Pipeline and Hazardous Materials Safety Administration (PHMSA); DOT.
Notice; Grant of Waiver.
The Pipeline and Hazardous Materials Safety Administration (PHMSA) is granting Kinder Morgan Louisiana Pipeline, LLC (KMLP) a waiver of compliance from the Federal pipeline safety regulations for a new natural gas transmission pipeline. The regulations establish the maximum stress level and overpressure protection limits for natural gas pipelines.Start Further Info
FOR FURTHER INFORMATION CONTACT:End Further Info End Preamble Start Supplemental Information
Pipeline Operator: Kinder Morgan Louisiana Pipeline, LLC (KMLP) petitioned PHMSA on August 2, 2006 for a waiver of compliance with the Federal pipeline safety regulations limiting the operating stress levels for Class 1 locations along the Leg 1 segment of the KMLP pipeline in Louisiana. This waiver would allow KMLP to operate a new natural gas transmission pipeline at a maximum allowable operating pressure (MAOP) corresponding to a pipe stress level up to 80 percent of the steel pipe's specified minimum yield strength (SMYS) in rural areas along the pipeline route. SMYS is defined as the level of stress where steel transitions from elastic to plastic deformation. The current maximum SMYS level allowed on pipelines in Class 1 locations is 72 percent according to 49 CFR 192.111. Because the proposed operating stress level of 80 percent is higher than the upper limit of the required overpressure protection under existing regulations (i.e., 10 percent over MAOP or 75 percent SMYS), KMLP proposes increasing the overpressure protection limit to 104 percent of the pipeline MAOP or 83 percent SMYS. The pipeline MAOP will be 1,440 psig.
On November 22, 2006 PHMSA published notice of this waiver request in the Federal Register (71 FR 67704) inviting interested persons to comment on the request. We did not receive any comments for or against this waiver request as a result of this notice. We also requested and received supplemental information from KMLP. The waiver request, Federal Register notice, supplemental information from KMLP, and all other pertinent documents are Start Printed Page 19758available for review in the DOT's Document Management System (DMS), Docket Number PHMSA-2006-25803.
On January 6, 2006 PHMSA issued a meeting notice and a call for papers in the Federal Register (71 FR 977) to seek public input on raising the MAOP on certain natural gas transmission pipelines. On March 21, 2006 PHMSA conducted a public meeting where subject matter experts from across the U.S. and other countries presented papers describing technical issues and experiences with operating pipelines above 72 percent SMYS. After receiving favorable public responses and comments from the meeting, PHMSA began developing criteria for the design and operation of pipelines above 72 percent SMYS.
PHMSA previously issued three waivers allowing operators to operate natural gas transmission pipelines above 72 percent SMYS. The waivers were granted with conditions that require operators to meet certain specified safety criteria. The safety criteria were developed from information received from the public meeting, industry best practices and internal research. KMLP used information gathered from these prior waiver grants along with internal procedures to develop its waiver petition.
PHMSA concludes that granting a waiver to KMLP is not inconsistent with pipeline safety and achieves a level of safety equal to or better than a similar pipeline designed and operated under existing regulations. The analysis concluded the following:
(1) KMLP's waiver application describes actions for the proposed pipeline life cycle addressing pipe and material quality, construction quality control, pre-in service strength testing, the Supervisory Control and Data Acquisition (SCADA) System, operations and maintenance and integrity management. The aggregate affect of these actions provides for more inspections and oversight than would occur on a pipeline installed under existing regulations.
(2) The actions proposed in KMLP's waiver application are consistent with prior waiver grants.
(3) The safety criteria contained in this waiver grant requires KMLP to more closely inspect and monitor this pipeline than a similar pipeline installed without a waiver.
