# Kern River Gas Transmission Company — Pipeline Special Permit - **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. <<>> U.S. Department ofTransportation Pipeline IJnd Hazardous Materials Safety Administration 1200 New Jersey Ave, S.E. Washington, D.C. 20590 JUL 3 0 l~l~ Mr. RobertS. Checketts Vice President, Operations, IT and Engineering Kern River Gas Transmission Company 2755 E. Cottonwood Parkway, Suite 300 Salt Lake City, Utah 84121 Ref: Special Permit PHMSA-2007-29078 Dear Mr. Checketts: The Pipeline and Hazardous Materials Safety Administration (PHMSA), Office of Pipeline Safety hereby gives notice that the referenced alternative maximum allowable operating pressure (MAOP) special permit PHMSA-2007 -29078, granted to the Kern River Gas Transmission Company (Kern River) on March 29, 2010, will expire on March 29, 2015. A Special Permit requiring renewal is defined as a special permit issued with an expiration date in the "limitations" section of the existing special permit. If Kern River wishes to renew this special permit, notice must be given to the PHMSA Associate Administrator for Pipeline Safety at least 180 days prior to the expiration date. The procedures for renewal are outlined on the following pages. My staff would be pleased to discuss this special permit or any other regulatory matter with you. Mr. John Gale, Director of Standards and Rulemaking Division, may be contacted at 202-366-0434 for regulatory matters, and Mr. Ken Lee, Director of Engineering and Research Division, may be contacted at 202-366-2694, for technical matters specific to the renewal of this special permit. Sincerely, ~ .. ~[~p F Associate Administrator for Pipeline Safety <<>> The Pipeline and Hazardous Materials Safety Administration (PHMSA) Office of Pipeline Safety ( OPS) Federal Special Permit Renewal Requirements June2014 Special permits issued with an expiration date must be renewed prior to the expiration of the special permit. Special permits requiring renewal are defined as: special permits issued with an expiration date in the "limitations" section of the existing special permit. A notice of intent to renew the expiring special permit must be made at least 180 days prior to the expiration. Renewal requests sent by United States Postal Service mail, express mail, or overnight courier. must be addressed to: The Associate Administrator for Pipeline Safety Pipeline and Hazardous Materials Safety Administration 1200 New Jersey Avenue, SE, East Building Washington, DC 20590 To expedite the delivery of the renewal application and attachments, we encourage pipeline operators to provide us with an electronic copy of the renewal application. The electronic copy renewal request must be sent by e-mail to John.Gale@dot.gov and kay.mciver@dot.gov. Please do not fax PHMSA renewal requests or documents. PHMSA may seek additional operational, integrity or environmental assessment information prior to granting any request for special permit. The renewal application must contain: (a) Special Permit: A copy of the original grant of the special permit. (b) Docket: PHMSA Docket Number of the issued special permit (c) Summary Report: A summary report that defines the following information from the issuance of the special permit to present. (i) Special Permit Number (ii) Grantee, or Pipeline Owner or Operator: 1) Parent Company: 2) Executive Contact: Mailing Address, Phone Number and e-mail address; and 3) Technical or Operational Contact: Mailing Address, Phone Number and e-mail address. (iii) Location of Special Permit: areas on the pipeline where the special permit is applicable including: diameter, mile posts, county, and state. Kern River Gas Transmission Company- PHMSA-2007-29078 Page 2 of 4 <<>> (iii) Location of Special Permit: areas on the pipeline where the special permit is applicable including: diameter, mile posts, county, and state. (iv) Applicable Usage or Need of the Special Permit: original and future including applicable Federal Code sections for special permit. (v) Annual Report: A copy of each special permit annual report (Condition 47) generated since the issuance of the special permit (maximum of 5 reports). Annual reports may be consolidated into a single report. [Annual reports on file. Not needed at this time.] (vi) Operating Pressure for Special Permit Segment: Maximum allowable operating pressure (MAOP). (vii) High Consequence Areas (HCAs) for Special Permit Segment: HCA boundaries on aerial photography; (If new HCAs have been added since the special permit was granted.) (viii) In-line inspection (ILl) for Special Permit Segments and Areas: ILl