the MAOP\nregulations in § 192.619, which allows Kern River to raise the MAOP of the applicable segment\nof the Kern River pipeline from 1202 psig to 1336 psig.\nFor the purpose of this special permit, the \"special permit area\" means the area consisting of the\nentire pipeline right-of-way for those sections along the applicable segment of the Kern River\npipeline that will operate above 72% SMYS in Class 1 locations, 60% SMYS in Class 2\n' There are currently no class 4 locations on the Kern River Transmission Company Pipeline System. This special\npermit does not apply to any future class 4 locations on the Kern River Transmission Company Pipeline System.\n\n<<<PAGE 3>>>\n\nlocations or 50% SMYS in Class 3 locations.\n3\n:\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-2007-29078\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:\nSteel Properties: The skelp/plate must be micro alloyed, fine grain, fully killed steel with\ncalcium treatment and continuous casting.\n2) Manufacturing Standards: New pipe segments or replacement pipe must be manufactured\naccording to American Petroleum Institute Specification SL, Specification for Line Pipe\n(API 5L), product specification level 2 (PSL 2), supplementary requirements (SR) for\nmaximum operating pressures and minimum operating temperatures. Pipe carbon\nequivalents must be at or below 0.25% based on the material chemistry parameter (Pcm)\nformula or 0.43% based on the C-IIW formula.\n3)\nFracture Control: API SL, 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. Kern River must institute an overall fracture\ncontrol plan addressing the steel pipe properties necessary to resist crack initiation and\ncrack propagation and to arrest a fracture within 8 pipe joints with a 99% occurrence\nprobability or within 5 pipe joints with a 90% occurrence probability. The plan must\ninclude acceptable Charpy Impact values, which are measures of a steel pipeline's\ntoughness and resistance to fracture. The fracture control plan, which must be submitted to\nPHMSA headquarters, must be in accordance with API 5L, Appendix F and must include\nthe following tests:\na)\nSR 5A - Fracture Toughness Testing for Shear Area: Test results must indicate at\nleast 85% minimum average shear area for all X- 70 heats and 80% minimum shear\narea for all X- 80 heats with a minimum result of 80% shear area for any single test.\nThe test results must also ensure a ductile fracture and arrest;\nb) SR 5B - Fracture Toughness Testing for Absorbed Energy; and\n\n<<<PAGE 4>>>\n\nc) SR 6 - Fracture Toughness Testing by Drop Weight Tear Test for All New Pipeline\nSegments or Pipe Replacements: Test results must be at least 80% of the average shear\narea for all heats with a minimum result of 60% of the shear area for any single test.\nThe test results must also ensure a ductile fracture and arrest.\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, Kern\nRiver must submit to PHMSA headquarters an alternative plan providing an acceptable\nmethod to resist crack initiation, crack propagation and to arrest ductile fractures in the\nspecial permit area.\n4) Steel Plate Quality Control for All New Pipeline Segments or Pipe Replacements: The\nsteel mill and/or pipe rolling mill must incorporate a comprehensive plate/coil mill and\npipe mill inspection program to check for defects and inclusions that could affect the pipe\nquality. This program must include a plate or rolled pipe ultrasonic testing (UT) inspection\nprogram to check for imperfections such as laminations. UT inspection must be conducted\non all factory beveled pipe ends. In addition, pipe body UT inspection must be conducted\non a minimum of 100% of pipe joints and all ends, with a minimum coverage of 35% of\nthe pipe body for those joints inspected. Any laminations identified by the UT inspection\nprogram must be evaluated in accordance with the acceptance criteria defined in ASTM\nInternational Standard ASTM A578/A578M \"Standard Specification for Straight-Beam\nUltrasonic Examination of Rolled Steel Plates for Special Applications (ASTM A578),\"\nLevel B or API 5L Paragraph 7.8.10. An inspection protocol for centerline segregation\nevaluation using a test method referred to as slab macro-etching must be employed to\ncheck for inclusions that may form as the steel plate cools after it has been cast. A\nminimum of one macro-etch or a suitable alternative test must be performed from the first\nor second heat (manufacturing run) of each sequence (approximately 4 heats) and graded\non the Mannesmann scale or equivalent. Test results with a Mannesmann scale rating of\none or two out of a possible four or five scale are acceptable.\nPipe Seam Quality Control for All New Pipeline Segments or Pipe Replacements: A\nquality assurance program must be instituted for pipe weld seams. The pipe weld seam\n\n<<<PAGE 5>>>\n\ntests must meet the minimum requirements for tensile strength in API 5L for the\n5\nappropriate pipe grade properties. A pipe weld seam hardness test using the Vickers\nhardness testing of a cross-section from the weld seam must be performed on one length of\npipe from each heat. The maximum weld seam and heat affected zone hardness must be a\nmaximum of 280 Vickers hardness (Hv10). The hardness tests must include a minimum of\n3 readings for each heat affected zone, 3 readings in the weld metal and 2 readings in each\nsection of pipe base metal for a total of 13 readings. The pipe weld seam must be 100%\nUT inspected after expansion and hydrostatic testing per API 5L.