PHMSA grants a waiver of compliance with §§ 192.111 and 192.201(a)(2)(i) to Kinder Morgan Louisiana Pipeline, LLC for Class 1 locations along the Leg 1 segment of the KMLP pipeline. The Leg 1 segment is a 137-mile, 42-inch pipeline, originating at the Sabine Pass Liquefied Natural Gas (LNG) terminal and extending to Evangeline Parish, Louisiana. Approximately 92 percent of the Leg 1 segment is located in Class 1 locations. For the purpose of this waiver, the waiver area is defined as the pipeline right-of-way for the Class 1 locations along the entire 137-mile Leg 1 segment of the KMLP pipeline.
This waiver is granted with the following conditions:
(1) Steel Properties: The skelp/plate must be micro alloyed, fine grain, fully killed steel with calcium treatment and continuous casting.
(2) Manufacturing Standards: The pipe must be manufactured according to American Petroleum Institute Specification 5L (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 percent based on the material chemistry parameter (Pcm) formula.
(3) Fracture Control: API 5L, the American Society of Mechanical Engineers B31.8 Standard (ASME B31.8) and other specifications and standards address the steel pipe toughness properties needed to resist crack initiation, crack propagation and to ensure crack arrest during a pipeline failure caused by a fracture. KMLP must institute an overall fracture control plan addressing steel pipe properties necessary to resist crack initiation and crack propagation and to arrest a fracture within eight pipe joints with a 99 percent occurrence probability or within five pipe joints with a 90 percent occurrence probability. The plan must include acceptable Charpy Impact and Drop Weight Tear Test values, which are measures of a steel pipeline's toughness and resistance to fracture. The fracture control plan, which must be submitted to PHMSA Headquarters, must be in accordance with API 5L, Appendix F and must include the following tests:
(a) SR 5A-Fracture Toughness Testing for Shear Area: Test results must indicate at least 85 percent minimum average shear area for all X-70 heats and 80 percent minimum shear area for all X-80 heats with a minimum result of 80 percent shear area for any single test and must ensure ductile fracture and arrest;
(b) SR 5B-Fracture Toughness Testing for Absorbed Energy; and
(c) SR 6-Fracture Toughness Testing by Drop Weight Tear Test: Test results must be at least 80 percent of the average shear area for all heats with a minimum result of 60 percent of the shear area for any single test and must ensure a ductile fracture.
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 waiver 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 of the pipe in the waiver area does not meet these specifications, KMLP 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 waiver area.
(4) Steel Plate Quality Control: The steel mill and/or pipe rolling mill must incorporate a comprehensive plate/coil mill and pipe mill inspection program to check for defects and inclusions that could affect the pipe quality. This program must include a plate (body and all ends) ultrasonic testing (UT) inspection program to check for imperfections such as laminations. An inspection protocol for centerline segregation evaluation using a test method referred to as slab macro-etching must be employed to check for inclusions that may form as the steel plate cools after it has been cast. A minimum of one macro-etch test must be performed from the first 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 five are acceptable.
(5) Pipe Seam Quality Control: A quality assurance program must be instituted for pipe weld seams. The pipe weld seam tests must meet the minimum requirements for tensile strength in API 5L for the appropriate pipe grade properties. A pipe weld seam hardness test using the Vickers hardness testing of a cross-section from the weld seam must be performed on one length Start Printed Page 19759of pipe from each heat. The weld seam and heat affected zone hardness must be a maximum of 280 Vickers hardness. The hardness tests must include a minimum of three readings for each heat affected zone, three readings in the weld metal and two readings in each section of pipe base metal for a total of 13 readings. The pipe weld seam must be 100 percent UT inspected after expansion and hydrostatic testing per APL 5L.
(6) Puncture Resistance: Steel pipe must be puncture resistant to 65 tons. Puncture resistance will be calculated based on industry established calculations such as the Pipeline Research Council International's “Reliability Based Prevention of Mechanical Damage to Pipelines” calculation method.
(7) Mill Hydrostatic Test: The pipe must be subjected to a mill hydrostatic test pressure of 95 percent SMYS or greater for 10 seconds.