survey summary results from all ILl tools used on the special permit segments and areas during the previous four ( 4) years. The summary should include any actionable anomalies or dents found, and all cracks in pipe body, pipe seam or girth weld. (ix) Integrity Data Integration Summary for Special Permit: Integrity data integration summary must be based upon threats as identified in Condition 35(c) of the special permit. (x) In-service incidents for Special Permit Segments and Areas: Any in- service ruptures or leaks including repair type and failure investigation findings; aerial photography of area, within the special permit segment and special permit inspection area, if applicable. (xi) Certification: A signed certification letter by a senior executive officer stating that Kern River is meeting the requirements of Condition 55 requirements at time of the renewal request. (xii) Special Permit Conditions: any suggested condition modifications required to maintain safety and the environment. (xiii) Summary Report: The summary report must demonstrate that the special permit is still consistent with pipeline safety. (d) Renewals: For renewal requests made at least 180 days before expiration and conforming to the requirements of the renewal process, the special permit will continue to be in effect until PHMSA takes a final administrative action on the application. After all documents are reviewed and the Associate Administrator of Pipeline Safety determines that the renewal of the Special Permit is consistent with federal regulations for public safety and the environment, a letter of decision and an updated special permit will be mailed to the operator. The renewal special permit letter of decision, conditions, and analysis and findings will be placed in the corresponding docket at www.Regulations.gov. Kern River Gas Transmission Company- PHMSA-2007-29078 Page 3 of 4 <<>> (e) State Partners: State partners in the affected state(s) will be notified of the renewal application. A Federal Register Notice of the renewal application will be initiated for a 30-day comment period. (f) Environmental Assessment: An Environmental Assessment (EA) may not be needed if one was conducted and noticed for the original special permit. If an EA must be conducted, then the renewal process will be lengthier. The operator will be responsible for development and submission of the EA requirements. PHMSA will review the EA for conformity to National Environmental Policy Act and federal pipeline regulations. The EA will be publicized in the Federal Register for a comment period of 30 days. PHMSA will notify the operator of any EA requirements after receipt of the renewal application. (g) Special Permit Decision Process: - Denial of renewal reqnest: If the Special Permit request is denied, the denial will be handled in accordance with the denial procedures including the appeal process outlined in 49 CFR § 190.341. Kern River Gas Transmission Company- PHMSA-2007-29078 Page4 of4 <<>> U.S. Department of Transportation Pipeline and Hazardous Materials Safety Administration 1200 New Jersey Ave, S.E. Washington, D.C. 20590 FEB 1 2 2015 Mr. RobertS. Checketts Vice President, Operations, IT and Engineering Kern River Gas Transmission Company 2755 E. Cottonwood Parkway, Suite 300 Salt Lake City, Utah 84121 Ref: Special Permit Renewal March 29, 2015 to March 29, 2020 PHMSA-2007 -29078 PHMSA-2009-0377 Dear Mr. Checketts: By letter dated July 30, 2014, the Pipeline and Hazardous Materials Safety Administration (PHMSA), Office of Pipeline Safety (OPS) notified the Kern River Gas Transmission Company (Kern River) that the special permit granted to Kern River on March 29, 2010, to waive compliance with certain federal regulations in 49 CFR §§ 192.111, 192.201, 192.505, and 192.619 for the 1,380-mile Kern River pipeline system would expire on March 29, 2015, unless renewed. The special permit allows Kern River to operate above the normal pipeline 72 percent of specified minimum yield strength (SMYS) operating pressures of 1,200 pounds per square inch gauge (psig) up to 1,333 psig (80 percent SMYS) on the 36-inch mainline and loop pipelines, and up to 1,350 psig in its compressor stations. By letter dated August 29, 2014, and supplemented by additional correspondence, Kern River applied for the renewal of the special permit and provided operational documentation to justify the special permit renewal. On November 4, 2014, PHMSA published a Federal Register notice announcing the renewal request (79 FR 65477). No public comments were received. The special permit renewal request letter and all other