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Home My WebLink AboutAIO 016AREA INJECTION ORDER NO. 16 Tarn Oil Pool Kuparuk River Field 1. February 18, 1998 ARCO’s application 2. March 9, 1998 ARCO’s follow-up letter regarding application 3. March 25, 1998 Maps 4. March 28, 1998 Notice of Public Hearing, Affidavit of Publication 5. April 27, 1998 ARCO’s application for AEO 6. April 28, 1998 Copy of Tarn’s testimony for Pool Rules 7. April 28, 1998 Transcript 8. September 27, 2004 Public Hearing Notice to Amend Underground Injection Orders to Incorporate Consistent Language Addressing the Mechanical Integrity of Wells 9. January 24, 2010 Administrative Approval to allow 2N-325 to be online in water only injection service with a known surface casing leak 10. December 12, 2011 Request to allow 2L-305 to be online in water only injection (AIO 16.002) 11. November 4, 2012 Request to allow 2L-319 to be online in water only injection (AIO 16.003) 12. May 8, 2013 - August 16, 2013 Amendment of Alternative MIT schedule for UIC injection Wells and background information 13. April 1, 2013 CPAI’s application for Administration Approval allowing well 2L-310 to be online in water only injection service (AIO 16.004) 14. October 30, 2015 CPAI’s application for Administration Approval allowing well 2L-323 to be online in water only injection service (AIO 16.005) 15. June 19, 2016 CPAI’s application for Administration Approval allowing well 2N-306 to be online in water only injection service (AIO 16.006) 16. March 26, 2016 – February 23, 2017 CPAI’s request to align the anniversary dates on AA’s with the current approved UIC testing schedule (AIO 16.001 Amended through AIO 16.005 Amended) 17. March 17, 2019 CPAI’s application for Administration Approval allowing well 2N-337C to be online in water only injection service (AIO 16.007) 18. April 9, 2019 CPAI’s application for Administration Approval to amend AIO 16.004 to change from water only injection to WAG (AIO 16.004 Amended) 19. July 6, 2022 CPAI’s application for Administration Approval to amend AIO 16.002 to change from water only injection to WAG (AIO 16.002 Amended) 20. July 7, 2022 CPAI’s application for Administration Approval to amend AIO 16.003 to change from water only injection to WAG (AIO 16.003 Amended) 21. August 2, 2022 Request to Amend Area Injection Order 16.006: Water Alternating Gas Injection Operations (AIO 16.006 Amended) 22. August 18, 2022 Request to Amend Area Injection Order 16.007: Water Alternating Gas Injection Operations (AIO 16.007 Amended) 23. November 11, 2024 CPAI request to amend AIO 16.004 amended allow WAG injection service without bleed criteria. (AIO 16.007 Amended Amended) 24. February 3, 2025 CPAI request to allow KRU injection well 2L-301 (PTD 208-192) to remain in water only injection service (AIO16.008) 25. January 15, 2025 AIO 7 Proposed language change (AIO 16.009) ORDERS I, ) ,), ) OR\G\NAL STATE OF ALASKA OIL AND GAS CONSERVATION COMMISSION 3001 Porcupine Drive Anchorage, Alaska 99501-3192 Re: The APPLICATION OF ARCO ALASKA, Inc. for an order allowing underground injection for purposes of waste disposal and enhanced oil recovery in the Tarn oil pool ) ) ) ) ) Tam Oil Pool Kuparuk River Field Area Injection Order No. 16 July 20, 1998 IT APPEARING THAT: 1. By correspondence dated February 18 and April 27, 1998, ARCO Alaska, Inc. ("AAI") requested authorization to inject fluids for purposes of waste disposal and enhanced oil recovery in the Tam oil pool. Meetings were also held at the Commission offices on February 3 and April 22, 1998, to discuss the proposed development. AAI submitted a final application dated April 27, 1998. 2. Notice of public hearing to be held on April 28, 1998 was published in the Anchorage Daily News on March 28, 1998. 3. A public hearing was held on Apri128, 1998, at which time AAI presented testimony concerning proposed underground injection in the Tam oil pool, and testimony to define the pool and establish rules for its development. FINDINGS: 1. Commission regulation 20 AAC 25.460 provides the Commission with authority to issue an order governing underground injection of fluids on an area basis for all wells within the same field, facility site, reservoir, project, or similar area. 2. The Tam oil pool is located immediately adjacent to the southwest comer of the Kuparuk River Unit on Alaska's North Slope. 3. AAI is the sole operator of all wells within one-quarter mile of the Tam oil pool area. The State of Alaska is the sole surface owner. 4. AAI currently anticipates drilling approximately 40 wells to develop the Tam oil pool. The scope of development may be expanded to encompass a larger area with additional wells depending on the results of delineation drilling. 5. AAI plans to begin enhanced oil recovery ("EOR") injection no later than six months after first production. EOR plans are to initially inject a large slug of miscible injectant ("MI") followed by a lean gas flush. Future EOR may include injecting foam, polymers or water. Initial development may not include a disposal well, but future need may reqUIre one. l. Area Injection Order No. ~.~ July 20, 1998 \ Page 2 6. Disposal injection, ifrequired, will occur into the Ivishak Sandstone of the Sadlerochit Group, which is wet in this area of the North Slope. 7. The Ivishak disposal zone in the Tam area appears to have at least 60 feet of sandstone with porosity greater than 15%, and can be defined in the Sinclair Colville #1 well at a depth of approximately 8500 feet subsea. 8. Approximately 1800 feet of shale in the Kingak Formation overlie the Ivishak Sandstone. 9. AAI does not intend to dispose of Class II fluids into the Ivishak Sandstone until it conducts adequate modeling of the process to establish appropriate operational constraints. 10. The Tam oil pool is composed of a sequence of discontinuous, generally low permeability sandstone and interbedded mudstone found in the interval between 4376 feet and 5990 feet measured depth ("MD") in the AAI Bermuda #1 well. Tarn oil pool sands are fine to very fine grained with shale laminations and interbeds. Reservoir sands are locally developed, generally lobate to linear in form, and separated from other reservoir sands by mudstone and shale. 11. The proposed casing program for Tam wells will be similar to that used in the Kuparuk River Unit. Conductor casing will be set below 75 feet. Either 9-5/8" or 7-5/8" surface casing will be set below the base of the West Sak Formation. Production casing will vary in size from 7" to 31h". ' 12. The mechanical integrity of injection wells will comply with the requirements specified in 20 AAC 25.412 prior to initiating injection operations. 13. The operator will comply with the requirements of 20 AAC 25.402 (d) & ( e) to monitor tubing-casing annulus pressures of injection wells periodically during injection operations to ensure there is no leakage and that casing pressure remains less than 70% of minimum yield strength of the casing. 14. All existing wells drilled within the proposed project area have been constructed in accordance with 20 AAC 25.030. All wells abandoned in the proposed project area have been abandoned in accordance with 20 AAC 25.105. 15. Simulation studies show injection of a relatively large slug (20% pore volume) ofMI followed by a lean gas flush is the most efficient recovery plan for the Tam oil pool, with a potential yield of 30% of the original oil in place. 16. Laboratory core floods using synthetic formation brines of the Tam reservoir indicate these lithologies are susceptible to formation damage related to fine migration when contacted with water. 17. The viscosity of water is generally too high to serve as an effective injectant in the Tam reservoir due to the reservoir's low permeability and discontinuous nature. 18. Aquifer support for Tam oil pool production is anticipated to be minimal. A I· . 0 d . :) rea nJcctlon r er No. 16 July 20, 1998 \ Page 3 19. The MI planned for Tam EOR will be the same as that used in the KRU's Large Scale Enhanced Oil Recovery Project. The MI is manufactured at CPF -lor CPF -2 by blending KRU lean gas with natural gas liquids from the Prudhoe Bay Unit. 20. Injection rates are expected to range between 30 to 50 MMSCFPD. Maximum MI injection pressures will be 4,400 psi. Wellhead pressures will vary, and are expected to range between 2,700 psi and 3,700 psi. 21. The high leak off coefficient and low viscosity associated with gas injectant precludes any possibility of propagating fractures significant distances into or above the Tarn oil pool. 22. There is no evidence from laboratory core flood experiments or compositional studies to indicate any compatibility problems between EOR fluids and either the Tarn formation or overlying confining strata. 23. The U. S. Environmental Protection Agency ('"EPA") exempted all aquifers lying 'l4 miles beyond and directly below the Kuparuk River Unit under 40 CFR 147.102 prior to the Commission taking primacy of UIC Class II operations in Alaska. The development area for the Tam reservoir lies within the Kuparuk River Unit aquifer exemption area approved by EP A. 24. AAI estimates the Tam oil pool holds about 136 million barrels of original oil in place ("OOIP"). Primary production is expected to recover 1 0% of OOIP in the Tam Oil Pool. 25. AAI estimates about 42 million barrels of oil ("MMBO") or about 31 % of OOIP will be recovered using proposed EOR methods. 26. Compositional analysis of crude oil from the Tam Oil Pool indicates 37 degree API gravity with a solution gas-oil ratio of 71 0 scf/stb based on analysis of recombined separator oil and gas. 27. The average Tam reservoir air permeability measured from conventional core in the AAI Tam #2 well is 9 millidarcies. CONCLUSIONS: 1. The application requirements of20 AAC 25.252 and 20 AAC 25.402 have been met. 2. An Area Injection Order is appropriate for the project area under 20 AAC 25.460. 3. The proposed injection operations will be conducted in permeable strata that can reasonably be expected to accept injected fluids at pressures less than the fracture pressure of the confining strata. 4. The proposed injection operations are for the purpose of enhanced recovery operations. 5. There is currently insufficient information upon which to grant approval for Class II disposal operations. \ Area Injection Order No. ...! July 20, 1998 \ Page 4 6. Well mechanical integrity is demonstrated by compliance with the requirements of 20 AAC 25.412 prior to initiation of injection operations. 7. The mechanical integrity of each injection well is ensured by a testing schedule of at least every four years after the initial test. 8. Weekly monitoring of tubing-casing annulus pressure and injection rates will disclose possible abnormalities in operational conditions. 9. An Area Injection Order for the project area will not cause waste nor jeopardize correlative rights and will improve ultimate recovery. NOW, THEREFORE, IT IS ORDERED THAT Area Injection Order No. 16 is issued for the Tam oil pool with the following rules governing Class II injection operations in the following affected area: UMIAT MERIDIAN T9N R7E Section 1,2, 3,4,5, 8, 9, 10, 11 and 12. T10N R7E Sections 13, 14, 15, 16,21,22,23,24,25,26,27,28,29,32,33,34,35, and 36. TION R8E Sections 18, 19,30 and 31. Rule 1 Authorized Injection Strata for Enhanced Recovery Within the affected area, fluids may be injected for purposes of pressure maintenance and enhanced recovery into strata defined as those which correlate with and are common to those found between the measured depths of 4376 feet and 5990 feet in the AAI Bermuda #1 well. Rule 2 Authorized Injection Strata for Disposal Class II disposal may not be conducted within the affected area until AAI conducts adequate process modeling to establish appropriate operational constraints and the commission has received sufficient information to authorize disposal. Rule 3 Fluid Injection Wells The underground injection of fluids must be through a well permitted for drilling as a service well for injection in conformance with 20 AAC 25.005 or through a well approved for conversion to a service well for injection in conformance with 20 AAC 25.280. Rule 4 Monitoring the Tubing-Casing Annulus Pressure Variations The tubing-casing annulus pressure and injection rate of each injection well must be checked at least weekly to ensure there is no leakage and that it does not exceed a pressure that will subject the casing to a hoop stress greater than 70% of the casing's minimum yield strength. Rule 5 Reporting the Tubing-Casing Annulus Pressure Variations Area Injection Order No. j July 20, 1998 J Page 5 Tubing-casing annulus pressure variations between consecutive observations need not be reported to the Commission unless accompanied by a greater than 10% increase in injection rate, indicating possible tubing and casing leaks. Rule 6 Demonstration of Tubing-Casing Annulus Mechanical Integrity A schedule must be developed and coordinated with the Commission that ensures that the tubing- casing annulus for each injection well is pressure tested prior to initiating injection, following well workovers affecting mechanical integrity and at least once every four years thereafter. A test surface pressure of 1500 psi or 0.25 psi/ft. multiplied by the vertical depth of the packer, whichever is greater, but not to exceed a hoop stress greater than 70% of the minimum yield strength of the casing to be used. The test pressure must show a decline of less than 10% in a thirty-minute period following thermal stabilization. The Commission must be notified at least twenty-four (24) hours in advance to enable a representative to witness pressure tests. Rule 7 Well Integrity Failure Whenever operating pressure observations or pressure tests indicate pressure communication or leakage of any casing, tubing or packer, the operator must notify the Commission on the first working day following the observation, obtain Commission approval of a plan for corrective action, and obtain Commission approval to continue injection Rule 8 Plugging and Abandonment of Injection Wells An injection well located within the affected area must not be plugged or abandoned unless approved by the Commission in accordance with 20 AAC 25.105. Rule 9 Tam Oil Pool Annual Reservoir Report An annual Tam Oil Pool surveillance report will be required by April 1 of each year subsequent to commencement of enhanced oil recovery operations. The report shall include but is not limited to the following: a. Progress of the enhanced recovery project and reservoir management summary including engineering and geological parameters. b. V oidage balance by month of produced fluids and injected fluids. c. Analysis of reservoir pressure surveys within the pool. d. Results and where appropriate, analysis of produced logging surveys, tracer surveys and observation well surveys. e. Results of any special monitoring. f. Evaluation of well testing and allocation. g. Future development plans. h. Review of Annual Plan of Operations and Development. Rule 10 Administrative Action Upon request, the Commission may administratively amend any rule stated above as long as the operator demonstrates to the