\n6) Mill Hydrostatic Test for All New Pipeline Segments or Pipe Replacements: The pipe\nmust be subjected to a mill hydrostatic test to achieve a minimum stress level of 95%\nSMYS in the pipe for a minimum duration of 10 seconds. The 95% stress level may be\nachieved using a combination of internal test pressure and the application of end loads\nimposed by the hydrostatic testing equipment as allowed by API 5L, Appendix K\n7)\nPipe Coating for All New Pipeline Segments or Pipe Replacements: The application of a\ncorrosion resistant coating to the steel pipe must be subject to a coating application quality\ncontrol program. The program must address pipe surface cleanliness standards, blast\ncleaning, application temperature control, adhesion, cathodic disbondment, moisture\npermeation, bending, minimum coating thickness, coating imperfections and coating repair.\nThe pipe for existing pipeline segments, new pipeline segments and/or replacements must\nbe protected against external corrosion by a non-shielding coating.\nField Coating for All New Pipeline Segments or Pipe Replacements: A field girth weld\njoint coating application specification and quality standards to ensure pipe surface\ncleanliness, application temperature control, adhesion quality, cathodic disbondment,\nmoisture permeation, bending, minimum coating thickness, holiday detection and repair\nquality must be implemented in field conditions. Field joint coatings must be non-\nshielding to cathodic protection (CP). Field coating applicators must use valid coating\nprocedures and be trained to use these procedures.\nField Coating: The coatings on existing girth weld joints must be non-shielding to CP.\n10) Coatings for Trenchless Installation for All New Pipeline Segments or Pipe Replacements:\nCoatings used for directional bore, slick bore and other trenchless installation methods\nmust resist abrasions and other damages that may occur due to rocks and other obstructions\nencountered in this installation technique.\n11) 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\n\n<<<PAGE 6>>>\n\nequivalents (CE) below 0.42 or a pre-heat procedure must be applied prior to welding for\nCE above 0.42.\n12) Design Factor - Pipelines: Pipe installed under this special permit in Class 1 location may\nuse a design factor of 0.80, in Class 2 locations may use a design factor of 0.67 and in\nClass 3 locations may use a design factor of 0.56. Road crossings in Class 1 and 2\nlocations may use a design factor of 0.67 and 0.56, respectively. New road crossings,\nrailroad crossings and fabricated assemblies must be designed using the existing design\nfactors in § 192.111(b) and (c).\n13) 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.\n14) 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 Kern River's technical coating operating tests show that the pipe coating\nwill properly withstand the higher operating temperature for long term operations. If the\ntemperature exceeds 120° Fahrenheit, Kern River 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 and results must be provided to the Director,\nPHMSA Western Region at least 60 days prior to implementation of the increased\ntemperature or special permit operations.\n15) Overpressure Protection Control: Mainline pipeline overpressure protection must be\nlimited to a maximum of 104% MAOP.\n16) Welding Procedures for All New Pipeline Segments or Pipe Replacements: For automatic\nor mechanized welding the 19' Edition of API 1104, \"Welding of Pipelines and Related\nFacilities\", will be used for welding procedure qualification, welder qualification and weld\nacceptance criteria. Operator will use the 19th Edition of API 1104 for all other welding\nprocesses. The Director, PHMSA Western Region must be notified at least 14 days prior to\nthe beginning of any welding procedure qualification activities. Automated or manual\nwelding procedure documentation must be submitted to the same PHMSA regional office.\n17) 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 7>>>\n\n7\nthe pipeline. If routine patrols or other observed conditions indicate the possible loss of\ncover over the pipeline, Kern River will perform a depth of cover study and replace cover\nas necessary to meet the minimum depth of cover requirements specified herein. If\nreplacing cover is not practical, the Director, PHMSA Western Region may agree to an\nalternate plan to assure safety in these areas.\n18) Construction Quality for All New Pipeline Segments or Pipe Replacements: A construction\nquality assurance plan to ensure quality standards and controls must be maintained\nthroughout the construction phase with respect to: inspection, pipe hauling and stringing,\nfield bending, welding, non-destructive examination (NDE) of girth welds, field joint\ncoating, pipeline coating integrity tests, lowering of the pipeline in the ditch, padding\nmaterials to protect the pipeline, backfilling, alternating current (AC) interference\nmitigation and CP systems. All girth welds must be non-destructively examined by\nradiography or alternative means. The NDE examiner must have all required and current\ncertifications.