pertinent documents are available for review in Docket No. PHMSA-2007-29078 in the Federal Docket Management System (FDMS) located at www.Regulations.gov. PHMSA reviewed all operational and maintenance data submitted by Kern River for the 1,380 mile Kern River facilities that spans from the discharges of the Muddy Creek and Painter Compressor stations, and at the Anschutz meter in Lincoln County, WY, to the outlet side of the Daggett meter station in San Bernardino County, CA, to the mainline. PHMSA finds that Kern River continues to meet the terms of the special permit and there has been no material change in conditions. Based on the information provided by Kern River, PHMSA has determined that renewal of the special permit would not be inconsistent with pipeline safety. <<>> Accordingly, by this Order, and as described in the original special permit, PHMSA grants the Kern River Gas Transmission Company a special permit renewal for PHMSA-2007-29078 (PHMSA-2009-0377) to operate from March 29,2015, through March 29, 2020, for the 1,380-mile Kern River pipeline system facilities. This special permit renewal Order waives compliance with certain Federal regulations in 49 CFR §§ 192.111, 192.201, 192.505, and 192.619, for the 1,380-mile Kern River pipeline system facilities. My staff would be pleased to discuss these special permits or any other regulatory matter with you. Mr. Chris Hoidal, Director, PHMSA, OPS, Western Region, may be contacted at 720-963-3160, for operational matters specific to the renewal of this special permit. Mr. John Gale, Director of Standards and Rulemaking Division, may be contacted at 202-366-0434 for regulatory matters, and Mr. Ken Lee, Director of Engineering and Research Division, may be contacted at 202-366-2694, for technical matters. Sincerely, -BXJ~ Jeffrey D. Wiese Associate Administrator for Pipeline Safety Page 2 of2 PHMSA-2007-29078 (PHMSA-2009-0377) Kern River Gas Transmission Company March 29, 2015 to March 29, 2020 <<>> NOV 6 2008 U.S. DEPARTMENT OF TRANSPORTATION 1 PIPELINE AND HAZARDOUS MATERIALS SAFETY ADMINISTRATION (PHMSA) SPECIAL PERMIT Docket Number: PHMSA-2007-29078 Requested By: Kern River Gas Transmission Company Date Requested: August 20, 2007 Code Sections: 49 CFR $$ 192.111, 192.201, 192.505, and 192.619 Grant of Special Permit: By this order, The Pipeline and Hazardous Materials Safety Administration (PHMSA) grants this special permit to the Kern River Gas Transmission Company (Kern River) subject to the conditions and limitations set forth below. This special permit waives compliance from 49 CFR §$ 192.111, 192.201, 192.505 and 192.619 for the 1,380-mile Kern River pipeline system. For the purposes of this special permit, the Kern River pipeline system means pipeline facilities beginning at the discharges of the Muddy Creek and Painter compressor stations, and at the Anschutz meter in Lincoln County, WY, to the outlet side of the Daggett meter station in San Bernardino County, CA to the mainline. The Kern River pipeline system consists of 682 miles of a 36-inch diameter mainline, 635 miles of 36-inch diameter loop lines, 10 compressor stations, 48 meter stations, 6 receipt laterals, and 7 delivery laterals. The Federal pipeline safety regulations in § 192.111 limit the design factors' for steel natural gas transmission pipelines for Class locations 1, 2 and 3 to the values in the following table: Class Maximum Location Design Class Maximum Class Maximum Factor Location Design Factor Location Design General 1 Factor 0.72 2 0.60 3 0.50 Un-cased road 0.60 2 0.50 3 crossings 0.50 Fabricated Assembly 1 0.60 2 0.60 3 0.50 Supported on Bridge 1 0.60 2 0.60 3 0.50 Stations 1 0.50 2 0.50 3 0.50 Pecied ministim yiche rength iS of tine pipe for examine. a rain pres or 102 were lame ore pipelin essure to a value that results in a hoop stress level of 72% SMY. <<>> 2 This special permit allows Kern River to raise the maximum allowable operating pressure (MAOP) of the Kern River pipeline system from 1200 pounds per square inch gauge (psig) to 1333 psig in the mainline and loop lines and to 1350 psig in the compressor station pipe. Accordingly, this special permit allows Ker River to operate the Kern River pipeline in Class locations 1, 2 and 3 using the design factors in the following table: Class Maximum Location Design Class Maximum Design Class Maximum Factor Location Factor Location Design Factor General 1 0.80 2 0.67 3 0.56 Un-cased road 1 0.67 2 0.56 3 crossings 0.56 Fabricated 1 Assembly 0.67 2 0.67 3 0.56 Supported on Bridge 1 0.67 2 0.67 3 0.56 Stations 1 0.56 2 0.56 3 0.56 Because the proposed operating