Commission's satisfaction that sound engineering practices are maintained and the amendment will not result in an increased risk of fluid movement into an USDW. Area Injection Order NO.1 v ') July 20, 1998 ') Page 6 DONE at Anchorage, Alaska and dated July 20, 1998 ( \. f\ ~ ÛtJv£ Camil1é Oechsli, Commissioner Alaska Oil and Gas Conservation Commission AS 31.05.080 provides that within 20 days after receipt of written notice of the entry of an order, a person affected by it may file with the Commission an application for rehearing. A request for rehearing must be received by 4:30 PM on the 23rd day following the date of the order, or next working day if a holiday or weekend, to be timely filed. The Commission shall grant or refuse the application in whole or in part within 10 days. The Commission can refuse an application by not acting on it within the 10-day period. An affected person has 30 days from the date the Commission refuses the application or mails (or otherwise distributes) an order upon rehearing, both being the tìnal order of the Commission, to appeal the decision to Superior Court. Where a request for rehearing is denied by non action of the Commission, the 30-day period for appeal to Superior Court runs from the date on which the request is deemed denied (i.e., 10th day after the application for rehearing was tìled). • • 0 ~ a ~ SEAN PARNELL, GOVERNOR nl/t~-7~ OIL 1~1`il lI~~7 333 W. 7th AVENUE, SUITE 100 COI~TSERQA'1`IO1~T COMI~'IISSIOrT ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 FAX (907)276-7542 ADMINISTRATIVE APPROVAL AIO 16.001 Mr. Brent Rogers Problem Wells Supervisor ConocoPhillips Alaska, Inc. P.O. Box 100360 Anchorage, AK 99510-0360 RE: KRU 2N-325 (PTD 1981630) Request for Administrative Approval Tarn Oil Pool Dear Mr. Rodgers: In accordance with Rule 10 of Area Injection Order (AIO) 16.000, the Alaska Oil and Gas Conservation Commission (AOGCC or Commission) hereby grants ConocoPhillips Alaska Inc. (CPAI)'s request for administrative approval to continue water injection in the subject well. Well diagnostics confirm the well has a surface casing leak at a depth of 120 feet. CPAI does not propose to repair the well at this time however intends to continue to evaluate possible repairlremediation possibilities. Reported results of CPAI's diagnostic procedures and wellhead pressure trend plots indicate that KRU 2N-325 exhibits at least two competent barriers - tubing/packer and production casing - to the release of well pressure. As part of the diagnostic testing, the well passed the standard inner annulus pressure test. Accordingly, the Commission believes that the well's condition does not compromise overall well integrity so as to threaten human safety or the environment. AOGCC's administrative approval to continue water injection only in KRU 2N-325 is conditioned upon the following: 1. CPAI shall record wellhead pressures and injection rate daily; 2. CPAI shall submit to the AOGCC a monthly report of well pressures, injection rates, and pressure bleeds for all annuli; 3. CPAI shall limit the inner annulus pressure to 2000 psi and the outer annulus pressure as low as practicable; 4. CPAI shall perform a mechanical integrity test of the inner annulus every 2 years to the maximum anticipated injection pressure; AIO 16.001 • • February 3, 2010 Page 2 of 2 5. CPAI shall immediately shut in the well and notify the AOGCC if there is any change in the well's mechanical condition; 6. After well shut in due to a change in the well's mechanical condition, AOGCC approval shall be required to restart injection; and 7. The MIT anniversary date is December 30, 2009. DONE at Anchorage, Alaska and dated Febi ~ ~, ~ Cath P. Foerster Commissioner r"afi ~~~ ~ A a ~F ~ ~ ~ ~< 1, RECONSIDERATION AND APPEAL NOTICE As provided in AS 31.05.080(a), within 20 days after written notice of the entry of this order or decision, or such further time as the Commission grants for good cause shown, a person affected by it may file with the Commission an application for reconsideration of the matter determined by it. If the notice was mailed, then the period of time shall be 23 days. An application for reconsideration must set out the respect in which the order or decision is believed to be erroneous. The Commission shall grant or refuse the application for reconsideration in whole or in part within 10 days after it is filed. Failure to act on it within 10-days is a denial of reconsideration. If the Commission denies reconsideration, upon denial, this order or decision and the denial of reconsideration are FINAL and may be appealed to superior court. The appeal MUST be filed within 33 days after the date on which the Commission mails, OR 30 days if the Commission otherwise distributes, the order or decision denying reconsideration, UNLESS the denial is by inaction, in which case the appeal MUST be filed within 40 days after the date on which the application for reconsideration was filed. If the Commission gants an application for reconsideration, this order or decision does not become final. Rather, the order or decision on reconsideration will be the FINAL order or decision of the Commission, and it may be appealed to superior court. That appeal MUST be filed within 33 days after the date on which the Commission mails, OR 30 days if the Commission otherwise distributes, the order or decision on reconsideration. As provided in AS 31.05.080(b), "[t]he questions reviewed on appeal are limited to the. questions presented to the Commission by the application for reconsideration." In computing a period of time above, the date of the event or default after which the designated period begins to run is not included in the period; the last day of the period is included, unless it falls on a weekend or state holiday, in which event the period runs until 5:00 p.m. on the next day that does not fall on a weekend or state holiday. C;ommissloner • • a N PARNELL, GOVERNOR ALASKA OIL AND GAS 333 W. 7th AVENUE, SUITE 100 CONSERVATION COMMISSION ANCHORAGE, ALASKA 99501 -3539 PHONE (907) 279 -1433 FAX (907) 276 -7542 ADMINISTRATIVE APPROVAL AREA INJECTION ORDER 16.002 Ms. Kelly Lyons Problem Well Supervisor ConocoPhillips Alaska, Inc. P.O. Box 100360 Anchorage, AK 99510 -0360 RE: KRU 2L -305 (PTD 1982400) Request for Administrative Approval Tarn Oil Pool Dear Ms. Lyons: In accordance with Rule 9 of Area Injection Order ( "AIO ") 16.000, the Alaska Oil and Gas Conservation Commission ( "AOGCC" or "Commission ") hereby GRANTS ConocoPhillips Alaska Inc. ( "CPAI ")'s request for administrative approval to continue water injection in the subject well. Kuparuk River Unit ( "KRU ") 2L -305 exhibits inner annulus repressurization following pressure bleeds while on miscible gas injection. Possible communication was reported to the Commission on June 18, 2011. The Commission finds that CPAI does not intend to perform repairs at this time, deferring until MI injection is again desired in the well. Reported results of CPAI's diagnostic procedures (including positive and negative pressure tests) and wellhead pressure trend plots indicate that KRU 2L -305 exhibits at least two competent barriers to the release of well pressure. CPAI has theorized that the IA pressure is the result of miscible gas injection drying out the seals and packoffs in KRU 2L -305 although an exact leak location has not been determined. The burst rating for surface casing is a consideration in determining pressure limits and other conditions of approval. Restricting the well to water injection significantly reduces the injection pressure. Such a limitation mitigates some of the concerns about potential excessive pressures in the event communication develops to the outer annulus. Given the stable pressure history while injecting water and relatively low annulus pressure (compared to miscible gas injection), the Commission believes it unnecessary to require special engineering controls to assure ongoing integrity of the surface casing. AOGCC's administrative approval to continue water injection only in KRU 2L -305 is conditioned upon the following: 1. CPAI shall record wellhead pressures and injection rate daily; AIO 16.002 • • December 21, 2011 Page 2 of 2 2. CPAI shall submit to the AOGCC a monthly report of well pressures and injection rates, and shall flag the well's periodic pressure bleeds on the report; 3. CPAI shall perform an MIT -IA every 2 years to the maximum anticipated injection pressure; 4. CPAI shall limit the well's IA operating pressure to 2000 psi and the OA operating pressure to 1000 psi; 5. CPAI shall immediately shut in the well and notify the AOGCC if there is any change in the well's mechanical condition; 6. After well shut in due to a change in the well's mechanical condition, AOGCC approval shall be required to restart injection; and 7. In order to establish the MIT anniversary date, CPAI should schedule a witnesse - IA prior to January 31, 2012. OIL ANA DONE at Anchorage, Alaska and dates Decemb- 1 1, 2011. ('`— ,.ICA -,;, .14 / 41 "I 7 1 UN CO 4 \, Daniel T. eamount, Jr. J ► m. . y r. Foerster Chair, Commissioner Commi .IOC 'r Commissioner RECONSIDERATION AND APPEAL NOTICE As provided in AS 31.05.080(a), within 20 days after written notice of the entry of this order or decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration of the matter determined by it. If the notice was mailed, then the period of time shall be 23 days. An application for reconsideration must set out the respect in which the order or decision is believed to be erroneous. The AOGCC shall grant or refuse the application for reconsideration in whole or in part within 10 days after it is filed. Failure to act on it within 10 -days is a denial of reconsideration. If the AOGCC denies reconsideration, upon denial, this order or decision and the denial of reconsideration are FINAL and may be appealed to superior court. The appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision denying reconsideration, UNLESS the denial is by inaction, in which case the appeal MUST be filed within 40 days after the date on which the application for reconsideration was filed. If the AOGCC grants an application for reconsideration, this order or decision does not become final. Rather, the order or decision on reconsideration will be the FINAL order or decision of the AOGCC, and it may be appealed to superior court. That appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision on reconsideration. As provided in AS 31.05.080(b), "[t]he questions reviewed on appeal are limited to the questions presented to the AOGCC by the application for reconsideration." In computing a period of time above, the date of the event or default after which the designated period begins to run is not included in the period; the last day of the period is included, unless it falls on a weekend or state holiday, in which event the period runs until 5:00 p.m. on the next day that does not fall on a weekend or state holiday. • • Mary Jones David McCaleb XTO Energy, Inc. IHS Energy Group George Vaught, Jr. Cartography GEPS P.O. Box 13557 810 Houston Street, Ste 200 5333 Westheimer, Suite 100 Denver, CO 80201 -3557 Ft. Worth, TX 76102 -6298 Houston, TX 77056 Jerry Hodgden Richard Associates Mark Wedman NRG Associates Halliburton Hodgden Oil Company President 408 18 Street 6900 Arctic Blvd. Golden, CO 80401 -2433 P. Box 1655 Anchorage, AK 99502 Colorado Springs, CO 80901 Bernie Karl CIRI Baker Oil Tools K &K Recycling Inc. Land Department 795 E. 94 Ct. P.O. Box 58055 P.O. Box 93330 Anchorage, AK 99515 -4295 Fairbanks, AK 99711 Anchorage, AK 99503 North Slope Borough Richard Wagner Gordon Severson Planning Department P.O. Box 60868 3201 Westmar Circle P.O. Box 69 Fairbanks, AK 99706 Anchorage, AK 99508 -4336 Barrow, AK 99723 Jack Hakkila Darwin Waldsmith James Gibbs P.O. Box 190083 P.O. Box 39309 P.O. Box 1597 Anchorage, AK 99519 Ninilchick, AK 99639 Soldotna, AK 99669 Penny Vadla Cliff Burglin 399 West Riverview Avenue 319 Charles Street Soldotna, AK 99669 -7714 Fairbanks, AK 99701 NP • • ter, Samantha J (DOA) m: Colombie, Jody J (DOA) Thursday, December 22, 2011 1:00 PM Aaron Guzman; Ben Greene; Bruce Williams; Bruno, Jeff J (DNR); caunderwood @marathonoil.com; Casey Sullivan; Dale Hoffman; David Lenig; Donna Vukich; Eric Lidji; Franger, James M (DNR); Gary Orr; Smith, Graham 0 (PCO); Greg Mattson; Heusser, Heather A (DNR); Jason Bergerson; jilt .a.mcleod @conocophillips.com; Joe Longo; King, Kathleen J (DNR); Lara Coates; Lois Epstein; Marc Kuck; Steele, Marie C (DNR); Mary Aschoff; Matt Gill; Maurizio Grandi; Ostrovsky, Larry Z (DNR); Bettis, Patricia K (DNR); Peter Contreras; Richard Garrard; Ryan Daniel; Sandra Lemke; Talib Syed; Ted Rockwell; Wayne Wooster; Woolf, Wendy C (DNR); William Hutto; William Van Dyke; ( michael .j.nelson @conocophillips.com); ( Von. L.Hutchins @conocophillips.com); AKDCWelilntegrityCoordinator; Dennis, Alan R (DNR); alaska @petrocalc.com; Anna Raft Barbara F Fullmer; bbritch; bbohrer @ap.org; Bill Penrose; Bill Walker; Bowen Roberts; Brandon Gagnon; Brandow, Ganda (ASRC Energy Services); Havelock, Brian E (DNR); Bruce Webb; caunderwood @marathonoil.com; Chris Gay; Claire Caldes; Cliff Posey; Crandall, Krissell; D Lawrence; dapa; Daryl J. Kleppin; Dave Harbour; Dave Matthews; David Boelens; David House; Scott, David (LAA); David Steingreaber; ddonkel @cfl.rr.com; Dennis Steffy; Elowe, Kristin; Erika Denman; Francis S. Sommer; Fred Steece; Garland Robinson; Gary Laughlin; schultz, gary (DNR sponsored); ghammons; Gordon Pospisil; Gorney, David L; Greg Duggin; Gregg Nady; Gregory Geddes gspfoff; Jdarlington (jarlington @gmail.com); Jeanne McPherren; jeff.jones @alaskajournal.com; Jones, Jeffery B (DOA); Jerry McCutcheon; Jill Womack; Jim White; Jim Winegarner; news @radiokenai.com; Easton, John R (DNR); John Garing; Katz, John W (GOV); John S. Haworth; John Spain; Jon Goltz; Jones, Jeffrey L (GOV); Judy Stanek; Houle, Julie (DNR); Kari Moriarty; Kaynell Zeman; Keith Wiles; Kelly Sperback; Kim Cunningham; Ostrovsky, Larry Z (DNR); Gregersen, Laura 5 (DNR); Marc Kayak; Mark Dalton; Mark Hanley (mark.hanley @anadarko.com); Mark P. Worcester; Kremer, Marguerite C (DNR); Michael Dammeyer; Michael Jacobs; Mike Bill; mike @kbbi.org; Mike Morgan; Mikel Schultz; Mindy Lewis; MJ Loveland; mjnelson; mkm7200; knelson @petroleumnews.com; Nick W. Glover; NSK Problem Well Supv; Patty Alfaro; Decker, Paul L (DNR); Paul Figel; Randall Kanady; Randy L. Skillern; Delbridge, Rena E (LAA); Renan Yanish; rob.g.dragnich @exxonmobil.com; Robert Brelsford; Robert Campbell; Ryan Tunseth; Scott Cranswick; Scott Griffith; Shannon Donnelly; Sharmaine Copeland; Shellenbaum, Diane P (DNR); Slemons, donne D (DNR); Sondra Stewman; Steve Lambert; Moothart, Steve R (DNR); Steven R. Rossberg; Suzanne Gibson; tablerk; sheffield©aoga.org; Taylor, Cammy 0 (DNR); Davidson, Temple (DNR); Teresa lmm; Terrie Hubble; Thor Cutler; Tim Mayers; Tina Grovier; Todd Durkee; Tony Hopfinger; trmjrl; Vicki Irwin; Walter Featherly; Will Chinn; Williamson, Mary J (DNR); yjrosen @ak.net; Ballantine, Tab A (LAW); Brooks, Phoebe L (DOA); Colombie, Jody J (DOA); Crisp, John H (DOA); Davies, Stephen F (DOA); Fisher, Samantha J (DOA); Foerster, Catherine