\n19) 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.\n20) Test Level for All New Pipeline Segments or Pipe Replacements: The pre-in service\nhydrostatic test must be to a pressure producing a hoop stress of at least 100% SMYS and\n1.25 X MAOP in areas to operate to 80% SMYS, at least 1.50 X MAOP in areas to operate\nup to 67% SMYS, and at least 1.50 X MAOP in areas to operate up to 56% SMYS.\n21) Uprating Existing Pipeline Segments: Kern River must meet one of the following criteria\nin Condition 21 (a), (b), or (c), prior to uprating any existing pipeline segment in the\nspecial permit area to an MAOP above 72% SMYS in Class 1 locations, 60% SMYS in\nClass 2 locations or 50% SMYS in Class 3 locations:\na) Hydrostatic Tests: Class 1, 2, and 3 locations in the special permit area must have been\nhydrostatically tested prior to the grant of this special permit as follows:\n1) Class 1 and Class 2 locations containing a high consequence area (HCA) per 49 CFR\nPart 192, Subpart O - the pipeline segment must be hydrostatically pressure tested to at\nleast 1.25 X MAOP.\n\n<<<PAGE 8>>>\n\n2) Class 3 locations - the hydrostatic test pressure must be a minimum of 1.40 x\n8\nMAOP.\n3) Whenever a change in class location has occurred anywhere within the special\npermit area prior to uprating the existing pipeline segment (e.g. Class 1 to 2 or Class 2\nto 3), the class change location must meet the hydrostatic test and repair requirements\nof Conditions 43, 51 and 52.\nb) Overpressure Protection: Class 1, Class 2 and Class 3 locations - in lieu of\nhydrostatically pressure testing a pipeline segment in accordance with Condition 21 a)\nabove, Kern River may operate the pipeline segment taking into account the pressure\ngradient provided they install protection against accidental overpressure in accordance\nwith the existing requirements in $$192.195, 192.199, and 192.201.\nc) Pressure Gradient Monitoring: Class 1, Class 2 and Class 3 locations - in lieu of\nhydrostatically pressure testing a pipeline segment in accordance with Condition 21 (a)\nand installing overpressure protection in accordance with Condition 21 (b) above, Kern\nRiver may operate the pipeline segment taking into account the pipeline pressure\ngradient provided they install overpressure protection and use operating procedures\ndesigned to prevent accidental overpressure of the pipeline in accordance with the\nfollowing requirements:\n1) The written operating procedures must include pressure gradient monitoring along\nthe pipeline at mainline valves as operating conditions change with updated gas flow\nmodels,\n2) Two operational pressure sensors must be installed at each mainline valve upstream\nof pipeline segments that do not meet the criteria of Conditions 21 (a) and (b) above,\nand must be tied into the SCADA system and set-up to limit and control compressor\ndischarge pressures based upon the gas flow gradient model and pressure of the gas\nalong the pipeline so as not to exceed the limits of Conditions 21 (a) and b),\n3) A review and training of written operating procedures and gas gradient flow models\nmust be conducted with gas controllers responsible for these operating procedures at\nleast once each calendar quarter,\n4) Pressure sensors must be calibrated once each calendar year at intervals not to\nexceed 15 months, and\n5) Whenever a change in class location has occurred anywhere within the special\npermit area prior to the grant of this special permit (e.g. Class 1 to 2 or Class 2 to 3), the\nclass change location must meet the requirements of Conditions 43 and 52 of this\n\n<<<PAGE 9>>>\n\nspecial permit.\n9\n22) Assessment of Test Failures: Any pipe failure occurring during a pre-in service hydrostatic\ntest or a hydrostatic test of an existing pipeline segment must undergo a root cause failure\nanalysis to include a metallurgical examination of the failed pipe. The results of this\nexamination must preclude a systemic pipeline material issue and the results must be\nreported to PHMSA headquarters and to the Director, PHMSA Western Region.\n23) Supervisory Control and Data Acquisition (SCADA) System Capabilities: A SCADA\nsystem to provide remote monitoring and control of the pipeline system must be employed.\n24) SCADA Procedures: A detailed procedure for establishing and maintaining accurate\nSCADA set points must be established to ensure the pipeline operates within acceptable\ndesign limits at all times.\n25) 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.\n26) 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.\n27)\nGas 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.\n28) The pipeline must have an ongoing pigging and liquids sampling plan to identify, mitigate\nand remove deleterious constituents, where applicable.\n29) If H¿S is above 8 ppm, the gas stream constituents must be reviewed for implementation of\na quarterly pigging/inhibitor injection program, including follow up sampling of liquids at\nreceipt points.