stress level of 80% specified minimum yield strength (SMYS) is higher than the upper limit of the required overpressure protection under the existing Federal pipeline safety regulations [i.e. 10% over MAOP or 75% SMYS], this special permit also allows Kern River to design, install and operate pressure relief and limiting devices on the applicable segment of the Kern River pipeline with a capacity that would ensure the pressure in Class locations 1, 2 and 3 pipeline segments would not exceed 104% of the MAOP or the pressure that produces a hoop stress of 83.2% SMYS in Class 1 locations, 69.7% SMYS in Class 2 locations or 58.2% SMYS in Class 3 locations in the event an overpressure situation develops. This special permit also waives the strength test requirements in § 192.505 and the MAOP regulations in § 192.619, which allows Kern River to raise the MAOP of the applicable segment of the Kern River pipeline from 1202 psig to 1336 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 sections along the applicable segment of the Kern River pipeline that will operate above 72% SMYS in Class 1 locations, 60% SMYS in Class 2 ' There are currently no class 4 locations on the Kern River Transmission Company Pipeline System. This special permit does not apply to any future class 4 locations on the Kern River Transmission Company Pipeline System. <<>> locations or 50% SMYS in Class 3 locations. 3 : PHMSA grants this special permit based on the findings set forth in the "Special Permit Analysis and Findings" document, which can be read in its entirety in Docket No. PHMSA-2007-29078 in the Federal Docket Management System (FDMS) located on the Internet at www.Regulations.gov. Conditions: PHMSA grants this special permit subject to the following conditions: Steel Properties: The skelp/plate must be micro alloyed, fine grain, fully killed steel with calcium treatment and continuous casting. 2) Manufacturing Standards: New pipe segments or replacement pipe must be manufactured according to American Petroleum Institute Specification SL, Specification for Line Pipe (API 5L), 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 0.25% based on the material chemistry parameter (Pcm) formula or 0.43% based on the C-IIW formula. 3) Fracture Control: API SL, 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. Kern River must institute an overall fracture control plan addressing the steel pipe properties necessary to resist crack initiation and crack propagation and to arrest a fracture within 8 pipe joints with a 99% occurrence probability or within 5 pipe joints with a 90% occurrence probability. The plan must include acceptable Charpy Impact 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 5A - Fracture Toughness Testing for Shear Area: Test results must indicate at least 85% minimum average shear area for all X- 70 heats and 80% minimum shear area for all X- 80 heats with a minimum result of 80% 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 for All New Pipeline Segments or Pipe Replacements: Test results must be at least 80% of the average shear area for all heats with a minimum result of 60% 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, Kern River 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 for All New Pipeline Segments or Pipe Replacements: 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 ultrasonic testing (UT) inspection program to check for imperfections such as laminations. UT inspection must be conducted on all factory beveled pipe ends. In addition, pipe body UT inspection must be conducted on a minimum of 100% of pipe joints and all ends, with a minimum coverage of 35% of the pipe body for those joints inspected. Any laminations identified by the UT inspection program must be evaluated in accordance with the acceptance criteria defined in ASTM International Standard ASTM A578/A578M "Standard Specification for Straight-Beam Ultrasonic Examination of Rolled Steel Plates for Special Applications (ASTM A578)," Level B or API 5L Paragraph 7.8.10. 