P (DOA); Fullom, Michael (DOA sponsored); Grimaldi, Louis R (DOA); Herrera, Matt F (DOA); Johnson, Elaine M (DOA); Jones, Jeffery B (DOA); Laasch, Linda K (DOA); Bender, Makana K (DOA); Herrera, Matt F (DOA); Maunder, Thomas E (DOA); McIver, Bren (DOA); McMains, Stephen E (DOA); Mumm, Joseph (DOA sponsored); Noble, Robert C (DOA); Norman, John K (DOA); Okland, Howard D (DOA); Paladijczuk, Tracie L (DOA); Pasqua!, Maria (DOA); Regg, James B (DOA); Roby, David 5 (DOA); Saltmarsh, Arthur C (DOA); Scheve, Charles M (DOA); Schwartz, Guy L (DOA); Seamount, Dan T (DOA) Subject: AIO2B -067 (KRU 3B -10), A1016 -002 (KRU 2L -305), AIO 2B -068 (KRU 3Q -01), OTH -71 (Oooguruk Unit) Attachments: aio2b- 068.pdf; Oth- 071.pdf; aio2b- 067.pdf; aio16- 002.pdf Jody J Colombie Special Assistant Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, AK 99501 (907)793 -1221 (phone) (907)276 -7542 (far) 1 • STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION 333 West 7 Avenue, Suite 100 Anchorage, Alaska 99501 Re: THE APPLICATION OF ) Area Injection Order No. 16.003 CONOCOPHILLIPS ALASKA, ) INC. for Administrative Approval ) Kuparuk River Unit allowing well 2L -319 (PTD 2071120) ) Tarn Oil Pool to be online in water only injection ) service with a tubing x inner annulus ) November 7, 2012 communication only when injecting ) miscible injectant. ) By letter dated November 4, 2012, ConocoPhillips Alaska, Inc. (CPAI) requested administrative approval to continue water only injection in the subject well. In accordance with Rule 10 of Area Injection Order (AIO) 16.000, the Alaska Oil and Gas Conservation Commission (AOGCC) hereby GRANTS ConocoPhillips Alaska Inc. (CPAI)'s request for administrative approval to continue water only injection in the subject well. CPAI reported to AOGCC on September 23, 2012 that the well showed signs of tubing x inner annulus (TxIA) communication after being on continual miscible injectant (MI) for more than a year. The IA would slowly repressurize over several days after pressure bleed events. On September 24, 2012, AOGCC approved a 30 day water only injection test in order to confirm that the communication was only evident when on MI injection service. A passing mechanical integrity test Tubing x Inner Annulus (MITIA) on October 4, 2012 and subsequent diagnostics indicates that KRU 2L -319 exhibits at least two competent barriers to the release of well pressure. The AOGCC finds that CPAI does not intend to perform repairs at this time. Accordingly, the AOGCC believes that the well's condition does not compromise overall well integrity so as to threaten human safety or the environment. AOGCC's approval to continue water injection only in KRU 2L -319 is conditioned upon the following: 1. CPAI shall record wellhead pressures and injection rate daily; 2. CPAI shall submit to the AOGCC a monthly report of well pressures, injection rates, and pressure bleeds for all annuli. Bleeds to be flagged on the report; 3. CPAI shall perform a mechanical integrity test of the inner annulus every 2 years to the maximum anticipated injection pressure; 4. CPAI shall limit the well's IA operating pressure to 2000 psi and the OA operating pressure to 1000 psi; 5. CPAI shall immediately shut in the well and notify the AOGCC if there is any change in the well's mechanical condition; AID 016.003 • • November 7, 2012 Page 2 of 2 6. After well shut in due to a change in the well's mechanical condition, AOGCC approval shall be required to restart injection; and 7. The MIT anniversary date will be set as October 4, 2012. DONE at Anchorage, Alaska and dated November 7, 2012. f � OILq, � AdJAlej/ �� . 1 Y1 � I +Ii {1111 < �« Cathy ' . Fo - rster Daniel T. Seamount, Jr. • K. ' an Commissioner Commissioner Commissioner � ON • RECONSIDERATION AND APPEAL NOTICE As provided in AS 31.05.080(a), within 20 days after written notice of the entry of this order or decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration of the matter determined by it. If the notice was mailed, then the period of time shall be 23 days. An application for reconsideration must set out the respect in which the order or decision is believed to be erroneous. The AOGCC shall grant or refuse the application for reconsideration in whole or in part within 10 days after it is filed. Failure to act on it within 10 -days is a denial of reconsideration. If the AOGCC denies reconsideration, upon denial, this order or decision and the denial of reconsideration are FINAL and may be appealed to superior court. The appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision denying reconsideration, UNLESS the denial is by inaction, in which case the appeal MUST be filed within 40 days after the date on which the application for reconsideration was filed. If the AOGCC grants an application for reconsideration, this order or decision does not become final. Rather, the order or decision on reconsideration will be the FINAL order or decision of the AOGCC, and it may be appealed to superior court. That appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision on reconsideration. As provided in AS 31.05.080(b), "[t]he questions reviewed on appeal are limited to the questions presented to the AOGCC by the application for reconsideration." In computing a period of time above, the date of the event or default after which the designated period begins to run is not included in the period; the last day of the period is included, unless it falls on a weekend or state holiday, in which event the period runs until 5:00 p.m. on the next day that does not fall on a weekend or state holiday. • • Colombie, Jody J (DOA) From: Colombie, Jody J (DOA) Sent: Wednesday, November 07, 2012 1:10 PM To: Singh, Angela K (DOA); Ballantine, Tab A (LAW); Brooks, Phoebe L (DOA); Colombie, Jody J (DOA); Crisp, John H (DOA); Davies, Stephen F (DOA); Ferguson, Victoria L (DOA); Fisher, Samantha J (DOA); Foerster, Catherine P (DOA); Grimaldi, Louis R (DOA); Johnson, Elaine M (DOA); Jones, Jeffery B (DOA); Laasch, Linda K (DOA); Bender, Makana K (DOA); McIver, Bren (DOA); McMains, Stephen E (DOA); Mumm, Joseph (DOA sponsored); Noble, Robert C (DOA); Norman, John K (DOA); Okland, Howard D (DOA); Paladijczuk, Tracie L (DOA); Pasqual, Maria (DOA); Regg, James B (DOA); Roby, David S (DOA); Scheve, Charles M (DOA); Schwartz, Guy L (DOA); Seamount, Dan T (DOA); Wallace, Chris D (DOA); Aaron Gluzman; Aaron Sorrell; Bruce Williams; Bruno, Jeff J (DNR); caunderwood @marathonoil.com; Casey Sullivan; Dale Hoffman; David Lenig; Donna Vukich; Eric Lidji; Erik Opstad; Franger, James M (DNR); Gary Orr; Smith, Graham 0 (PCO); Greg Mattson; Heusser, Heather A (DNR); James Rodgers; Jason Bergerson; Jennifer Starck; jilt .a.mcleod @conocophillips.com; Joe Longo; King, Kathleen J (DNR); Lara Coates; Lois Epstein; Marc Kuck; Steele, Marie C (DNR); Matt Gill; Melissa Okoola; Ostrovsky, Larry (DNR sponsored); Bettis, Patricia K (DOA); Perrin, Don J (DNR); Peter Contreras; Pexton, Scott R (DNR); Richard Garrard; Ryan Daniel; Sandra Lemke; Talib Syed; Terrace Dalton; Wayne Wooster; Woolf, Wendy C (DNR); William Hutto; William Van Dyke; (michael.j.nelson @conocophillips.com); AKDCWeIIIntegrityCoordinator; alaska @petrocalc.com; Anna Raff; Barbara F Fullmer; bbritch; bbohrer @ap.org; Bill Penrose; Bill Walker; Bowen Roberts; Bruce Webb; Claire Caldes; Cliff Posey; Crandall, Krissell; D Lawrence; Daryl J. Kleppin; Dave Harbour; Dave Matthews; David Boelens; David Duffy; David House; Scott, David (LAA); David Steingreaber; Davide Simeone; ddonkel @cfl.rr.com; Elowe, Kristin; Francis S. Sommer; Gary Laughlin; schultz, gary (DNR sponsored); ghammons; Gordon Pospisil; Gorney, David L.; Greg Duggin; Gregg Nady; Gregory Geddes; gspfoff; Jdarlington (jarlington @gmail.com); Jeanne McPherren; Jones, Jeffery B (DOA); Jerry McCutcheon; Jill Womack; Jim White; Jim Winegarner; Joe Lastufka; news @radiokenai.com; Easton, John R (DNR); John Garing; John Spain; Jon Goltz; Jones, Jeffrey L (GOV); Judy Stanek; Judy Stanek; Houle, Julie (DNR); Julie Little; Kari Moriarty; Kaynell Zeman; Keith Wiles; Kelly Sperback; Gregersen, Laura S (DNR); Luke Keller; Marc Kovak; Mark Dalton; Mark Hanley (mark.hanley @anadarko.com); Mark P. Worcester; Kremer, Marguerite C (DNR); Michael Jacobs; Mike Bill; mike @kbbi.org; Mike Morgan; Mike! Schultz; Mindy Lewis; MJ Loveland; mjnelson; mkm7200; knelson @petroleumnews.com; Nick W. Glover; NSK Problem Well Supv; Patty Alfaro; Decker, Paul L (DNR); Paul Figel; Paul Mazzolini; Randall Kanady; Randy L. Skillern; Delbridge, Rena E (LAA); Renan Yanish; Robert Brelsford; Robert Campbell; Ryan Tunseth; Scott Cranswick; Scott Griffith; Shannon Donnelly; Sharmaine Copeland; Shellenbaum, Diane P (DNR); Slemons, Jonne D (DNR); Sondra Stewman; Stephanie Klemmer; Moothart, Steve R (DNR); Steven R. Rossberg; Suzanne Gibson; sheffield @aoga.org; Davidson, Temple (DNR); Teresa Imm; Thor Cutler; Tim Mayers; Tina Grovier; Todd Durkee; Tony Hopfinger; trmjrl; Vicki Irwin; Walter Featherly; yjrosen @ak.net Subject: AIO 16 -003 KRU Administrative Approval Attachments: aio16- 003.pdf Jody J. Colombie Special Assistant Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage, AK 99501 (907)793 -1221 (phone) (907)276 -7542 (fax) 1 Mary Jones • David McCaleb • XTO Energy, Inc. IHS Energy Group George Vaught, Jr. Cartography GEPS P.O. Box 13557 810 Houston St., Ste. 200 5333 Westheimer, Ste. 100 Denver, CO 80201 -3557 Ft. Worth, TX 76102 -6298 Houston, TX 77056 Jerry Hodgden Richard Neahring Mark Wedman Hodgden Oil Company NRG Associates Halliburton to President 40818 St. 6900 Arctic Blvd. Golden, CO 80401 -2433 P.O. Box 1655 Anchorage, AK 99502 Colorado Springs, CO 80901 Bernie Karl CIRI K &K Recycling Inc. Land Department Baker Oil pools P.O. Box 58055 P.O. Box 93330 795 E. 94 Ct. Fairbanks, AK 99711 Anchorage, AK 99503 Anchorage, AK 99515 -4295 North Slope Borough Richard Wagner Gordon Severson Planning Department P.O. Box 60868 3201 Westmar Cir. P.O. Box 69 Barrow, AK 99723 Fairbanks, AK 99706 Anchorage, AK 99508 -4336 Jack Hakkila Darwin Waldsmith James Gibbs P.O. Box 190083 P.O. Box 39309 P.O. Box 1597 Anchorage, AK 99519 Ninilchik, AK 99639 Soldotna, AK 99669 Penny Vadla 399 W. Riverview Ave. Soldotna, AK 99669 -7714 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION 333 West 7th Avenue, Suite 100 Anchorage, Alaska 99501 Re: THE APPLICATION OF ) Area Injection Order No. 16.004 CONOCOPHILLIPS ALASKA, ) INC. for Administrative Approval ) Kuparuk River Unit allowing well 2L-310 (PTD 2100280) ) Kuparuk River Field to be online in water only injection ) Tarn Oil Pool service with a tubing x inner annulus ) communication only when injecting ) April 14, 2014 miscible injectant. ) By letter dated April 1, 2014, ConocoPhillips Alaska, Inc. (CPAI) requested administrative approval to continue water only injection in the subject well. In accordance with Rule 10 of Area Injection Order (AIO) 16.000, the Alaska Oil and Gas Conservation Commission (AOGCC) hereby GRANTS CPAI's request for administrative approval to continue water only injection in the subject well. CPAI reported a potential Tubing x Inner Annulus pressure communication to AOGCC on February 3, 2014 while on miscible injectant (MI) injection service. Diagnostics were performed while on MI and CPAI WAG'ed the well to water after receiving permission from AOGCC. The well does not exhibit signs of pressure communication while on water injection. The passing non -state witnessed mechanical integrity test of the Inner Annulus (MITIA) on February 5, 2014 indicates that 2L-310 exhibits at least two competent barriers to the release of well pressure. Accordingly, the AOGCC believes that the well's condition does not compromise overall well integrity so as to threaten human safety or the environment. AOGCC's approval to continue water injection only in KRU 2L-310 is conditioned upon the following: 1. CPAI shall record wellhead pressures and injection rate daily; 2. CPAI shall submit to the AOGCC a monthly report of well pressures, injection rates, and pressure bleeds for all annuli. Bleeds to be flagged on the report; 3. CPAI shall perform a mechanical integrity test of the inner annulus every 2 years to the maximum anticipated injection pressure; 4. CPAI shall limit the well's IA operating pressure to 2000 psi and the OA operating pressure to 1000 psi; 5. CPAI shall immediately shut in the well and notify the AOGCC if there is any change in the well's mechanical condition; 6. After well shut in due to a change in the well's mechanical condition, AOGCC approval shall be required to restart injection; and 7. The MIT anniversary date is February 5, 2014. AIO 16.004 April 14, 2014 Page 2 of 2 DONE at Anchorage, Alaska and dated April 14, 2014. ��4 ��' /,/- Cathy P. Foerster Chair, Commissioner aniel T. Seamouq�,--jr. Commissioner ; TION AND APPEAL NOTICE As provided in AS 31.05.080(a), within 20 days after written notice of the entry of this order or decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration of the matter determined by it. If the notice was mailed, then the period of time shall be 23 days. An application for reconsideration must set out the respect in which the order or decision is believed to be erroneous. The AOGCC shall grantor refuse the application for reconsideration in whole or in part within 10 days after it is filed. Failure to act on it within 10-days is a denial of reconsideration. If the AOGCC denies reconsideration, upon denial, this order or decision and the denial of reconsideration are FINAL and may be appealed to superior court. The appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision denying reconsideration, UNLESS the denial is by inaction, in which case the appeal MUST be filed within 40 days after the date on which the application for reconsideration was filed. If the AOGCC grants an application for reconsideration, this order or decision does not become final. Rather, the order or decision on reconsideration will be the FINAL order or decision of the AOGCC, and it may be appealed to superior court. That appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision on reconsideration. In computing a period of time above, the date of the event or default after which the designated period begins to run is not included in the period; the last day of the period is included, unless it falls on a weekend or state holiday, in which event the period runs until 5:00 p.m. on the next day that does not fall on a weekend or state holiday. Singh. Angela K (DOA) From: Carlisle, Samantha J (DOA) Sent: Monday, April 14, 2014 3:59 PM To: Ballantine, Tab A (LAW); Bender, Makana K (DOA); Bettis, Patricia K (DOA); Brooks, Phoebe L (DOA); Carlisle, Samantha J (DOA); Colombie, Jody J (DOA); Crisp, John H (DOA); Davies, Stephen F (DOA); Eaton, Loraine E (DOA); Ferguson, Victoria L (DOA); Foerster, Catherine P (DOA); Frystacky, Michal (DOA); Grimaldi, Louis R (DOA); Guhl, Meredith D (DOA); Hill, Johnnie W (DOA); Hunt, Jennifer L (DOA); Johnson, Elaine M (DOA); Jones, Jeffery B (DOA); Mumm, Joseph (DOA sponsored); Noble, Robert C (DOA); Paladijczuk, Tracie L (DOA); Pasqual, Maria (DOA); Regg, James B (DOA); Roby, David S (DOA); Scheve, Charles M (DOA); Schwartz, Guy