\n30) 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\n\n<<<PAGE 10>>>\n\ndeleterious free liquids and/or particulates to minimize the entry of contaminants and to\n10\nprotect the integrity of downstream pipeline segments.\n31) Gas Quality Monitoring Equipment: Equipment, including moisture analyzer,\nchromatograph and semi-annual HaS sampling (quarterly sampling where HaS 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.\n32) Interference Current Surveys: Interference surveys must be performed before increasing\nthe pressure above the existing MAOP to ensure compliance with applicable NACE\nInternational Standard Practices 0169 and 0177 (NACE SP 0169 and NACE SP 0177) for\ninterference current levels. If interference currents are found, Kern River will determine if\nthere have been any adverse effects to the pipeline and mitigate the effects as necessary.\nKern River will report the results of any negative finding and the associated mitigative\nefforts to the Director, PHMSA Western Region.\n33) Verification of Cathodic Protection: An interrupted close interval survey (CIS) must be\nperformed in concert and integrated with ILI 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. If one-half mile spacing\nbetween test stations is not practical, the PHMSA Regional Director of the Western Region\nmay agree to an alternate plan to verify cathodic protection in these areas.\n34) Initial Close Interval Survey (CIS) - Initial: Kern River must have performed a CIS on the\npipeline in the special permit area within the two years immediately prior to the increase in\noperating pressure above the existing MAOP or a CIS must be completed within one year\nafter the pressure increase. The CIS results must be integrated with the ILI results to\ndetermine whether any further action is needed.\n35) Coating Assessment: To verify the pipeline coating conditions and to remediate any\nintegrity issues, Kern River must perform a DCVG survey or an ACVG survey of the\nfollowing not later than one year after the grant of this special permit.\na) all piping in the special permit area that has operated above 120 degrees Fahrenheit,\nb) all Class 1 locations with structures within 300 feet of the pipeline,\nc) all Class 2 and all Class 3 locations; and\n\n<<<PAGE 11>>>\n\nd) all HCAs.\n11\nA DCVG or ACG survey and remediation need not be performed if Kern River has\nperformed a DCVG or ACG and remediation survey of the above, and completed the\nremediation of any integrity issue within the two years prior to the grant of this special\npermit. Kern River must remediate any damaged coating indications found during these\nassessments that are classified as moderate (i.e. 15% IR and above for DCVG or 35 dBuV\nand above for ACVG) or severe based on NACE International Recommended Practice\n0502-2002, Pipeline External Corrosion Direct Assessment Methodology, (NACE RP\n0502-2002). A minimum of two coating survey assessment classifications must be\nexcavated, classified and/or remediated per each survey crew and compressor station\ndischarge section. If factors beyond Kern River's control prevent the completion of the\nDCVG or ACVG survey and remediation within one year, a DCVG or ACG survey and\nremediation must be performed as soon as practicable and a letter justifying the delay and\nproviding the anticipated date of completion must be submitted to the Director, PHMSA\nWestern Region not later than one year after the grant of this special permit.\n36) Pipeline Markers: Kern River must employ line-of-sight markings on the pipeline in the\nspecial permit area except in agricultural areas or large water crossings such as lakes\nwhere line-of-sight markers are not practical. The marking of pipelines is also subject to\nFederal Energy Regulatory Commission orders or environmental permits and local\nrestrictions.\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)\nMonitoring 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)\nInitial ILI: Kern River must have performed an initial ILI inspection of the pipeline in the\nspecial permit area within the three years immediately prior to the increase in operating\npressure above the existing MAOP or the two years immediately after the increase in\npressure using a high-resolution magnetic flux leakage (MFL) tool and a geometry tool.\nThe results of the initial ILI must be integrated with the initial CIS required per condition\n34 above. Kern River must evaluate and repair all \"Repair Immediately\" and \"Repair\nwithin One Year\" anomalies (based on previous ILI inspections) in accordance with\ncondition 43 below prior to increasing the pressure above the existing MAOP.\n\n<<<PAGE 12>>>\n\n40) Future ILI: A second ILI using a high-resolution MFL must be completed on the\n12\npipeline in the special permit area within the first reassessment interval required by\n49 CFR Part 192, Subpart O, regardless of HCA classification. Future ILI must be\nperformed on a frequency consistent with Subpart O on the pipeline in the special permit\narea.\n41) Direct Assessment Plan: Headers, mainline valve bypasses and other sections in the\nspecial permit area that cannot accommodate IL","truncated":true,"body_characters":54696}