(8) Pipe Coating: The application of a corrosion resistant coating to the steel pipe must be subject to a coating application quality control program. The program must address pipe surface cleanliness standards, blast cleaning, application temperature control, adhesion, cathodic disbondment, moisture permeation, bending, minimum coating thickness, coating imperfections and coating repair.
(9) Field Coating: A field girth weld joint coating application specification and quality standards to ensure pipe surface cleanliness, application temperature control, adhesion quality, cathodic disbondment, moisture permeation, bending, minimum coating thickness, holiday detection and repair quality must be implemented in field conditions. Field joint coatings must be non-shielding to cathodic protection (CP). Field coating applicators must use valid coating procedures and be trained to use these procedures.
(10) Coatings for Trenchless Installation: Coatings used for directional bore, slick bore and other trenchless installation methods must resist abrasions and other damages that may occur due to rocks and other obstructions encountered in this installation technique.
(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 prior to welding for CE above 0.42.
(12) Fittings: All pressure rated fittings and components (including flanges, valves, gaskets, pressure vessels and compressors) must be rated for a pressure rating commensurate with the MAOP and class location of the pipeline. Designed fittings (including tees, elbows and caps) must have the same design factors as the adjacent pipe class location.
(13) Design Factor—Stations: Compressor and meter stations must be designed using a design factor of 0.50 in accordance with § 192.111.
(14) Temperature Control: The compressor station discharge temperature must not exceed 120° Fahrenheit or a temperature below the maximum long-term operating temperature for the pipe coating.
(15) Overpressure Protection Control: Mainline pipeline overpressure protection must not exceed 104 percent MAOP.
(16) Welding Procedures: The appropriate PHMSA regional office must be notified within 14 days of the beginning of welding procedure qualification activities. Automated or manual welding procedure documentation must be submitted to the same PHMSA regional office.
(17) Depth of Cover: The soil cover must be a minimum 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 the pipeline. If a routine patrol or other observed conditions indicate the possible loss of cover over the pipeline, KMLP must perform a depth of cover study and replace cover as necessary to meet the minimum depth of cover requirements specified herein.
(18) Construction Quality: A construction quality assurance plan to ensure quality standards and controls must be maintained throughout the construction phase for inspection, pipe hauling and stringing, field bending, welding, non-destructive examination (NDE) of girth welds, field joint coating, pipeline coating integrity tests, lowering of the pipeline in the ditch, padding materials to protect the pipeline, backfilling, alternating current (AC) interference mitigation and CP systems. All girth welds must be non-destructively examined (NDE) by radiography or alternative means. The NDE examiner must have all required certifications which must be current.
(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 Headquarters' attention. An induced AC program to protect the pipeline from corrosion caused by stray currents must be in place within six months after placing the pipeline in service.
(20) Test Level: The pre-in service hydrostatic test pressure on 0.8 designed Class 1 location pipe must be equal to or greater than 125 percent of the MAOP and produce a hoop stress of at least 100 percent SMYS.
(21) Assessment of Test Failures: Any pipe failure occurring during the pre-in service hydrostatic test must undergo a root cause failure analysis to include a metallurgical examination of the failed pipe. The results of this examination must preclude a systemic pipeline material issue and the results must be reported to PHMSA Headquarters and the appropriate PHMSA regional office.
(22) SCADA System Capabilities: A SCADA system to provide remote monitoring and control of the entire pipeline system must be employed.
(23) 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.
(24) Mainline Valve Control: Mainline valves located on either side of a pipeline segment containing a High Consequence Area (HCA) where personnel response time to the valve exceeds one hour must be remotely controlled by the SCADA system. The SCADA system must be capable of opening and closing the valve and monitoring the valve position, upstream pressure and downstream pressure. As an alternative, a leak detection system for mainline valve control is acceptable.
(25) Leak Reporting: KMLP must notify the appropriate PHMSA regional office within 24 hours of any non-reportable leaks occurring on the pipeline.