L (DOA); Seamount, Dan T (DOA); Singh, Angela K (DOA); Turkington, Jeff A (DOA); Wallace, Chris D (DOA); (michael j.nelson@conocophillips.com); AKDCWeIIIntegrityCoordinator; Alexander Bridge; Andrew Vandedack; Anna Raff; Barbara F Fullmer, bbritch; bbohrer@ap.org; Barron, William C (DNR); Bill Penrose; Bill Walker, Bob Shavelson; Brian Havelock; Burdick, John D (DNR); Cliff Posey; Colleen Miller; Crandall, Krissell; D Lawrence; Daryl J. Kleppin; Dave Harbour, Dave Matthews; David Boelens; David Duffy; David Goade; David House; David McCaleb; David Scott; David Steingreaber; David Tetta; Davide Simeone; ddonkel@cfl.rr.com; Donna Ambruz; Dowdy, Alicia G (DNR); Dudley Platt; Ed Jones; Elowe, Kristin; Evans, John R (LDZX); Francis S. Sommer, Frank Molli; schultz, gary (DNR sponsored); George Pollock; ghammons; Gordon Pospisil; Gorney, David L.; Greg Duggin; Gregg Nady; gspfoff, Jacki Rose; Jdarlington oarlington@gmail.com); Jeanne McPherren; Jerry McCutcheon; Jim White; Joe Lastufka; news@radiokenai.com; Easton, John R (DNR); John Garing; Jon Goltz; Jones, Jeffrey L (GOV); Juanita Lovett; Judy Stanek, Houle, Julie (DNR); Julie Little; Kari Moriarty; Keith Wiles; Kelly Sperback; Klippmann; Gregersen, Laura S (DNR); Leslie Smith; Lisa Parker; Louisiana Cutler, Luke Keller, Marc Kovak; Dalton, Mark (DOT sponsored); Mark Hanley (mark.hanley@anadarko.com); Mark P. Worcester, Mark Wedman; Kremer, Marguerite C (DNR); Michael Jacobs; Mike Bill; mike@kbbi.org; Mikel Schultz; Mindy Lewis; MJ Loveland; mjnelson; mkm7200; Morones, Mark P (DNR); knelson@petroleumnews.com; Nick W. Glover, Nikki Martin; NSK Problem Well Supv; Oliver Sternicki; Patty Alfaro; Decker, Paul L (DNR); Paul Mazzolini; Pike, Kevin W (DNR); Randall Kanady; Randy L. Skillern; Randy Redmond; Rena Delbridge; Renan Yanish; Robert Brelsford; Ryan Tunseth; Sandra Haggard; Sara Leverette; Scott Griffith; Shannon Donnelly; Sharmaine Copeland; Sharon Yarawsky, Shellenbaum, Diane P (DNR); Slemons, Jonne D (DNR); Smart Energy Universe; Smith, Kyle S (DNR); Sondra Stewman; Stephanie Klemmer; Steve Kiorpes; Moothart, Steve R (DNR); Steven R. Rossberg; Suzanne Gibson; Sheffield@aoga.org; Tania Ramos; Ted Kramer; Davidson, Temple (DNR); Terence Dalton; Teresa Imm; Thor Cutler, Tim Mayers; Tina Grovier; Todd Durkee; Tony Hopfinger; trmjrl; Tyler Senden; Vicki Irwin; Vinnie Catalano; Walter Featherly; yjrosen@ak.net; Aaron Gluzman; Aaron Sorrell; Ajibola Adeyeye; Alan Dennis; Andrew Cater, Anne Hillman; Bruce Williams; Bruno, Jeff J (DNR); Casey Sullivan; David Lenig; Perrin, Don 1 (DNR); Donna Vukich; Eric Lidji; Erik Opstad; Gary Orr, Smith, Graham O (PCO); Greg Mattson; Hans Schlegel; Heusser, Heather A (DNR); Holly Pearen; James Rodgers; Jason Bergerson; Jennifer Starck; jill.a.mcleod@conocophillips.com; Jim Magill; Joe Longo; John Martineck; Josh Kindred; Kenneth Luckey; King, Kathleen J (DNR); Laney Vazquez; Lois Epstein; Longan, Sara W (DNR); Marc Kuck; Marcia Hobson; Steele, Marie C (DNR); Matt Armstrong; Matt Gill; Franger, lames M (DNR); Morgan, Kirk A (DNR); Pat Galvin; Peter Contreras; Pollet, Jolie; Richard Garrard; Richard Nehring; Robert Province; Ryan Daniel; Sandra Lemke; Pexton, Scott R (DNR); Peterson, Shaun (DNR); Pollard, Susan R (LAW); Talib Syed; Terence Dalton; Todd, Richard J (LAW); Tostevin, Breck C (LAW); Wayne Wooster; Woolf, Wendy To: C (DNR); William Hutto; William Van Dyke Subject: AIO 16.004 Kuparuk River Unit Attachments: aio16-004.pdf Samantha CarCisCe Executive Secretary 11 At4s(a OiCandjCas Conservation Commission 333 West 711 .Avenue, Suite loo .Anchorage, _ X 99501 (907) 793-1223 ((yhone) (907) 276-7542 (fax) CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Samantha Carlisle at (907) 793- 1223 or Samantha.Carlisle@Alaska.Gov. Kelly Lyons Problem Wells Supervisor ConocoPhillips Alaska, Inc. Post Office Box 100360 Anchorage, AK 99510-0360 Penny Vadla George Vaught, Jr. Jerry Hodgden O 399 W. Riverview Ave. Post Office Box 13557 40818 081Golden, 8t n St. Company Soldotna, AK 99669-7714 Denver, CO 80201-3557 Golden, CO 80401-2433 Bernie Karl CIRI North Slope Borough K&K Recycling Inc. Land Department Planning Department Post Office Box 58055 Post Office Box 93330 Post Office Box 69 Fairbanks, AK 99711 Anchorage, AK 99503 Barrow, AK 99723 Richard Wagner Gordon Severson Jack Hakkila Post Office Box 60868 3201 Westmar Cir. Post Office Box 190083 Fairbanks, AK 99706 Anchorage, AK 99508-4336 Anchorage, AK 99519 Darwin Waldsmith Post Office Box 39309 Ninilchik, AK 99639 James Gibbs Post Office Box 1597 Soldotna, AK 99669 fy k �4 , `11,11R- Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.alaska.gov ADMINISTRATIVE APPROVAL AREA INJECTION ORDER 16.004 AMENDED AMENDED Ms. Jaime Bronga Well Integrity Specialist ConocoPhillips Alaska, Inc. P.O. Box 100360 Anchorage, AK 99510-0360 Re: Docket Number: AIO-24-033 Request to Amend Administrative Approval to Area Injection Order 16.004; Water Alternating Gas Injection Kuparuk River Unit (KRU) 2L-310 (PTD 2100280), Tarn Oil Pool Dear Ms. Bronga: By emailed letter dated November 11, 2024, ConocoPhillips Alaska, Inc. (CPAI) requested to amend administrative approval AIO 16.004 Amended to modify the thermal bleed restrictions and continue water alternating gas (WAG) injection with a known tubing by inner annulus (TxIA) pressure communication which is exhibited only while on gas injection. In accordance with 20AAC 25.556(d), the Alaska Oil and Gas Conservation Commission (AOGCC) hereby GRANTS, subject to conditions, CPAI’s request to amend the administrative approval and continue WAG injection in the subject well. CPAI reported a potential TxIA pressure communication to AOGCC on February 3, 2014, while on miscible injectant (MI) injection service and on April 14, 2014, AOGCC approved AIO 16.004 to allow water only injection to continue. The well does not exhibit signs of pressure communication while on water injection. AOGCC amended AIO 16.004 on April 17, 2019, after CPAI changed an internal policy to allow WAG injection in wells that can meet certain criteria. CPAI has now removed their internal policy limitation on non-thermal bleed frequency and requested AOGCC amend AIO 16.004 for consistency. CPAI maintains live transmitters on the inner and outer annulus and alarm functions in the Supervisory Control and Data Acquisition (SCADA) system that create layers of protection from an over pressure event. CPAI performed diagnostics including a passing state witnessed mechanical integrity test of the Inner Annulus (MITIA) on August 6, 2024, which indicates that 2L-310 exhibits at least two competent barriers to the release of well pressure. AOGCC believes CPAI can safely manage the TxIA communication with periodic pressure bleeds by maintaining the inner annulus to a pressure not to exceed 2,400 psi and the outer annulus not to exceed 1,000 psi. Accordingly, the AOGCC believes that the AIO 16.004 Amended Amended November 26, 2024 Page 2 of 3 well’s condition does not compromise overall well integrity so as to threaten human safety or the environment. AOGCC’s approval to continue WAG injection in KRU 2L-310 is conditioned upon the following: 1) CPAI shall record wellhead pressures and injection rate daily; 2) CPAI shall submit to the AOGCC a monthly report of well pressures, injection rates, and pressure bleeds for all annuli. Bleeds to be flagged on the report; 3) CPAI shall perform a MIT of the inner annulus every two years to the greater of the maximum anticipated injection pressure or 0.25 x packer TVD, but not less than 1,500 psi; 4) CPAI shall perform a Surface Casing Leak Detect (SCLD) log every two years on the OA rather than a MIT of the OA. It is not a requirement to have this SCLD log state-witnessed. 5) CPAI shall limit the well’s inner annulus operating pressure to 2,400 psi during gas injection and 2,000 psi during water injection. Audible control room alarms shall be set at or below these limits; 6) CPAI shall limit the well’s outer annulus operating pressure to 1,000 psi. Audible control room alarms shall be set at or below these limits; 7) CPAI shall monitor the inner and outer annulus pressures in real time with its SCADA system; 8) CPAI shall immediately shut in the well and notify the AOGCC if there is any change in the well's mechanical condition; 9) After well shut in due to a change in the well's mechanical condition, AOGCC approval shall be required to restart injection; and 10) The next required MIT is to be before or during the month of August 2026. This is to align with the agreed upon CPAI Underground Injection Control MIT permanent test schedule for pad testing. DONE at Anchorage, Alaska and dated November 26, 2024. Jessie L. Chmielowski Gregory C. Wilson Commissioner Commissioner Gregory C. Wilson Digitally signed by Gregory C. Wilson Date: 2024.11.26 09:51:33 -09'00' Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2024.11.26 11:01:21 -09'00' AIO 16.004 Amended Amended November 26, 2024 Page 3 of 3 RECONSIDERATION AND APPEAL NOTICE As provided in AS 31.05.080(a), within 20 days after written notice of the entry of this order or decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration of the matter determined by it. If the notice was mailed, then the period of time shall be 23 days. An application for reconsideration must set out the respect in which the order or decision is believed to be erroneous. The AOGCC shall grant or refuse the application for reconsideration in whole or in part within 10 days after it is filed. Failure to act on it within 10 days is a denial of reconsideration. If the AOGCC denies reconsideration, upon denial, this order or decision and the denial of reconsideration are FINAL and may be appealed to superior court. The appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision denying reconsideration, UNLESS the denial is by inaction, in which case the appeal MUST be filed within 40 days after the date on which the application for reconsideration was filed. If the AOGCC grants an application for reconsideration, this order or decision does not become final. Rather, the order or decision on reconsideration will be the FINAL order or decision of the AOGCC, and it may be appealed to superior court. That appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision on reconsideration. In computing a period of time above, the date of the event or default after which the designated period begins to run is not included in the period; the last day of the period is included, unless it falls on a weekend or state holiday, in which event the period runs until 5:00 p.m. on the next day that does not fall on a weekend or state holiday. From:Coldiron, Samantha J (OGC) To:AOGCC_Public_Notices Subject:[AOGCC_Public_Notices] Area Injection Order 16.004 amended amended (CPAI) Date:Tuesday, November 26, 2024 11:28:04 AM Attachments:aio16.004 amended amended.pdf Docket Number: AIO-24-033 Request to Amend Administrative Approval to Area Injection Order 16.004; Water Alternating Gas Injection Kuparuk River Unit (KRU) 2L-310 (PTD 2100280), Tarn Oil Pool Samantha Coldiron AOGCC Special Assistant Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage, AK 99501 (907) 793-1223 __________________________________ List Name: AOGCC_Public_Notices@list.state.ak.us You subscribed as: samantha.coldiron@alaska.gov Unsubscribe at: https://list.state.ak.us/mailman/options/aogcc_public_notices/samantha.coldiron%40alaska.go v THE STATE °fALASKA GOVERNOR BILL WALKER Alaska Oil and Gas Conservation Commission ADMINISTRATIVE APPROVAL AREA INJECTION ORDER NO. 16.005 Ms. Kelly Lyons Problem Wells Supervisor ConocoPhillips Alaska, Inc. P.O. Box 100360 Anchorage, AK 99510-0360 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.olaska.gov Re: Docket Number: AIO-15-049 Request for administrative approval to allow well 2L-323 (PTD 1982510) to be online in water only injection service with a known tubing by inner annulus communication. Kuparuk River Unit (KRU) 2L-323 (PTD 1982510) Kuparuk River Field Tarn Oil Pool Dear Ms. Lyons: By letter dated October 30, 2015, ConocoPhillips Alaska, Inc. (CPAI) requested administrative approval to continue water only injection in the subject well. In accordance with Rule 10 of Area Injection Order (AIO) 16.000, the Alaska Oil and Gas Conservation Commission (AOGCC) hereby GRANTS CPAI's request for administrative approval to continue water only injection in the subject well. CPAI reported a potential Tubing x Inner Annulus pressure communication to AOGCC on January 31, 2015 while the well was on gas injection. CPAI performed diagnostics including a passing non -state witnessed Mechanical Integrity Test of the Inner Annulus (MITIA) on February 1, 2015 which indicates that 2L-323 exhibits at least two competent barriers to the release of well pressure. The well was shut in and was WAG'ed to water on October 2, 2015 for an AOGCC approved 30 day monitor period. The well does not exhibit signs of pressure communication while on water injection. Accordingly, the AOGCC believes that the well's condition does not compromise overall well integrity so as to threaten human safety or the environment. AIO 16.005 November 5, 2015 Page 2 of 2 AOGCC's approval to continue water injection only in KRU 2L-323 is conditioned upon the following: 1. CPAI shall record wellhead pressures and injection rate daily; 2. CPAI shall submit to the AOGCC a monthly report of well pressures, injection rates, and pressure bleeds for all annuli. Bleeds to be flagged on the report; 3. CPAI shall perform a mechanical integrity test of the inner annulus every 2 years to the maximum anticipated injection pressure; 4. CPAI shall limit the well's IA operating pressure to 2000 psi and the OA operating pressure to 1000 psi; 5. CPAI shall immediately shut in the well and notify the AOGCC if there is any change in the well's mechanical condition; 6. After well shut in due to a change in the well's mechanical condition, AOGCC approval shall be required to restart injection; and 7. The MIT anniversary date is February 1, 2015. DONE at Anchorage, Alaska and dated November 5, 2015. Cathy . Foerster Daniel T. Seamount, Jr. Chair, Commissioner Commissioner RECONSIDERATION AND APPEAL NOTICE As provided in AS 31.05.080(a), within 20 days after written notice of the entry of this order or decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration of the matter determined by it. If the notice was mailed, then the period of time shall be 23 days. An application for reconsideration must set out the respect in which the order or decision is believed to be erroneous. The AOGCC shall grant or refuse the application for reconsideration in whole or in part within 10 days after it is filed. Failure to act on it within 10-days is a denial of reconsideration. If the AOGCC denies reconsideration, upon denial, this order or decision and the denial of reconsideration are FINAL and may be appealed to superior court. The appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision denying reconsideration, UNLESS the denial is by inaction, in which case the appeal MUST be filed within 40 days after the date on which the application for reconsideration was filed. If the AOGCC grants an application for