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. Pipe Seam Quality Control for All New Pipeline Segments or Pipe Replacements: 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 5 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 3 readings for each heat affected zone, 3 readings in the weld metal and 2 readings in each section of pipe base metal for a total of 13 readings. The pipe weld seam must be 100% UT inspected after expansion and hydrostatic testing per API 5L. 6) Mill Hydrostatic Test for All New Pipeline Segments or Pipe Replacements: The pipe must be subjected to a mill hydrostatic test to achieve a minimum stress level of 95% SMYS in the pipe for a minimum duration of 10 seconds. The 95% stress level may be achieved using a combination of internal test pressure and the application of end loads imposed by the hydrostatic testing equipment as allowed by API 5L, Appendix K 7) Pipe Coating for All New Pipeline Segments or Pipe Replacements: 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. The pipe for existing pipeline segments, new pipeline segments and/or replacements must be protected against external corrosion by a non-shielding coating. Field Coating for All New Pipeline Segments or Pipe Replacements: 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. Field Coating: The coatings on existing girth weld joints must be non-shielding to CP. 10) Coatings for Trenchless Installation for All New Pipeline Segments or Pipe Replacements: 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. 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) Design Factor - Pipelines: Pipe installed under this special permit in Class 1 location may use a design factor of 0.80, in Class 2 locations may use a design factor of 0.67 and in Class 3 locations may use a design factor of 0.56. Road crossings in Class 1 and 2 locations may use a design factor of 0.67 and 0.56, respectively. New road crossings, railroad crossings and fabricated assemblies must be designed using the existing design factors in § 192.111(b) and (c). 13) 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 factor as the adjacent pipe. 14) 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 Kern River's technical coating operating tests show that the pipe coating will properly withstand the higher operating temperature for long term operations. If the temperature exceeds 120° Fahrenheit, Kern River must also institute a coating monitoring program in these areas using ongoing Direct Current Voltage Gradient (DCVG) surveys or Alternating Current Voltage Gradient (ACVG) surveys or other testing to demonstrate the integrity of the coating. This program and results must be provided to the Director, PHMSA Western Region at least 60 days prior to implementation of the increased temperature or special permit operations. 15) Overpressure Protection Control: Mainline pipeline overpressure protection must be limited to a maximum of 104% MAOP. 16) Welding Procedures for All New Pipeline Segments or Pipe Replacements: For automatic or mechanized welding the 19' Edition of API 1104, "Welding of Pipelines and Related Facilities", will be used for welding procedure qualification, welder qualification and weld acceptance criteria. Operator will use the 19th Edition of API 1104 for all other welding processes. The Director, PHMSA Western Region must be notified at least 14 days prior to the beginning of any welding procedure qualification activities. Automated or manual welding procedure documentation must be submitted to the same PHMSA regional office. 17) 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 <<>> 7 the pipeline. If routine patrols or other observed conditions indicate the possible loss of cover over the pipeline, Kern River will perform a depth of cover study and replace cover as necessary to meet the minimum depth of cover requirements specified herein. If replacing cover is not practical, the Director, PHMSA Western Region may agree to an alternate plan to assure safety in these areas. 18) Construction Quality for All New Pipeline Segments or Pipe Replacements: 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 by radiography or alternative means. The NDE examiner must have all required and current certifications. 19) 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 by notifying the appropriate regional office. 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. 20) Test Level for All New Pipeline Segments or Pipe Replacements: The pre-in service hydrostatic test must be to a pressure producing a hoop stress of at least 100% SMYS and 1.25 X MAOP in areas to operate to 80% SMYS, at least 1.50 X MAOP in areas to operate up to 67% SMYS, and at least 1.50 X MAOP in areas to operate up to 56% SMYS. 21) Uprating Existing Pipeline Segments: Kern River must meet one of the following criteria in Condition 21 (a), (b), or (c), prior to uprating any existing pipeline segment in the special permit area to an MAOP above 72% SMYS in Class 1 locations, 60% SMYS in Class 2 locations or 50% SMYS in Class 3 locations: a) Hydrostatic Tests: Class 1, 2, and 3 locations in the special permit area must have been hydrostatically tested prior to the grant of this