(26) Annual Reporting: Following approval of the waiver, KMLP must annually report the following:
(a) The results of any in-line inspection (ILI) and the results of any direct assessment performed within the waiver area during the previous year;
(b) Any new integrity threats identified within the waiver area during the previous year;
(c) Any encroachment in the waiver area, including the number of new residences or public gathering areas;
(d) Any class or HCA changes in the waiver area during the previous year;
(e) Any reportable incidents associated with the waiver area that occurred during the previous year;Start Printed Page 19760
(f) Any leaks on the pipeline in the waiver area that occurred during the previous year;
(g) A list of all repairs on the pipeline in the waiver area made during the previous year;
(h) On-going damage prevention initiatives on the pipeline in the waiver area and a discussion of their success or failure;
(i) Any changes in procedures used to assess and/or monitor the pipeline operating under this waiver; and
(j) Any company mergers, acquisitions, transfers of assets, or other events affecting the regulatory responsibility of the company operating the pipeline to which this waiver applies.
(27) Pipeline Inspection: The pipeline must be capable of passing ILI tools. All headers and other segments covered under this waiver that do not allow the passage of an ILI device must have a corrosion mitigation plan.
(28) Gas Quality Monitoring: Gas quality monitoring equipment must be installed to permit the operator to manage and limit the introduction of contaminants and free liquids into the pipeline. An acceptable gas quality monitoring and mitigation program must be instituted to not exceed the following limits:
(a) H2 S (0.25 grains per 100 standard cubic feet or 4 parts per million, maximum);
(b) CO2 (3 percent maximum);
(c) H2 O (less than or equal to 7 pounds per million standard cubic feet and no free water); and
(d) Other deleterious constituents that may impact the integrity of the pipeline must be instituted.
(29) Gas Quality Control: Filters/separators must be installed at locations where gas is received into the pipeline where the incoming gas stream quality includes potentially deleterious constituents to minimize the entry of contaminants and to protect the integrity of downstream pipeline segments.
(30) Cathodic Protection: The initial CP system must be operational within 12 months of placing the pipeline in service.
(31) Interference Current Surveys: Interference surveys must be performed within six months of placing the pipeline in service to ensure compliance with applicable NACE International Standard Recommended Practices 0169 and 0177 (NACE RP 0169 and NACE RP 0177) for interference current levels. If interference currents are found, KMLP will determine if there have been any adverse effects to the pipeline and mitigate the effects as necessary. KMLP will report to PHMSA the results of any negative finding and the associated mitigative efforts.
(32) Corrosion Surveys: Corrosion surveys of the affected pipeline must be completed within six months of placing the respective CP system(s) in operation to ensure adequate external corrosion protection per NACE RP 0169. The survey must also address the proper number and location of CP test stations as well as AC interference mitigation and AC grounding programs per NACE RP 0177.
(33) Verification of Cathodic Protection: An interrupted close interval survey (CIS) must be performed in concert with ILI for all HCA pipeline mileage in accordance with 49 CFR 192 Subpart O reassessment intervals. At least one CP test station must be located within each HCA with a maximum spacing between test stations of one-half mile within an HCA. If any annual test station reading fails to meet 49 CFR 192 Subpart I requirements, remedial actions must occur within six months. Remedial actions must include a CIS on each side of the affected test station and all modifications to the CP system necessary to ensure adequate external corrosion control.
(34) Pipeline Markers: KMLP must employ line-of-sight markings on the pipeline in the waiver area except in agricultural areas or large water crossings such as lakes where line of sight signage is not practical. The marking of pipelines is also subject to Federal Energy Regulatory Commission orders or environmental permits and local restrictions.
(35) Pipeline Patrolling: Pipeline patrolling must be conducted at least monthly to inspect for excavation activities, ground movement, wash-outs, leakage or other activities and conditions affecting the safe operation of the pipeline.
(36) 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.
(37) Review of Risk Assessment Calculations: A copy of the C-FER PIRAMID risk analysis report regarding the pipe subject to this waiver must be submitted to PHMSA Headquarters.