reconsideration, this order or decision does not become final. Rather, the order or decision on reconsideration will be the FINAL order or decision of the AOGCC, and it may be appealed to superior court. That appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision on reconsideration. In computing a period of time above, the date of the event or default after which the designated period begins to run is not included in the period; the last day of the period is included, unless it falls on a weekend or state holiday, in which event the period runs until 5:00 p.m. on the next day that does not fall on a weekend or state holiday. James Gibbs Jack Hakkila Bernie Karl P.O. Box 1597 P.O. Box 190083 M Recycling Inc. Soldotna, AK 99669 Anchorage, AK 99519 P.O. Box 58055 Fairbanks, AK 99711 Gordon Severson Penny Vadla George Vaught, Jr. 3201 Westmar Cir. 399 W. Riverview Ave. P.O. Box 13557 Anchorage, AK 99508-4336 Soldotna, AK 99669-7714 Denver, CO 80201-3557 Ms. Kelly Lyons Richard Wagner Darwin Waldsmith Problem Wells Supervisor P.O. Box 60868 P.O. Box 39309 ConocoPhillips Alaska, Inc. Fairbanks, AK 99706 Ninilchik, AK 99639 P.O. Box 100360 Anchorage, AK 99510-0360 yq� �la- Angela K. Singh Colombie, Jody J (DOA) From: Colombie, Jody J (DOA) Sent: Friday, November 06, 2015 9:17 AM To: 'AKDCWellIntegrityCoordinator'; 'Alex Demarban'; 'Alexander Bridge'; 'Allen Huckabay'; 'Andrew VanderJack'; 'Anna Raff'; 'Barbara F Fullmer'; 'bbritch'; 'Becky Bohrer'; 'Bob Shavelson'; 'Brian Havelock'; 'Bruce Webb'; Burdick, John D (DNR); 'Caleb Conrad'; 'Carrie Wong'; 'Cliff Posey'; 'Colleen Miller'; 'Crandall, Krissell'; 'D Lawrence'; 'Dave Harbour'; 'David Boelens'; 'David Duffy'; 'David House'; 'David McCaleb'; 'David Steingreaber'; 'David Tetta'; 'Davide Simeone'; 'ddonkel@cfl.rr.com'; 'Dean Gallegos'; Delbridge, Rena E (LAS); DNROG Units (DNR sponsored); 'Donna Ambruz'; 'Ed Jones'; 'Elowe, Kristin'; 'Evans, John R (LDZX)'; 'Frank Molli'; 'Gary Oskolkosf'; 'George Pollock'; 'ghammons'; 'Gordon Pospisil'; 'Gregg Nady'; 'gspfoff'; Hyun, James J (DNR); 'Jacki Rose'; 'Jdarlington Oarlington@gmail.com)'; 'Jeanne McPherren'; 'Jennifer Williams'; 'Jerry Hodgden'; 'Jerry McCutcheon'; 'Jessica Solnick'; 'Jim Watt'; 'Jim White'; 'Joe Lastufka'; 'Joe Nicks'; 'John Adams'; 'John Easton'; 'Jon Goltz'; 'Juanita Lovett'; 'Judy Stanek'; 'Julie Houle'; 'Julie Little'; 'Karl Moriarty'; 'Kazeem Adegbola'; 'Keith Wiles'; 'Kelly Sperback'; 'Laney Vazquez'; 'Laura Silliphant (laura.gregersen@alaska.gov)'; 'Leslie Smith'; 'Lisa Parker'; 'Louisiana Cutler'; 'Luke Keller'; 'Marc Kovak'; 'Mark Dalton'; 'Mark Hanley (mark.hanley@anadarko.com)'; 'Mark Landt'; 'Mark Wedman'; 'Marquerite kremer (meg.kremer@alaska.gov)'; 'Mary Cocklan-Vendl'; 'Michael Calkins'; 'Michael Duncan'; 'Michael Moora'; 'Mike Bill'; 'Mike Mason'; 'Mike) Schultz'; 'MJ Loveland'; 'mkm7200'; Morones, Mark P (DNR); Munisteri, Islin W M (DNR); 'nelson'; 'Nichole Saunders'; 'Nick W. Glover'; 'Nikki Martin'; NSK Problem Well Supv; Patty Alfaro; 'Paul Craig'; Paul Decker (paul.decker@alaska.gov); 'Paul Mazzolini'; Pike, Kevin W (DNR); Randall Kanady; Randy L. Skillern; 'Renan Yanish'; 'Robert Brelsford'; 'Ryan Tunseth'; Sara Leverette; 'Scott Griffith'; Shannon Donnelly, Sharmaine Copeland; 'Sharon Yarawsky'; Shellenbaum, Diane P (DNR); Skutca, Joseph E (DNR); Smart Energy Universe; Smith, Kyle S (DNR); Sondra Stewman; 'Stephanie Klemmer'; Sternicki, Oliver R; Steve Moothart (steve.moothart@alaska.gov); 'Suzanne Gibson'; Tamera Sheffield; 'Tania Ramos'; 'Ted Kramer'; Temple Davidson; Terence Dalton; Teresa Imm; Thor Cutler; 'Tim Mayers'; Todd Durkee; trmjrl; 'Tyler Senden'; Vicki Irwin; Vinnie Catalano Subject: KRU Tarn Admin Approval Attachments: aiol6-005.pdf Jody J. CoCombie _A0(jCC SpeciaCAssistant ACaska OiCand Gas Conservation Commission 333 '1'Vest 7`.Avenue .Anchorage, .ACaska 995oi Office: (907) 793-1221 fax: (907) 276-7542 CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Jody Colombie at 907.793.1221 or iody.colombie@alaska.aov. Colombie, Jody J (DOA) From: Colombie, Jody J (DOA) Sent: Friday, November 06, 2015 9:11 AM To: 'Ballantine, Tab A (LAW) (tab.ballantine@alaska.gov)'; 'Bender, Makana K (DOA) (makana.bender@alaska.gov)'; 'Bettis, Patricia K (DOA) (patricia.bettis@alaska.gov)'; Bixby, Brian D (DOA); 'Brooks, Phoebe L (DOA) (phoebe.brooks@alaska.gov)'; Carlisle, Samantha J (DOA); 'Colombie, Jody J (DOA) Oody.colombie@alaska.gov)'; Cook, Guy D (DOA); 'Crisp, John H (DOA) Oohn.crisp@alaska.gov)'; 'Davies, Stephen F (DOA) (steve.davies@alaska.gov)'; Eaton, Loraine E (DOA); 'Foerster, Catherine P (DOA) (cathy.foerster@alaska.gov)'; Trystacky, Michal (michal.frystacky@alaska.gov)'; 'Grimaldi, Louis R (DOA) (lou.grimaldi@alaska.gov)'; 'Guhl, Meredith (DOA sponsored) (meredith.guhl@alaska.gov)'; Herrera, Matthew F (DOA); 'Hill, Johnnie W (DOA)'; 'Jones, Jeffery B (DOA) Oeffjones@alaska.gov)'; Kair, Michael N (DOA); Loepp, Victoria T (DOA); 'Mumm, Joseph (DOA sponsored) Ooseph.mumm@alaska.gov)'; 'Noble, Robert C (DOA) (bob.noble@alaska.gov)'; 'Paladijczuk, Tracie L (DOA) (tracie.paladijczuk@alaska.gov)'; 'Pasqual, Maria (DOA) (maria.pasqual@alaska.gov)'; 'Regg, James B (DOA) Oim.regg@alaska.gov)'; 'Roby, David S (DOA) (dave.roby@alaska.gov)'; 'Scheve, Charles M (DOA) (chuck.scheve@alaska.gov)'; 'Schwartz, Guy L (DOA) (guy.schwartz@alaska.gov)'; 'Seamount, Dan T (DOA) (dan.seamount@alaska.gov)'; 'Singh, Angela K (DOA) (angela.singh@alaska.gov)'; 'Wallace, Chris D (DOA) (chris.wallace@alaska.gov)' Subject: KRU Tarn Admin Approval Attachments: aio16-005.pdf Jody J. Colombie AOJCC SpeciaCAssistant ACaska OiCandGas Conservation Commission 333 West 7" .Avenue Anchorage, Alaska 99501 Office: (907) 793-1221 fax: (907) 276-7542 CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Jody Colombie at 907.793.1221 or iodv.colombie@alaska.aov. Colombie, Jody J (DOA) From: Colombie, Jody J (DOA) Sent: Friday, November 06, 2015 9:12 AM To: 'Aaron Gluzman'; 'Aaron Sorrell; Ajibola Adeyeye; Alan Dennis; Andrew Cater; Anne Hillman; Bajsarowicz, Caroline J; Brian Gross; 'Bruce Williams'; Bruno, Jeff J (DNR); Casey Sullivan; David Tetta; Don Shaw; 'Donna Vukich'; Eric Lidji; 'Gary Orr'; 'Graham Smith'; 'Greg Mattson'; Hak Dickenson; Heusser, Heather A (DNR); Holly Pearen; James Hyun; 'Jason Bergerson'; 'Jim Magill'; Joe Longo; John Martineck; Josh Kindred; Kenneth Luckey; King, Kathleen J (DNR); Laney Vazquez; Lois Epstein; Longan, Sara W (DNR); 'Louisiana Cutler'; Marc Kuck; Marcia Hobson; 'Marie Steele'; Matt Armstrong; 'Mike Franger'; Morgan, Kirk A (DNR); Pat Galvin; 'Patricia Bettis'; Pete Dickinson; Peter Contreras; Richard Garrard; Richmond, Diane M; Robert Province; 'Ryan Daniel'; 'Sandra Lemke'; Sarah Baker, Shaun Peterson; 'Susan Pollard'; Talib Syed; Terence Dalton; Tina Grovier (tmgrovier@stoel.com); Todd, Richard J (LAW); Tostevin, Breck C (LAW); 'Wayne Wooster'; 'William Van Dyke' Subject: KRU Tarn Admin Approval Attachments: aio16-005.pdf Jody J. CoCombie .AOqCC SpeciaCAssistant _Alaska. OiCand C�as Conservation Commission 333'Nest 7" .Avenue -Anchorage, .Alaska 995o1 Office: (907) 793-1221 Fax: i907) 276-7542 CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Jody Colombie at 907.793.1221 or iodv.colombie@alaska.gov. THE STATE Alaska Oil and Gas °fALASKA Conservation Commission GOVERNOR BILL WALKER ADMINISTRATIVE APPROVAL AREA INJECTION ORDER NO. 16.006 Ms. Kelly Lyons Problem Wells Supervisor ConocoPhillips Alaska, Inc. P.O. Box 100360 Anchorage, AK 99510-0360 Re: Docket Number: AIO-16-026 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.alaska.gov Request for administrative approval to allow well 2N-306 (PTD 2040620) to be online in water only injection service with a known tubing by inner annulus communication. Kuparuk River Unit (KRU) 2N-306 (PTD 2040620) Kuparuk River Field Tarn Oil Pool Dear Ms. Lyons: By letter dated June 19, 2016, ConocoPhillips Alaska, Inc. (CPAI) requested administrative approval to continue water only injection in the subject well. In accordance with Rule 10 of Area Injection Order (AIO) 16.000, the Alaska Oil and Gas Conservation Commission (AOGCC) hereby GRANTS CPAI's request for administrative approval to continue water only injection in the subject well. CPAI reported a potential Tubing (T) x Inner Annulus (IA) pressure communication to AOGCC on April 18, 2016 while the well was injecting gas. AOGCC approved a gas injection monitoring period in which the well continued to display evidence of communication. The well was WAG'ed to water for a 30 day period in which communication was not observed. CPAI performed diagnostics including a passing non -state witnessed MITIA on May 22, 2016 which indicates that 2N-306 exhibits at least two competent barriers to the release of well pressure. The well does not exhibit signs of pressure communication while on water injection. Accordingly, the AOGCC believes that the well's condition does not compromise overall well integrity so as to threaten human safety or the environment. AIO 16.006 June 23, 2016 Page 2 of 2 AOGCC's approval to continue water injection onl in KRU 2N-306 is conditioned upon the following: 1. CPAI shall record wellhead pressures and injection rate daily; 2. CPAI shall submit to the AOGCC a monthly report of well pressures, injection rates, and pressure bleeds for all annuli. Bleeds to be flagged on the report; 3. CPAI shall perform a mechanical integrity test of the inner annulus every 2 years to the maximum anticipated injection pressure; 4. CPAI shall limit the well's IA operating pressure to 2000 psi and the OA operating pressure to 1000 psi; 5. CPAI shall immediately shut in the well and notify the AOGCC if there is any change in the well's mechanical condition; 6. After well shut in due to a change in the well's mechanical condition, AOGCC approval shall be required to restart injection; and 7. The next required MIT is to be before or during the month of August 2016. This is to align with the agreed upon CPAI Underground Injection Control MIT permanent test schedule for pad testing. DONE at Anchorage, Alaska and dated June 23, 2016. Q Cathy/ . Foerster Daniel T. Seamount, Jr. Chai , Commissioner Commissioner AND APPEAL NOTICE As provided in AS 31.05.080(a), within 20 days after written notice of the entry of this order or decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration of the matter determined by it. If the notice was mailed, then the period of time shall be 23 days. An application for reconsideration must set out the respect in which the order or decision is believed to be erroneous. The AOGCC shall grant or refuse the application for reconsideration in whole or in part within 10 days after it is filed. Failure to act on it within 10-days is a denial of reconsideration. If the AOGCC denies reconsideration, upon denial, this order or decision and the denial of reconsideration are FINAL and may be appealed to superior court. The appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision denying reconsideration, UNLESS the denial is by inaction, in which case the appeal MUST be filed within 40 days after the date on which the application for reconsideration was filed. If the AOGCC grants an application for reconsideration, this order or decision does not become final. Rather, the order or decision on reconsideration will be the FINAL order or decision of the AOGCC, and it may be appealed to superior court. That appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision on reconsideration. In computing a period of time above, the date of the event or default after which the designated period begins to run is not included in the period; the last day of the period is included, unless it falls on a weekend or state holiday, in which event the period runs until 5:00 p.m. on the next day that does not fall on a weekend or state holiday. Colombie, Jody J (DOA) From: Colombie, Jody J (DOA) Sent: Thursday, June 23, 2016 3:43 PM To: Ballantine, Tab A (LAW); Bender, Makana K (DOA); Bettis, Patricia K (DOA); Bixby, Brian D (DOA); Brooks, Phoebe L (DOA); Carlisle, Samantha J (DOA); Colombie, Jody J (DOA); Cook, Guy D (DOA); Davies, Stephen F (DOA); Eaton, Loraine E (DOA); Foerster, Catherine P (DOA); Frystacky, Michal (DOA); Grimaldi, Louis R (DOA); Guhl, Meredith D (DOA); Herrera, Matthew F (DOA); Hill, Johnnie W (DOA); Jones, Jeffery B (DOA); Kair, Michael N (DOA); Link, Liz M (DOA); Loepp, Victoria T (DOA); Mumm, Joseph (DOA sponsored); Noble, Robert C (DOA); Paladijczuk, Tracie L (DOA); Pasqual, Maria (DOA); Quick, Michael J (DOA); Regg, James B (DOA); Roby, David S (DOA); Scheve, Charles M (DOA); Schwartz, Guy L (DOA); Seamount, Dan T (DOA); Singh, Angela K (DOA); Wallace, Chris D (DOA); AKDCWellIntegrityCoordinator; Alan Bailey; Alex Demarban; Alexander Bridge; Allen Huckabay; Amanda Tuttle; Andrew VanderJack; Anna Raff; Barbara F Fullmer; bbritch; bbohrer@ap.org; Bill Bredar; Bob Shavelson; Brian Havelock; Bruce Webb; Burdick, John D (DNR); Caleb Conrad; Candi English; Colleen Miller; Crandall, Krissell; D Lawrence; Dave Harbour; David Boelens; David Duffy; David House; David McCaleb; David Tetta; ddonkel@cfl.rr.com; Dean Gallegos; Delbridge, Rena E (LAS); DNROG Units (DNR sponsored); Donna Ambruz; Ed Jones; Elowe, Kristin; Evans, John R (LDZX); Frank Molli; Gary Oskolkosf, George Pollock; Gordon Pospisil; Greeley, Destin M (DOR); Gregg Nady; gspfoff, Hyun, James J (DNR); Jacki Rose; Jdarlington Oarlington@gmail.com); Jeanne McPherren; Jerry Hodgden; Jerry McCutcheon; Jim Watt; Jim White; Joe Lastufka; Radio Kenai; Easton, John R (DNR); Jon Goltz; Juanita Lovett; Judy Stanek; Houle, Julie (DNR); Julie Little; Karen Thomas; Kari Moriarty; Kazeem Adegbola; Keith Torrance; Keith Wiles; Kelly Sperback; Gregersen, Laura S (DNR); Leslie Smith; Louisiana Cutler; Luke Keller; Marc Kovak; Dalton, Mark (DOT sponsored); Mark Hanley (mark.hanley@anadarko.com); Mark Landt; Mark Wedman; Kremer, Marguerite C (DNR); Mary Cocklan-Vendl; Mealear Tauch; Michael Calkins; Michael Moora; MJ Loveland; mkm7200; Morones, Mark P (DNR); Munisteri, Islin W M (DNR); knelson@petroleumnews.com; Nichole Saunders; Nick W. Glover; Nikki Martin; NSK Problem Well Supv; Oliver Sternicki; Patty Alfaro; Paul Craig; Decker, Paul L (DNR); Paul Mazzolini; Pike, Kevin W (DNR); Randall Kanady; Randy L. Skillern; Renan Yanish; Richard Cool; Robert Brelsford; Ryan Tunseth; Sara Leverette; Scott Griffith; Shannon Donnelly; Sharmaine Copeland; Sharon Yarawsky; Shellenbaum, Diane P (DNR); Skutca, Joseph E (DNR); Smart Energy Universe; Smith, Kyle S (DNR); Sondra Stewman; Stephanie Klemmer; Stephen Hennigan; Moothart, Steve R (DNR); Steve Quinn; Suzanne Gibson; sheffield@aoga.org; Ted Kramer; Davidson, Temple (DNR); Teresa Imm; Thor Cutler; Tim Mayers; Todd Durkee; trmjrl; Tyler Senden; Vicki Irwin; Vinnie Catalano; Aaron Gluzman; Aaron Sorrell; Ajibola Adeyeye; Alan Dennis; Ann Danielson; Bajsarowicz, Caroline J; Brian Gross; Bruce Williams; Bruno, Jeff J (DNR); Casey Sullivan; Catie Quinn; D. McCraine; Don Shaw; Eric Lidji; Furie Drilling; Garrett Haag; Smith, Graham O (DNR); Dickenson, Hak K (DNR); Heusser, Heather A (DNR); Holly Pearen; J. Stuart; Jason Bergerson; Jim Magill; Joe Longo; John Martineck; Josh Kindred; Kasper