special permit as follows: 1) Class 1 and Class 2 locations containing a high consequence area (HCA) per 49 CFR Part 192, Subpart O - the pipeline segment must be hydrostatically pressure tested to at least 1.25 X MAOP. <<>> 2) Class 3 locations - the hydrostatic test pressure must be a minimum of 1.40 x 8 MAOP. 3) Whenever a change in class location has occurred anywhere within the special permit area prior to uprating the existing pipeline segment (e.g. Class 1 to 2 or Class 2 to 3), the class change location must meet the hydrostatic test and repair requirements of Conditions 43, 51 and 52. b) Overpressure Protection: Class 1, Class 2 and Class 3 locations - in lieu of hydrostatically pressure testing a pipeline segment in accordance with Condition 21 a) above, Kern River may operate the pipeline segment taking into account the pressure gradient provided they install protection against accidental overpressure in accordance with the existing requirements in $$192.195, 192.199, and 192.201. c) Pressure Gradient Monitoring: Class 1, Class 2 and Class 3 locations - in lieu of hydrostatically pressure testing a pipeline segment in accordance with Condition 21 (a) and installing overpressure protection in accordance with Condition 21 (b) above, Kern River may operate the pipeline segment taking into account the pipeline pressure gradient provided they install overpressure protection and use operating procedures designed to prevent accidental overpressure of the pipeline in accordance with the following requirements: 1) The written operating procedures must include pressure gradient monitoring along the pipeline at mainline valves as operating conditions change with updated gas flow models, 2) Two operational pressure sensors must be installed at each mainline valve upstream of pipeline segments that do not meet the criteria of Conditions 21 (a) and (b) above, and must be tied into the SCADA system and set-up to limit and control compressor discharge pressures based upon the gas flow gradient model and pressure of the gas along the pipeline so as not to exceed the limits of Conditions 21 (a) and b), 3) A review and training of written operating procedures and gas gradient flow models must be conducted with gas controllers responsible for these operating procedures at least once each calendar quarter, 4) Pressure sensors must be calibrated once each calendar year at intervals not to exceed 15 months, and 5) Whenever a change in class location has occurred anywhere within the special permit area prior to the grant of this special permit (e.g. Class 1 to 2 or Class 2 to 3), the class change location must meet the requirements of Conditions 43 and 52 of this <<>> special permit. 9 22) Assessment of Test Failures: Any pipe failure occurring during a pre-in service hydrostatic test or a hydrostatic test of an existing pipeline segment 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 to the Director, PHMSA Western Region. 23) Supervisory Control and Data Acquisition (SCADA) System Capabilities: A SCADA system to provide remote monitoring and control of the pipeline system must be employed. 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 via the SCADA system. The SCADA system must be capable of closing these mainline valves and monitoring the valve position, as well as upstream pressure and downstream pressure at the mainline valve. As an alternative, a leak detection system for mainline valve control is acceptable. 26) Pipeline Inspection: The pipeline must be capable of passing in-line inspection (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 (1.0 grain per 100 standard cubic feet or 16 parts per million (ppm), maximum); b) CO2 (3% 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. 28) The pipeline must have an ongoing pigging and liquids sampling plan to identify, mitigate and remove deleterious constituents, where applicable. 29) If H¿S is above 8 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. 30) Gas Quality Control: Separators or filters/separators must be installed at locations where gas is received into the pipeline where the incoming gas stream quality includes potentially <<>> deleterious free liquids and/or particulates to minimize the entry of contaminants and to 10 protect the integrity of downstream pipeline segments. 31) Gas Quality Monitoring Equipment: Equipment, including moisture analyzer, chromatograph and semi-annual HaS sampling (quarterly sampling where HaS is above 8 ppm), must be installed to permit the operator to manage and limit the introduction of contaminants and free liquids into the pipeline. 