(38) Initial ILI: KMLP must perform a baseline ILI in association with the construction of the pipeline using a high-resolution Magnetic Flux Leakage (MFL) tool to be completed within three years of placing the pipeline in service. KMLP must also run a geometry tool after the backfill of the pipeline and after the dewatering from the hydrostatic strength test but not later than six months after placing the pipeline in service.
(39) Future ILI: A second high-resolution MFL inspection must be performed and completed on the pipe subject to this waiver within the first reassessment interval required by 49 CFR Subpart O, regardless of HCA classification. Future ILI must be performed on a frequency consistent with Subpart O for the entire pipeline covered by this waiver.
(40) Direct Assessment Plan: Headers, mainline valve bypasses and other sections covered by this waiver that cannot accommodate ILI tools must be part of a Direct Assessment (DA) plan or other acceptable integrity monitoring method.
(41) Initial CIS: A CIS must be performed on the pipeline within two years of the pipeline in-service date. The CIS results must be integrated with the baseline ILI to determine whether further action is needed.
(42) Damage Prevention Program: The Common Ground Alliance's damage prevention best practices must be incorporated into the KMLP damage prevention program.
(43) Class 2 and 3 Pipe: Pipe installed in Class 2 and Class 3 locations must use stress factors of 0.60 and 0.50 as required in § 192.111. Pipe in road and railroad crossings must meet the requirements of § 192.111. Future class changes must meet the requirements of §§ 192.609 and 192.611.
(44) Anomaly Evaluation and Repair: Anomaly evaluations and repairs must be performed based upon the following:
(a) Anomaly Response Time
—Any waiver area anomaly with a failure pressure ratio (FPR) equal to or less than 1.1 must be treated as an “immediate repair condition” per 49 CFR 192, Subpart O.
—Any waiver area anomaly with a FPR equal to or less than 1.25 must be repaired within 12 months.
(b) Anomaly Repair Criteria
—All other pipe segments with anomalies not repaired must be reassessed according to Subpart O and ASME B31.8S requirements and class location factor. Each anomaly not repaired, as an immediate repair, must have a corrosion growth rate and ILI tool tolerance assigned to it per the Gas Integrity Management Program (IMP) to determine the maximum re-inspection interval.
—KMLP must confirm the remaining strength (R-STRENG) effective area method, R-STRENG-0.85dL, and ASME B31G assessment methods are valid for the pipe diameter, wall thickness, grade, operating Start Printed Page 19761pressure, operating stress level and operating temperature. KMLP must also use the most conservative method until confirmation of the proper method is made to PHMSA Headquarters.
(45) Preliminary Report: A preliminary report describing the results, completion dates and status of the waiver conditions must be completed for the pipeline and submitted to PHMSA Headquarters and the appropriate PHMSA regional office prior to commencing construction of the pipeline.
(46) Completion Report: A completion report describing the results, completion dates and status of the outstanding waiver conditions must be submitted to PHMSA Headquarters and the appropriate regional office within 180 days after completion of the pipeline.
(47) ILI Reports: A report must be submitted for the pipeline after the baseline ILI (MFL and Geometry) run has been performed with assessment and integration of the results. A report must also be submitted upon completion of the second ILI run. These reports must be submitted to PHMSA Headquarters and the appropriate PHMSA regional office.
(48) Potential Impact Radius Calculation Updates: If the pipeline operating pressures and gas quality are determined to be outside the parameters of the C-FER Study, a revised study with the updated parameters must be incorporated into the IMP.
Should KMLP fail to comply with any conditions of the wavier, or should PHMSA determine this waiver is no longer appropriate or that the waiver is inconsistent with pipeline safety, PHMSA may revoke this waiver and require KMLP to comply with regulatory requirements of §§ 192.111 and 192.201(a)(2)(i).Start Signature
Issued in Washington, DC on April 13, 2007.
Jeffrey D. Wiese,
Acting Associate Administrator for Pipeline Safety.
[FR Doc. E7-7414 Filed 4-18-07; 8:45 am]
BILLING CODE 4910-60-P