Kowalewski; Laney Vazquez; Lois Epstein; Longan, Sara W (DNR); Marc Kuck; Marcia Hobson; Steele, Marie C (DNR); Matt Armstrong; Franger, James M (DNR); Morgan, Kirk A (DNR); Pat Galvin; Pete Dickinson; Peter Contreras; Richard Garrard; Richmond, Diane M; Robert Province; Ryan Daniel; Sandra Lemke; Pollard, Susan R (LAW); T. Hord; Talib Syed; Tina Grovier (tmgrovier@stoel.com); Tostevin, Breck C (LAW); Vicky Sterling; Wayne Wooster; William Van Dyke Subject: Dockets AIO 16-025 and AIO 16-026 Attachments: aio2c 036.pdf; aiol6.006.pdf Docket Number: AIO-16-025 - CPA Administrative approval to allow well 3 S-26 (PTD 2010400) to be online in water only injection service with a known tubing by inner annulus communication. Kuparuk River Unit (KRU) 3S-26 (PTD 2010400) Kuparuk River Field Kuparuk River Oil Pool Docket Number: AIO-16-026 - CPA Administrative approval to allow well 2N-306 (PTD 2040620) to be online in water only injection service with a known tubing by inner annulus communication. Kuparuk River Unit (KRU) 2N-306 (PTD 2040620) Kuparuk River Field Tarn Oil Pool Jody J. Co(ombie AOGCC Specia(Assistant ACaska Oi(andGas Conservation Commission 333 West 711 Avenue Anchorage, Alaska 99501 Office: (907) 793-1221 Fax: (907) 276-7542 CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Jody Colombie at 907.793.1221 or iodv.colombie@alaska.gov. Jack Hakkila Bernie Karl P.O. Box 190083 K&K Recycling Inc. P.O. Box 58055 Anchorage, AK 99519 Fairbanks, AK 99711 Penny Vadla George Vaught, Jr. 399 W. Riverview Ave. P.O. Box 13557 Soldotna, AK 99669-7714 Denver, CO 80201-3557 Ms. Kelly Lyons Richard Wagner Problem Wells Supervisor P.O. Box 60868 ConocoPhillips Alaska, Inc. Fairbanks, AK 99706 P.O. Box 100360 Anchorage, AK 99510-0360 Gordon Severson 3201 Westmar Cir. Anchorage, AK 99508-4336 Darwin Waldsmith P.O. Box 39309 Ninilchik, AK 99639 Angela K. Singh THE STATE 'ALASKA GOVERNOR BILL WALKER Ms. Kelly Lyons Well Integrity Supervisor ConocoPhillips Alaska, Inc. P.O. Box 100360 Anchorage, AK 99510-0360 Re: Docket Number: AIO-17-009 March 30, 2017 Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.alaska.gov �\ UU� �+��,/ L AZV 11,.0U� -v � Request to amend the Mechanical Integrity Testing (MIT) anniversary date for 97 wells which operate under existing administrative approvals. Request to amend the required MIT pressure criteria for six wells which operate under existing administrative approvals. Area Injection Orders 2B, 2C, 16, 18B, 18C, 28 and 30 Kuparuk River Unit and Colville River Unit Dear Ms. Lyons: By letter dated February 23, 2017, ConocoPhillips Alaska, Inc. (CPAI) requested administrative approval to change the MIT anniversary date on 97 wells to align with the established CPAI Underground Injection Control MIT permanent test schedule for pad testing. CPAI also requested an amendment to the required MIT pressure criteria for six wells. In accordance with Rule 9 of Area Injection Order (AIO) 02B.000, Rule 10 of AIO 16 , and Rule 11 of AIO 2C, 18B, 18C, 28, and 30, the Alaska Oil and Gas Conservation Commission (AOGCC) hereby GRANTS CPAI's request for administrative approval to amend the MIT anniversary date for the 97 wells and amend the required MIT pressure criteria for the six wells as detailed in the accompanying tables. CPAI has been working with AOGCC since late 2015 and submitted a proposal to AOGCC on March 26, 2016 looking to consolidate well testing to the established pad testing schedule which has an emphasis on summer months May through August. CPAI has been looking for efficiencies by scheduling and completing the multiple well tests required in a pad by pad sequence averaged over a four-year workload. Over the last twelve months the CPAI well integrity team has coordinated with AOGCC inspectors to witness multiple well tests and both have identified efficiencies in utilizing this pad schedule. The administrative action rules contained within the Area Injection Orders allow the AOGCC to administratively waive or amend the requirements of any rule as long as the change does not promote waste or jeopardize correlative rights, is based on sound engineering and geoscience principles, and will not result in an increased risk of fluid movement into freshwater. DONE at Anchorage, Alaska and dated March 30, 2017. CathyA. Foerster Chair, Commissioner aniel T. Seamount, Jr. Commissioner Hollis French Commissioner RECONSIDERATION AND APPEAL NOTICE As provided in AS 31.05.080(a), within 20 days after written notice of the entry of this order or decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration of the matter determined by it. If the notice was mailed, then the period of time shall be 23 days. An application for reconsideration must set out the respect in which the order or decision is believed to be erroneous. The AOGCC shall grant or refuse the application for reconsideration in whole or in part within 10 days after it is filed. Failure to act on it within 10-days is a denial of reconsideration. If the AOGCC denies reconsideration, upon denial, this order or decision and the denial of reconsideration are FINAL and may be appealed to superior court. The appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision denying reconsideration, UNLESS the denial is by inaction, in which case the appeal MUST be filed within 40 days after the date on which the application for reconsideration was filed. If the AOGCC grants an application for reconsideration, this order or decision does not become final. Rather, the order or decision on reconsideration will be the FINAL order or decision of the AOGCC, and it may be appealed to superior court. That appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision on reconsideration. In computing a period of time above, the date of the event or default after which the designated period begins to run is not included in the period; the last day of the period is included, unless it falls on a weekend or state holiday, in which event the period runs until 5:00 p.m. on the next day that does not fall on a weekend or state holiday. PTD # Well name AIO # New Anniversary Test Month 1981630 KUPARUK RIV U TARN 2N-325 AIO 16.001 August 2018 1982400 KUPARUK RIV U TARN 2L-305 AIO 16.002 August 2018 2071120 KUPARUK RIV U TARN 2L-319 AIO 16.003 August 2018 2100280 KUPARUK RIV U TARN 2L-310 AIO 16.004 August 2018 1982510 KUPARUK RIV U TARN 2L-323 AIO 16.005 August 2018 2032250 COLVILLE RIV UNIT CDI-07 AIO 1813.006 June 2017 2010060 COLVILLE RIV UNITCDI-21 AIO 1813.007 June 2017 2061420 COLVILLE RIV NAWK CD4-321 AIO 18C.002 June 2017 2061180 COLVILLE RIV UNIT CD4-17 AIO 18C.003 June 2017 2040240 COLVILLE RIV UNIT CD1-46 AIO 18C.004 June 2017 2071010 COLVILLE RIV NAN-K CD4-322 AIO 18C.005 June 2017 2010380 COLVILLE RIV UNIT CD1-14 AIO 18C.006 June 2017 2060650 COLVILLE RIV NAWN CD4-209 AIO 28.003 June 2017 1851090 KUPARUK RIV UNIT 2Z-16 AIO 213.002 August 2015 1960900 KUPARUK RIV UNIT 2M-09A AIO 213.004 June 2016 1951930 KUPARUK RIV UNIT 30-21 AIO 213.005 August 2018 1830960 KUPARUK RIV UNIT 2C-07 AIO 2B.007 August 2015 2001940 KUPARUK RIV UNIT 1A-04A AIO 2B.011 July 2017 1951810 KUPARUK RIV UNIT 3R-25 AIO 26.012 August 2018 2000260 KUPARUK RIV UNIT 3K-22A AIO 26.013 May 2017 1881200 KUPARUK RIV UNIT 2K-03 AIO 26.016 June 2017 1890590 KUPARUK RIV UNIT 2K-10 AIO 26.017 June 2017 1861960 KUPARUK RIV UNIT 3Q-05 AIO 26.019 August 2018 1841060 KUPARUK RIV UNIT 2G-10 AIO 26.030 May 2018 1880590 KUPARUK RIV UNIT 30-10 AIO 213.033 June 2017 1821300 KUPARUK RIV UNIT 1G-01 AIO 213.035 July 2017 1841510 KUPARUK RIV UNIT 2D-04 AIO 213.037 August 2017 1831560 KUPARUK RIV UNIT 2F-13 AIO 213.039 July 2018 1861780 KUPARUK RIV UNIT 3Q-15 AIO 26.042 August 2018 1890740 KUPARUK RIV UNIT 2K-12 AIO 26.048 June 2017 1811780 KUPARUK RIV UNIT IA-12 AIO 2B.049 July 2017 1830520 KUPARUK RIV UNIT 1Y-09 AIO 26.051 July 2017 1841520 KUPARUK RIV UNIT 2D-02 AIO 26.052 August 2017 1841230 KUPARUK RIV UNIT 1L-05 AIO 213.054 June 2018 1831760 KUPARUK RIV UNIT 2V-05 AIO 213.055 June 2018 1830620 KUPARUK RIV UNIT 1Y-08 AIO 2B.056 July 2017 2100490 KUPARUK RIV UNIT 3N-16A AIO 26.057 August 2018 1811360 KUPARUK RIV UNIT 16-11 AIO 26.060 June 2017 1861640 KUPARUK RIV UNIT 3K-11 AIO 26.061 May 2017 1852280 KUPARUK RIV UNIT 3F-04 AIO 26.063 June 2017 1831070 KUPARUK RIV UNIT 2X-05 AIO 26.064 June 2017 2101810 KUPARUK RIV UNIT 1E-08A AIO 213.065 June 2018 1950920 KUPARUK RIV UNIT 2T-28 AIO 26.066 June 2017 1851140 KUPARUK RIV UNIT 36-10 AIO 26.067 June 2017 1911250 KUPARUK RIV UNIT 3Q-01 AIO 213.068 August 2018 1841010 KUPARUK RIV UNIT 2D-10 AIO 213.070 August 2017 1831610 KUPARUK RIV UNIT 2V-02 AIO 213.071 June 2017 2120950 KUPARUK RIV UNIT 3N-11A AIO 213.072 August 2018 1840290 IKUPARUK RIV UNIT 26-10 AIO 213.073 May 2018 1831870 KUPARUK RIV UNIT 2F-04 AIO 213.074 July 2018 1820310 KUPARUK RIV UNIT 1A-16RD AIO 2B.075 July 2017 1840960 KUPARUK RIV UNIT 21-1-13 AIO 26.076 May 2018 1822140 KUPARUK RIV UNIT 1E-22 AIO 2B.078 June 2018 1821320 KUPARUK RIV UNIT 1F-05 AIO 2B.080 June 2018 2100130 KUPARUK RIV UNIT 1E-15A AIO 2B.081 June 2018 1861790 KUPARUK RIV UNIT 3Q-16 AIO 26.082 August 2018 1900350 KUPARUK RIV UNIT 1L-10 AIO 2B.083 June 2018 1850180 KUPARUK RIV UNIT 2U-05 AIO 213.084 August 2018 1830890 KUPARUK RIV UNIT 2C-03 AIO 26.085 August 2017 1830950 KUPARUK RIV UNIT 2C-08 AIO 26.086 August 2017 1852460 KUPARUK RIV UNIT 3F-08 AIO 26.087 June 2017 1851520 KUPARUK RIV UNIT 111-15 AIO 26.088 May 2017 1852720 KUPARUK RIV UNIT 3F-11 AIO 213.089 June 2017 1850440 KUPARUK RIV UNIT 1Q-13 AIO 213.090 July 2017 1830940 KUPARUK RIV UNIT 2C-04 AIO 2B.091 August 2015 1860960 KUPARUK RIV UNIT 2T-10 AIO 2B.092 June 2017 1841920 KUPARUK RIV UNIT 1Q-09 AIO 26.093 July 2017 1861410 KUPARUK RIV UNIT 2T-02 AIO 2C.001 June 2017 1861890 KUPARUK RIV UNIT 3Q-12 AIO 2C.002 August 2018 1870780 KUPARUK RIV UNIT 31-1-06 AIO 2C.003 June 2017 1901320 KUPARUK RIV UNIT 3G-23 AIO 2C.004 August 2017 1850750 KUPARUK RIV UNIT 313-05 AIO 2C.005 June 2017 1821720 KUPARUK RIV UNIT 1F-04 AIO 2C.006 June 2018 2140470 KUPARUK RIV UNIT 2T-32A AIO 2C.007 June 2017 1841450 KUPARUK RIV UNIT 1L-07 AIO 2C.008 June 2018 1840700 KUPARUK RIV UNIT 21-1-03 AIO 2C.009 May 2018 2000770 KUPARUK RIV UNIT 1D-38 AIO 2C.010 July 2018 1901210 KUPARUK RIV UNIT 3G-15 AIO 2C.011 August 2017 1840220 KUPARUK RIV UNIT 26-06 AIO 2C.012 May 2018 1852160 KUPARUK RIV UNIT 3J-08 AIO 2C.013 July 2018 1830510 KUPARUK RIV UNIT 1Y-10 AIO 2C.014 July 2017 1840860 KUPARUK RIV UNIT 21-1-15 AIO 2C.015 May 2018 1870790 KUPARUK RIV UNIT 31-1-07 AIO 2C.016 June 2017 1951210 KUPARUK RIV UNIT 1Q-24 AIO 2C.017 July 2017 2012090 KUPARUK RIV UNIT IF-16A AIO 2C.018 June 2018 1841180 KUPARUK RIV UNIT 2G-01 AIO 2C.019 May 2018 1911320 KUPARUK RIV UNIT 2M-19 AIO 2C.020 June 2018 1920710 KUPARUK RIV UNIT 2M-27 AIO 2C.021 June 2018 1950170 KUPARUK RIV UNIT 2T-18 AIO 2C.023 June 2017 1840240 KUPARUK RIV UNIT 213-07 AIO 2C.024 May 2018 1851160 KUPARUK RIV UNIT 36-12 AIO 2C.025 June 2017 1880290 KUPARUK RIV UNIT 30-17 AIO 2C.026 June 2017 1971120 KUPARUK RIV UNIT 1B-08A AIO 2C.027 June 2017 1850770 KUPARUK RIV UNIT 3B-07 AIO 2C.028 June 2017 1840800 KUPARUK RIV UNIT 2G-05 AIO 2C.029 May 2016 2100310 COLVILLE RIV FIORD CD3-123 AIO 30.005 February 2018 2110240 COLVILLE RIV FIORD CD3-198 AIO 30.006 February 2018 PTD # Well name AIO # Amended MIT pressure criteria CPAI shall perform an MIT -IA every 2 years to the maximum 2060650 COLVILLE RIV NAWN CD4-209 AIO 28.003 anticipated injection pressure. CPAI shall perform an MIT -IA every 2 years to the maximum 1881200 KUPARUK RIV UNIT 2K-03 AIO 26.016 anticipated injection pressure. CPAI shall perform an MIT -IA every 2 years to the maximum 1890590 KUPARUK RIV UNIT 2K-10 AIO 26.017 anticipated injection pressure. CPAI shall perform an MIT -IA every 2 years to the maximum 1861960 KUPARUK RIV UNIT 3Q-05 AIO 213.019 anticipated injection pressure. CPAI shall perform an MIT -IA every 2 years to the maximum 1811360 KUPARUK RIV UNIT 16-11 AIO 213.060 anticipated injection pressure. CPAI shall perform an MIT -IA every 2 years to the maximum 1861640 KUPARUK RIV UNIT 3K-11 AIO 26.061 anticipated injection pressure. `l' 1 I F STATE. "ALASKA March 30, 2017 Ms. Kelly Lyons Well Integrity Supervisor ConocoPhillips Alaska, Inc. P.O. Box 100360 Anchorage, AK 99510-0360 Re: Docket Number: AIO-17-009 Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 aogcc.alaska.gov Request to amend the Mechanical Integrity Testing (MIT) anniversary date for 97 wells which operate under existing administrative approvals. Request to amend the required MIT pressure criteria for six wells which operate under existing administrative approvals. Area Injection Orders 2B, 2C, 16, 18B, 18C, 28 and 30 Kuparuk River Unit and Colville River Unit Dear Ms. Lyons: By letter dated February 23, 2017, ConocoPhillips Alaska, Inc. (CPAI) requested administrative approval to change the MIT anniversary date on 97 wells to align with the established CPAI Underground Injection Control MIT permanent test schedule for pad testing. CPAI also requested an amendment to the required MIT pressure criteria for six wells. In accordance with Rule 9 of Area Injection Order (AIO) 02B.000, Rule 10 of AIO 16, and Rule 11 of AIO 2C, 18B,18C, 28, and 30, the Alaska Oil and Gas Conservation Commission (AOGCC) hereby GRANTS CPAI's request for administrative approval to amend the MIT anniversary date for the 97 wells and amend the required MIT pressure criteria for the six wells as detailed in the accompanying tables. CPAI has been working with AOGCC since late 2015 and submitted a proposal to AOGCC on March 26, 2016 looking to consolidate well testing to the established pad testing schedule which has an emphasis on summer months May through August. CPAI has been looking for efficiencies by scheduling and completing the multiple well tests required in a pad by pad sequence averaged over a four-year workload. Over the last twelve months the CPAI well integrity team has coordinated with AOGCC inspectors to witness multiple well tests and both have identified efficiencies in utilizing this pad schedule. The administrative action rules contained within the Area Injection Orders allow the AOGCC to administratively waive or amend the requirements of any rule as long as the change does not promote waste of jeopardize correlative rights, is based on sound engineering and geoscience principles, and will not result in an increased risk of fluid movement into freshwater. DONE at Anchorage, Alaska and dated March 30, 2017. //signature on file// Cathy P. Foerster Chair, Commissioner //signature on file// Daniel T. Seamount, Jr. Commissioner //signature on file// Hollis French Commissioner TION AND APPEAL NOTICE As provided in AS 31.05.080(a), within 20 days after written notice of the entry of this order or decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration of the matter determined by it. If the notice was mailed, then the period of time shall be 23 days. An application for reconsideration must set out the respect in which the order or decision is believed to be erroneous. The AOGCC shall grant or refuse the application for reconsideration in whole or in part within 10 days after it is filed. Failure to act on it within 10-days is a denial