32) Interference Current Surveys: Interference surveys must be performed before increasing the pressure above the existing MAOP to ensure compliance with applicable NACE International Standard Practices 0169 and 0177 (NACE SP 0169 and NACE SP 0177) for interference current levels. If interference currents are found, Kern River will determine if there have been any adverse effects to the pipeline and mitigate the effects as necessary. Kern River will report the results of any negative finding and the associated mitigative efforts to the Director, PHMSA Western Region. 33) Verification of Cathodic Protection: An interrupted close interval survey (CIS) must be performed in concert and integrated with ILI in accordance with 49 CFR Part 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 Part 192, Subpart I requirements, remedial actions must occur within six months. Remedial actions must include a CIS on each side of the affected test station and all modifications to the CP system necessary to ensure adequate external corrosion control. If one-half mile spacing between test stations is not practical, the PHMSA Regional Director of the Western Region may agree to an alternate plan to verify cathodic protection in these areas. 34) Initial Close Interval Survey (CIS) - Initial: Kern River must have performed a CIS on the pipeline in the special permit area within the two years immediately prior to the increase in operating pressure above the existing MAOP or a CIS must be completed within one year after the pressure increase. The CIS results must be integrated with the ILI results to determine whether any further action is needed. 35) Coating Assessment: To verify the pipeline coating conditions and to remediate any integrity issues, Kern River must perform a DCVG survey or an ACVG survey of the following not later than one year after the grant of this special permit. a) all piping in the special permit area that has operated above 120 degrees Fahrenheit, b) all Class 1 locations with structures within 300 feet of the pipeline, c) all Class 2 and all Class 3 locations; and <<>> d) all HCAs. 11 A DCVG or ACG survey and remediation need not be performed if Kern River has performed a DCVG or ACG and remediation survey of the above, and completed the remediation of any integrity issue within the two years prior to the grant of this special permit. Kern River must remediate any damaged coating indications found during these assessments that are classified as moderate (i.e. 15% IR and above for DCVG or 35 dBuV and above for ACVG) or severe based on NACE International Recommended Practice 0502-2002, Pipeline External Corrosion Direct Assessment Methodology, (NACE RP 0502-2002). A minimum of two coating survey assessment classifications must be excavated, classified and/or remediated per each survey crew and compressor station discharge section. If factors beyond Kern River's control prevent the completion of the DCVG or ACVG survey and remediation within one year, a DCVG or ACG survey and remediation must be performed as soon as practicable and a letter justifying the delay and providing the anticipated date of completion must be submitted to the Director, PHMSA Western Region not later than one year after the grant of this special permit. 36) Pipeline Markers: Kern River 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. 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: Kern River must have performed an initial ILI inspection of the pipeline in the special permit area within the three years immediately prior to the increase in operating pressure above the existing MAOP or the two years immediately after the increase in pressure using a high-resolution magnetic flux leakage (MFL) tool and a geometry tool. The results of the initial ILI must be integrated with the initial CIS required per condition 34 above. Kern River must evaluate and repair all "Repair Immediately" and "Repair within One Year" anomalies (based on previous ILI inspections) in accordance with condition 43 below prior to increasing the pressure above the existing MAOP. <<>> 40) Future ILI: A second ILI using a high-resolution MFL must be completed on the 12 pipeline in the special permit area within the first reassessment interval required by 49 CFR Part 192, Subpart O, regardless of HCA classification. Future ILI must be performed on a frequency consistent with Subpart O on the pipeline in the special permit area. 41) Direct Assessment Plan: Headers, mainline valve bypasses and other sections in the special permit area that cannot accommodate IL - **truncated:** true - **body characters:** 54696