of reconsideration. If the AOGCC denies reconsideration, upon denial, this order or decision and the denial of reconsideration are FINAL and may be appealed to superior court. The appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision denying reconsideration, UNLESS the denial is by inaction, in which case the appeal MUST be filed within 40 days after the date on which the application for reconsideration was filed. If the AOGCC grants an application for reconsideration, this order or decision does not become final. Rather, the order or decision on reconsideration will be the FINAL order or decision of the AOGCC, and it may be appealed to superior court. That appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision on reconsideration. In computing a period of time above, the date of the event or default after which the designated period begins to run is not included in the period; the last day of the period is included, unless it falls on a weekend or state holiday, in which event the period runs until 5:00 p.m. on the next day that does not fall on a weekend or state holiday. PTD # Well name AIO # New Anniversary Test Month 1981630 KUPARUK RIV U TARN 2N-325 AIO 16.001 August 2018 1982400 KUPARUK RIV U TARN 2L-305 AIO 16.002 August 2018 2071120 KUPARUK RIV U TARN 2L-319 AIO 16.003 August 2018 2100280 IKUPARUK RIV U TARN 2L-310 AIO 16.004 August 2018 1982510 KUPARUK RIV U TARN 2L-323 AIO 16.005 August 2018 2032250 COLVILLE RIV UNIT CD1-07 AIO 18B.006 June 2017 2010060 COLVILLE RIV UNIT CD1-21 AIO 1813.007 June 2017 2061420 COLVILLE RIV NAWK CD4-321 AIO 18C.002 June 2017 2061180 COLVILLE RIV UNIT CD4-17 AIO 18C.003 June 2017 2040240 COLVILLE RIV UNIT CD1-46 AIO 18C.004 June 2017 2071010 COLVILLE RIV NAWK CD4-322 AIO 18C.005 June 2017 2010380 COLVILLE RIV UNIT CD1-14 AIO 18C.006 June 2017 2060650 COLVILLE RIV NAWN CD4-209 AIO 28.003 June 2017 1851090 KUPARUK RIV UNIT 2Z-16 AIO 26.002 August 2015 1960900 KUPARUK RIV UNIT 2M-09A AIO 2B.004 June 2016 1951930 KUPARUK RIV UNIT 3Q-21 AIO 2B.005 August 2018 1830960 KUPARUK RIV UNIT 2C-07 AIO 213.007 August 2015 2001940 KUPARUK RIV UNIT 1A-04A AIO 2B.011 July 2017 1951810 KUPARUK RIV UNIT 311-25 AIO 28.012 August 2018 2000260 KUPARUK RIV UNIT 3K-22A AIO 213.013 May 2017 1881200 KUPARUK RIV UNIT 2K-03 AIO 26.016 June 2017 1890590 KUPARUK RIV UNIT 2K-10 AIO 213.017 June 2017 1861960 KUPARUK RIV UNIT 3Q-05 AIO 213.019 August 2018 1841060 KUPARUK RIV UNIT 2G-10 AIO 213.030 May 2018 1880590 KUPARUK RIV UNIT 30-10 AIO 28.033 June 2017 1821300 KUPARUK RIV UNIT 1G-01 AIO 213.035 July 2017 1841510 KUPARUK RIV UNIT 2D-04 AIO 26.037 August 2017 1831560 KUPARUK RIV UNIT 2F-13 AIO 26.039 July 2018 1861780 KUPARUK RIV UNIT 3Q-15 AIO 2B.042 August 2018 1890740 KUPARUK RIV UNIT 2K-12 AIO 2B.048 June 2017 1811780 KUPARUK RIV UNIT 1A-12 AIO 2B.049 July 2017 1830520 KUPARUK RIV UNIT 1Y-09 AIO 213.051 July 2017 1841520 KUPARUK RIV UNIT 2D-02 AIO 213.052 August 2017 1841230 KUPARUK RIV UNIT 1L-05 AIO 26.054 June 2018 1831760 KUPARUK RIV UNIT 2V-05 AIO 213.055 June 2018 1830620 KUPARUK RIV UNIT 1Y-08 AIO 213.056 July 2017 2100490 KUPARUK RIV UNIT 3N-16A AIO 213.057 August 2018 1811360 KUPARUK RIV UNIT 113-11 AIO 28.060 June 2017 1861640 KUPARUK RIV UNIT 3K-11 AIO 213.061 May 2017 1852280 KUPARUK RIV UNIT 3F-04 AIO 2B.063 June 2017 1831070 KUPARUK RIV UNIT 2X-05 AIO 26.064 June 2017 2101810 KUPARUK RIV UNIT 1E-08A AIO 26.065 June 2018 1950920 KUPARUK RIV UNIT 2T-28 AIO 213.066 June 2017 1851140 KUPARUK RIV UNIT 313-10 AIO 2B.067 June 2017 1911250 KUPARUK RIV UNIT 3Q-01 AIO 26.068 August 2018 1841010 KUPARUK RIV UNIT 2D-10 AIO 26.070 August 2017 1831610 KUPARUK RIV UNIT 2V-02 AIO 2B.071 June 2017 2120950 KUPARUK RIV UNIT 3N-11A AIO 2B.072 August 2018 1840290 KUPARUK RIV UNIT 2B-10 AIO 26.073 May 2018 1831870 KUPARUK RIV UNIT 2F-04 AIO 26.074 July 2018 1820310 KUPARUK RIV UNIT 1A-16RD AIO 213.075 July 2017 1840960 KUPARUK RIV UNIT 2H-13 AIO 28.076 May 2018 1822140 KUPARUK RIV UNIT 1E-22 AIO 213.078 June 2018 1821320 KUPARUK RIV UNIT 1F-05 AIO 213.080 June 2018 2100130 KUPARUK RIV UNIT 1E-15A AIO 2B.081 June 2018 1861790 KUPARUK RIV UNIT 3Q-16 AIO 213.082 August 2018 1900350 KUPARUK RIV UNIT 1L-10 AIO 213.083 June 2018 1850180 KUPARUK RIV UNIT 2U-05 AIO 2B.084 August 2018 1830890 KUPARUK RIV UNIT 2C-03 AIO 28.085 August 2017 1830950 KUPARUK RIV UNIT 2C-08 AIO 2B.086 August 2017 1852460 KUPARUK RIV UNIT 3F-08 AIO 213.087 June 2017 1851520 KUPARUK RIV UNIT 1R-15 AIO 26.088 May 2017 1852720 KUPARUK RIV UNIT 3F-11 AIO 26.089 June 2017 1850440 KUPARUK RIV UNIT 1Q-13 AIO 213.090 July 2017 1830940 KUPARUK RIV UNIT 2C-04 AIO 213.091 August 2015 1860960 KUPARUK RIV UNIT 2T-10 AIO 26.092 June 2017 1841920 KUPARUK RIV UNIT 1Q-09 AIO 26.093 July 2017 1861410 KUPARUK RIV UNIT 2T-02 AIO 2C.001 June 2017 1861890 KUPARUK RIV UNIT 3Q-12 AIO 2C.002 August 2018 1870780 KUPARUK RIV UNIT 3H-06 AIO 2C.003 June 2017 1901320 KUPARUK RIV UNIT 3G-23 AIO 2C.004 August 2017 1850750 KUPARUK RIV UNIT 313-05 AIO 2C.005 June 2017 1821720 KUPARUK RIV UNIT IF-04 AIO 2C.006 June 2018 2140470 KUPARUK RIV UNIT 2T-32A AIO 2C.007 June 2017 1841450 KUPARUK RIV UNIT 1L-07 AIO 2C.008 June 2018 1840700 KUPARUK RIV UNIT 2H-03 AIO 2C.009 May 2018 2000770 KUPARUK RIV UNIT 113-38 AIO 2C.010 July 2018 1901210 KUPARUK RIV UNIT 3G-15 AIO 2C.011 August 2017 1840220 KUPARUK RIV UNIT 26-06 AIO 2C.012 May 2018 1852160 KUPARUK RIV UNIT 3J-08 AIO 2C.013 July 2018 1830510 KUPARUK RIV UNIT 1Y-10 AIO 2C.014 July 2017 1840860 KUPARUK RIV UNIT 2H-15 AIO 2C.015 May 2018 1870790 KUPARUK RIV UNIT 3H-07 AIO 2C.016 June 2017 1951210 KUPARUK RIV UNIT 1Q-24 AIO 2C.017 July 2017 2012090 KUPARUK RIV UNIT 1F-16A AIO 2C.018 June 2018 1841180 KUPARUK RIV UNIT 2G-01 AIO 2C.019 May 2018 1911320 KUPARUK RIV UNIT 2M-19 AIO 2C.020 June 2018 9-20710 KUPARUK RIV UNIT 2M-27 AIO 2C.021 June 2018 1950170 KUPARUK RIV UNIT 2T-18 AIO 2C.023 June 2017 1840240 KUPARUK RIV UNIT 26-07 AIO 2C.024 May 2018 1851160 KUPARUK RIV UNIT 36-12 AIO 2C.025 June 2017 1880290 KUPARUK RIV UNIT 30-17 AIO 2C.026 June 2017 1971120 KUPARUK RIV UNIT 1B-08A AIO 2C.027 June 2017 1850770 KUPARUK RIV UNIT 36-07 AIO 2C.028 June 2017 1840800 KUPARUK RIV UNIT 2G-05 AIO 2C.029 May 2016 2100310 COLVILLE RIV FIORD CD3-123 AIO 30.005 February 2018 2110240 COLVILLE RIV FIORD CD3-198 AIO 30.006 February 2018 PTD # Well name AIO # Amended MIT pressure criteria CPAI shall perform an MIT -IA every 2 years to the maximum 2060650 COLVILLE RIV NAWN CD4-209 AIO 28.003 anticipated injection pressure. CPAI shall perform an MIT -IA every 2 years to the maximum 1881200 KUPARUK RIV UNIT 2K-03 AIO 26.016 anticipated injection pressure. CPAI shall perform an MIT -IA every 2 years to the maximum 1890590 KUPARUK RIV UNIT 2K-10 AIO 213.017 anticipated injection pressure. CPAI shall perform an MIT -IA every 2 years to the maximum 1861960 KUPARUK RIV UNIT 3Q-05 AIO 2B.019 anticipated injection pressure. CPAI shall perform an MIT -IA every 2 years to the maximum 1811360 KUPARUK RIV UNIT 113-11 AIO 26.060 anticipated injection pressure. CPAI shall perform an MIT -IA every 2 years to the maximum 1861640 KUPARUK RIV UNIT 3K-11 AIO 2B.061 anticipated injection pressure. Bernie Karl K8:K Recycling Inc. Gordon Severson Penny Vadla P.O. Box 58055 3201 Westmar Cir. 399 W. Riverview Ave. Fairbanks, AK 99711-0055 Anchorage, AK 99508-4336 Soldotna, AK 99669-7714 George Vaught, Jr. Darwin Waldsmith Richard Wagner P.O. Box 13557 P.O. Box 39309 P.O. Box 60868 Denver, CO 80201-3557 Ninilchik, AK 99639-0309 Fairbanks, AK 99706-0868 Singh, Angela K (DOA) From: Colombie, Jody J (DOA) Sent: Thursday, March 30, 20171:37 PM To: DOA AOGCC Prudhoe Bay, Bender, Makana K (DOA); Bettis, Patricia K (DOA); Brooks, Phoebe L (DOA); Carlisle, Samantha J (DOA); Colombie, Jody J (DOA); Davies, Stephen F (DOA); Eaton, Loraine E (DOA); Foerster, Catherine P (DOA); French, Hollis (DOA); Frystacky, Michal (DOA); Guhl, Meredith D (DOA); Kair, Michael N (DOA); Link, Liz M (DOA); Loepp, Victoria T (DOA); Mumm, Joseph (DOA sponsored); Paladijczuk, Tracie L (DOA); Pasqual, Maria (DOA); Quick, Michael J (DOA); Regg, James B (DOA); Roby, David S (DOA); Schwartz, Guy L (DOA); Seamount, Dan T (DOA); Singh, Angela K (DOA); Wallace, Chris D (DOA); AK, GWO Projects Well Integrity; AKDCWellIntegrityCoordinator, Alan Bailey, Alex Demarban; Alexander Bridge; Allen Huckabay; Andrew VanderJack, Ann Danielson; Anna Raff; Barbara F Fullmer, bbritch; bbohrer@ap.org; Ben Boettger, Bill Bredar, Bob Shavelson; Brandon Viator; Brian Havelock; Bruce Webb; Caleb Conrad; Candi English; Cocklan-Vendl, Mary E; Colleen Miller, Connie Downing; Crandall, Krissell; D Lawrence; Dale Hoffman; Darci Horner, Dave Harbour, David Boelens; David Duffy, David House; David McCaleb; David McCraine; David Tetta; ddonkel@cfl.rr.com; DNROG Units (DNR sponsored); Donna Ambruz; Ed Jones; Elizabeth Harball; Elowe, Kristin; Elwood Brehmer, Evan Osborne; Evans, John R (LDZX); George Pollock, Gordon Pospisil; Greeley, Destin M (DOR); Gretchen Stoddard; gspfoff, Hunter Cox, Hurst, Rona D (DNR); Hyun, James J (DNR); Jacki Rose; Jdarlington Oarlington@gmaii.com); Jeanne McPherren; Jerry Hodgden; Jill Simek; Jim Watt; Jim White; Joe Lastufka; Radio Kenai; Burdick, John D (DNR); Easton, John R (DNR); Larsen, John M (DOR); John Stuart; Jon Goltz, Chmielowski, Josef (DNR); Juanita Lovett, Judy Stanek; Kari Moriarty, Kasper Kowalewski; Kazeem Adegbola; Keith Torrance; Keith Wiles, Kelly Sperback; Frank, Kevin J (DNR); Kruse, Rebecca D (DNR); Gregersen, Laura S (DNR); Leslie Smith; Lori Nelson; Louisiana Cutler, Luke Keller, Marc Kovak; Dalton, Mark (DOT sponsored); Mark Hanley (mark.hanley@anadarko.com); Mark Landt, Mark Wedman; Mealear Tauch; Michael Bill; Michael Calkins; Michael Moora; MJ Loveland; mkm7200; Motteram, Luke A, Mueller, Marta R (DNR); Munisteri, Islin W M (DNR); knelson@petroleumnews.com; Nichole Saunders; Nikki Martin; NSK Problem Well Supv; Patty Alfaro; Paul Craig; Decker, Paul L (DNR); Paul Mazzolini; Pike, Kevin W (DNR); Randall Kanady; Renan Yanish; Richard Cool; Robert Brelsford; Ryan Tunseth; Sara Leverette; Scott Griffith; Shahla Farzan; Shannon Donnelly, Sharon Yarawsky, Skutca, Joseph E (DNR); Smart Energy Universe; Smith, Kyle S (DNR); Stephanie Klemmer, Stephen Hennigan; Sternicki, Oliver R, Moothart, Steve R (DNR); Steve Quinn; Suzanne Gibson; sheffield@aoga.org; Ted Kramer, Teresa Imm; Thor Cutler, Tim Jones; Tim Mayers; Todd Durkee, trmjrl; Tyler Senden; Umekwe, Maduabuchi P (DNR); Vinnie Catalano; Well Integrity, Well Integrity, Weston Nash; Whitney Pettus; Aaron Gluzman; Aaron Sorrell; Ajibola Adeyeye; Alan Dennis; Assmann, Aaron A; Bajsarowicz, Caroline J; Bruce Williams; Bruno, Jeff J (DNR); Casey Sullivan; Catie Quinn; Corey Munk, Don Shaw, Eric Lidji; Garrett Haag; Smith, Graham O (DNR); Dickenson, Hak K (DNR); Heusser, Heather A (DNR); Fair, Holly S (DNR); Holly Pearen; Jamie M. Long; Jason Bergerson; Jesse Chielowski; Jim Magill; Joe Longo; John Martineck; Josh Kindred; Laney Vazquez; Lois Epstein; Longan, Sara W (DNR); Marc Kuck; Marcia Hobson; Steele, Marie C (DNR); Matt Armstrong; Franger, James M (DNR); Morgan, Kirk A (DNR); Umekwe, Maduabuchi P (DNR); Pat Galvin; Pete Dickinson; Peter Contreras, Richard Garrard; Richmond, Diane M; Robert Province; Ryan Daniel; Sandra Lemke, Pollard, Susan R (LAW); Talib Syed; Tina Grovier (tmgrovier@stoel.com); Tostevin, Breck C (LAW); Wayne Wooster, William Van Dyke Subject: Various Administrative Approvals for ConocoPhillips and Hilcorp Alaska Attachments: co462.007.pdf, MIT schedule 2017 approval.pdf, Anniversary dates 2017 attachment.pdf Please see attached. Re: Docket Number: CO-17-001 Application to administratively amend Rule 3 of Conservation Order No. 462 Duck Island Unit Endicott Oil Pool Re: Docket Number: AIO-17-009 Request to amend the Mechanical Integrity Testing (MIT) anniversary date for 97 wells which operate under existing administrative approvals. Request to amend the required MIT pressure criteria for six wells which operate under existing administrative approvals. Area Injection Orders 2B, 2C, 16, 1813, 18C, 28 and 30 Kuparuk River Unit and Colville River Unit %t?L1Lr �. C.(il(?ttil�iE tjc(: -Special "s_sisiant nl�i�ka. Oil r.71,1cf C�as CanseiwatioYi Coirylrtlissiratl. <limcdinrcige, „<1lisha �)950] CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Jody Colombie at 907.793.1221 or iody.colombie@alaska.gov. THE STATE ALASKA GOVERNOR MIKE DUNLEAVY ADMINISTRATIVE APPROVAL AREA INJECTION ORDER NO. 16.007 Ms. Kelly Lyons Well Integrity Supervisor ConocoPhillips Alaska, Inc. P.O. Box 100360 Anchorage, AK 99510-0360 Re: Docket Number: AIO-19-009 Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 v .aogcc.olosko.gov Request for administrative approval to allow well 2N -337C (PTD 2141210) to be online in water only injection service with a known tubing by inner annulus communication. Kuparuk River Unit (KRU) 2N -337C (PTD 2141210) Kuparuk River Field Tarn Oil Pool Dear Ms. Lyons: By letter dated March 17, 2019, ConocoPhillips Alaska, Inc. (CPAI) requested administrative approval to continue water only injection in the subject well. In accordance with Rule 10 of Area Injection Order (AIO) 16.000, the Alaska Oil and Gas Conservation Commission (AOGCC) hereby GRANTS CPAI's request for administrative approval to continue water only injection in the subject well. CPAI reported a potential tubing (T) by Inner Annulus (IA) pressure communication to AOGCC on January 31, 2019 while the well was injecting gas. CPAI WAG'ed the well from gas to water for an AOGCC approved 30 day monitoring period in which there were no fiu•ther signs of pressure communication. CPAI performed diagnostics including a passing non -state witnessed Mechanical Integrity Test of the Inner Annulus (MITIA) on February 4, 2019 which indicates that 2N -337C exhibits at least two competent barriers to the release of well pressure. The well does not exhibit signs of pressure communication while on water injection. Accordingly, the AOGCC believes that the well's condition does not compromise overall well integrity so as to threaten human safety or the environment. AIO 16.007 March 27, 2019 Page 2 of 2 AOGCC's approval to continue water injection only in KRU 2N -337C is conditioned upon the following: 1. CPAI shall record wellhead pressures and injection rate daily; 2. CPAI shall submit to the AOGCC a monthly report of well pressures, injection rates, and pressure bleeds for all annuli. Bleeds to be flagged on the report; 3. CPAI shall perform a mechanical integrity test of the inner annulus every 2 years to the maximum anticipated injection pressure, but not less than 1500 psi; 4. CPAI shall limit the well's IA operating pressure to 2000 psi and the OA operating pressure to 1000 psi; 5. CPAI shall immediately shut in the well and notify the AOGCC if there is any change in the well's mechanical condition; 6. After well shut in due to a change in the well's mechanical condition, AOGCC approval shall be required to restart injection; and 7. The next required MIT is to be before or during the month of August 2020. This is to align with the agreed upon CPAI Underground Injection Control MIT permanent test schedule for pad testing. DONE at Anchorage, Alaska and dated March 27, 2019. Daniel T. Seamount, Jr. ssie L. Chmielowski Commissioner Commissioner As provided in AS 31.05.080(a), within 20 days after written notice of the entry of this order or decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration of the matter determined by it. If the notice was mailed, then the period of time shall be 23 days. An application for reconsideration must set out the respect in which the order or decision is believed to be erroneous. The AOGCC shall grant or refuse the application for reconsideration in whole or in part within 10 days after it is filed. Failure to act on it within 10 -days is a denial of reconsideration. If the AOGCC denies reconsideration, upon denial, this order or decision and the denial of reconsideration are FINAL and may be appealed to superior court. The appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision denying reconsideration, UNLESS the denial is by inaction, in which case the appeal MUST be filed within 40 days after the date on which the application for reconsideration was filed. If the AOGCC grants an application for reconsideration, this order or decision does not become final. Rather, the order or decision on reconsideration will be the FINAL order or decision of the AOGCC, and it may be appealed to superior court. That appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision on reconsideration. In computing a period of time above, the date of the event or default after which the designated period begins to run is not included in the period; the last day of the period is included, unless it falls on a weekend or state holiday, in which event the period runs until 5:00 p.m. on the next day that does not fall on a weekend or state holiday. THF STATE "ALASKA GOCF.RNORMICILI.EI ) DUNLEAVY ADMINISTRATIVE APPROVAL AREA INJECTION ORDER NO. 16.007 Ms. Kelly Lyons Well Integrity Supervisor ConocoPhillips Alaska, Inc. P.O. Box 100360 Anchorage, AK 99510-0360 Re: Docket Number: AIO-19-009 Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.olaska.gov Request for administrative approval to allow well 2N -337C (PTD 2141210) to be online in water only injection service with a known tubing by inner annulus communication. Kuparuk River Unit (KRU) 2N -337C (PTD 2141210) Kuparuk River Field Tam Oil Pool Dear Ms. Lyons: By letter dated March 17, 2019, ConocoPhillips Alaska, Inc. (CPAI) requested administrative approval to continue water only injection in the subject well. In accordance with Rule 10 of Area Injection Order (AIO) 16.000, the Alaska Oil and Gas Conservation Commission (AOGCC) hereby GRANTS CPAI's request for administrative approval to continue water only injection in the subject well. CPAI reported a potential tubing (T) by Inner Annulus (IA) pressure communication to AOGCC on January 31, 2019 while the well was injecting gas. CPAI WAG'ed the well from gas to water for an AOGCC approved 30 -day monitoring period in which there were no further signs of pressure communication. CPAI performed diagnostics including a passing non -state witnessed Mechanical Integrity Test of the Inner Annulus (MITIA) on February 4, 2019 which indicates that 2N -337C exhibits at least two competent barriers to the release of well pressure. The well does not exhibit signs of pressure communication while on water injection. Accordingly, the AOGCC believes that the well's condition does not compromise overall well integrity so as to threaten human safety or the environment. AOGCC's approval to continue water iniection only in KRU 2N -337C is conditioned upon the following: 1. CPAI shall record wellhead pressures and injection rate daily; AIO 16.007 March 27, 2019 Page 2 of 2 2. CPAI shall submit to the AOGCC a monthly report of well pressures, injection rates, and pressure bleeds for all annuli. Bleeds to be flagged on the report; 3. CPAI shall perform a mechanical integrity test of the inner annulus every 2 years to the maximum anticipated injection pressure, but not less than 1500 psi; 4. CPAI shall limit the well's IA operating pressure to 2000 psi and the OA operating pressure to 1000 psi; 5. CPAI shall immediately shut in the well and notify the AOGCC if there is any change in the well's mechanical condition; 6. After well shut in due to a change in the well's mechanical condition, AOGCC approval shall be required to restart injection; and 7. The next required MIT is to be before or during the month of August 2020. This is to align with the agreed upon CPAI Underground Injection Control MIT permanent test schedule for pad testing. DONE at Anchorage, Alaska and dated March 27, 2019. �5�,niLaR,Q('� !� .-. A' i I' -,ZJ //signature on file// //signature on file// Daniel T. Seamount, Jr. Jessie L. Chmielowski ; Commissioner Commissioner ("T ��rrnN ��- As provided in AS 31.05.080(a), within 20 days after written notice of the entry of this order or decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration of the matter determined by it. If the notice was mailed, then the period of time shall be 23 days. An application for reconsideration must set out the respect in which the order or decision is believed to be erroneous. The AOGCC shall grant or refuse the application for reconsideration in whole or in part within 10 days after it is filed. Failure to act on it within 10 -days is a denial of reconsideration. If the AOGCC denies reconsideration, upon denial, this order or decision and the denial of reconsideration are FINAL and may be appealed to superior court. The appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision denying reconsideration, UNLESS the denial is by inaction, in which case the appeal MUST be filed within 40 days after the date on which the application for reconsideration was filed. If the AOGCC grants an application for recoasidemtion, this order or decision does not become final. Rather, the order or decision on reconsideration will be the FINAL order or decision of the AOGCC, and it may be appealed to superior court. That appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision on reconsideration. In computing a period of time above, the date of the event m default after which the designated period begins ro nm is not included in the period; the last day of the period is included, unless it falls on a weekend or state holiday, in which event the period runs until 5:00 p.m. on the next day that does not fall on a weekend or state holiday. Carlisle, Samantha J (DOA) From: Carlisle, Samantha J (DOA) Sent: Thursday, March 28, 2019 10:33 AM To: 'AOGCC_Public_Notices@list.state.ak.us' Subject: Area Injection Order 16.007 (Kuparuk River Unit) Attachments: aiol6.007.pdf Docket Number: AIO-19-009 Request for administrative approval to allow well 2N -337C (PTD 2141210) to be online in water only injection service with a known tubing by inner annulus communication. Kuparuk River Unit (KRU) 2N -337C (PTD 21412 10) Kuparuk River Field Tarn Oil Pool Samantha Carlisle Executive Secretary III Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage, AK 99501 (907) 793-1223 CONFIDENTIALITY NOTICE: This e-mail message, including anv attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you. contact Samantha Carlisle at (907) 793-1223 or Samantha.Ctu-lislaiaalaska.eov. Bernie Karl Gordon Severson Penny Vadla K&K Recycling Inc. 3201 Westmar Cir. 399 W. Riverview Ave. P.O. Box 58055 Anchorage, AK 99508-4336 Soldotna, AK 99669-7714 Fairbanks, AK 99711 George Vaught, Jr. Darwin Waldsmith Richard Wagner P.O. Box 13557 P.O. Box 39309 P.O. Box 60868 Denver, CO 80201-3557 Ninilchik, AK 99639 Fairbanks, AK 99706 THE STATE °fALASKA GOVERNOR MIKE DUNLEAVY Alaska Oil and Gas Conservation Commission ADMINISTRATIVE APPROVAL AREA INJECTION ORDER NO. 16.004 AMENDED Mr. Jan Byrne Well Integrity Supervisor ConocoPhillips Alaska, Inc. P.O. Box 100360 Anchorage, AK 99510-0360 Re: Docket Number: AIO-19-014 333 west Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax 907.276.7542 Ww .aogcc.alaska.gov Request for administrative approval to allow well 2L-310 (PTD 2100280) to be online in water alternating gas (WAG) injection service with a known tubing by inner annulus communication. Kuparuk River Unit (KRU) 2L-310 (PTD 2100280) Kuparuk River Field Tarn Oil Pool Dear Mr. Byrne: By letter dated April 9, 2019, ConocoPhillips Alaska, Inc. (CPAI) requested administrative approval to amend Area Injection Order (AIO) 16.004 to change from water only injection to WAG in the subject well. In accordance with Rule 10 of Area Injection Order (AIO) 16.000, the Alaska Oil and Gas Conservation Commission (AOGCC) hereby GRANTS CPAI's request for administrative approval to allow WAG injection in the subject well. CPAI reported a potential Tubing x Inner Annulus pressure communication to AOGCC on February 3, 2014 while on miscible injectant (MI) injection service and on April 14, 2014 AOGCC approved AIO 16.004 to allow water only injection to continue. The well does not exhibit signs of pressure communication while on water injection. CPAI has recently changed an internal policy to allow WAG injection in wells that can meet certain criteria. CPAI has implemented the criteria and during the AOGCC approved gas injection monitoring period the IA pressure build up rate decreased from an initial 55 psi per day to 5 psi per day which AOGCC finds CPAI is able to manage with periodic pressure bleeds. CPAI has real time monitoring and alarm notifications of IA and OA pressures on 2L -pad wells. CPAI performed diagnostics including a passing non -state witnessed mechanical integrity test of the Inner Annulus (MITIA) on August 10, 2018 which indicates that 2L-310 exhibits at least two competent barriers to the release of well pressure. AIO 16.004 Amended April 17, 2019 Page 2 of 2 Accordingly, the AOGCC believes that the well's condition does not compromise overall well integrity so as to threaten human safety or the environment AOGCC's approval to continue WAG injection in KRU 2L-310 is conditioned upon the following: 1. CPAI shall record wellhead pressures and injection rate daily; 2. CPAI shall submit to the AOGCC a monthly report of well pressures, injection rates, and pressure bleeds for all annuli. A maximum of two non -thermal related IA bleeds per month while injecting gas. Bleeds to be flagged on the report; 3. CPAI shall perform a mechanical integrity test of the inner annulus (MITIA) every 2 years to the maximum anticipated injection pressure, but not less than 1500 psi; 4. CPAI shall perform a mechanical integrity test of the outer annulus (MITOA) every 2 years to not less than 1200 psi or a passing surface casing leak detect (SCLD) log; 5. CPAI shall limit the well's IA operating pressure to 2400 psi and the OA operating pressure to 1000 psi while on gas injection; 6. CPAI shall limit the well's IA operating pressure to 2000 psi and the OA operating pressure to 1000 psi while on water injection; 7. CPAI shall maintain real time monitoring and alarm notifications preset on the IA and OA; 8. CPAI shall immediately shut in the well and notify the AOGCC if there is any change in the well's mechanical condition; W 10. After well shut in due to a change in the well's mechanical condition, AOGCC approval shall be required to restart injection; and The next required MIT is to be before or during the month of August 2020. This is to align with the agreed upon CPAI Underground Injection Control MIT permanent test schedule for pad testing. DONE aattAAnchorage, Alaska and dated April 17,, '20019. Daniel T. Seamount, Jr. J 6e L=ielowski Commissioner Commissioner As provided in AS 31.05,080(a), within 20 days after written notice of the entry of this order or decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration of the matter determined by it. If the notice was mailed, then the period of time shall be 23 days. An application for reconsideration must set out the respect in which the order or decision is believed to be erroneous. The AOGCC shall grant or refuse the application for reconsideration in whole or in part within 10 days after it is filed. Failure to act on it within 10 -days is a denial of reconsideration. If the AOGCC denies reconsideration, upon denial, this order or decision and the denial of reconsideration are FINAL and may be appealed to superior court. The appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision denying reconsideration, UNLESS the denial is by inaction, in which case the appeal MUST be filed within 40 days after the date on which the application for reconsideration was filed. If the AOGCC grants an application for reconsideration, this order or decision does not become final. Rather, the order or decision on reconsideration will be the FINAL order or decision of the AOGCC, and it may be appealed to superior court. That appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision on reconsideration. In computing aperiod of time above, the date of the event or default after which the designated period begins to run is not included in the period; the last day of the period is included, unless it falls on a weekend or state holiday, in which event the period runs until 5:00 p.m. on the next day that does not fall on a weekend or state holiday. THE STATE "ALASKA GOVERNOR MICH.QIEL J. DUNLEAVY Alaska Oil and Gas Conservation Commission ADMINISTRATIVE APPROVAL AREA INJECTION ORDER NO. 16.004 AMENDED Mr. Jan Byrne Well Integrity Supervisor ConocoPhillips Alaska, Inc. P.O. Box 100360 Anchorage, AK 99510-0360 Re: Docket Number: AIO-19-014 333 west Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.alaska.gov Request for administrative approval to allow well 2L-310 (PTD 2100280) to be online in water alternating gas (WAG) injection service with a known tubing by inner annulus communication. Kuparuk River Unit (KRU) 2L-310 (PTD 2100280) Kuparuk River Field Tarn Oil Pool Dear Mr. Byrne: By letter dated April 9, 2019, ConocoPhillips Alaska, Inc. (CPAI) requested administrative approval to amend Area Injection Order (AIO) 16.004 to change from water only injection to WAG in the subject well. In accordance with Rule 10 of Area Injection Order (AIO) 16.000, the Alaska Oil and Gas Conservation Commission (AOGCC) hereby GRANTS CPAI's request for administrative approval to allow WAG injection in the subject well. CPAI reported a potential Tubing x Inner Annulus pressure communication to AOGCC on February 3, 2014 while on miscible injectant (MI) injection service and on April 14, 2014 AOGCC approved AIO 16.004 to allow water only injection to continue. The well does not exhibit signs of pressure communication while on water injection. CPAI has recently changed an internal policy to allow WAG injection in wells that can meet certain criteria. CPAI has implemented the criteria and during the AOGCC approved gas injection monitoring period the IA pressure build up rate decreased from an initial 55 psi per day to 5 psi per day which AOGCC finds CPAI is able to manage with periodic pressure bleeds. CPAI has real time monitoring and alarm notifications of IA and OA pressures on 2L -pad wells. CPAI performed diagnostics including a passing non -state witnessed mechanical integrity test of the Inner Annulus (MITIA) on August 10, 2018 which indicates that 2L-310 exhibits at least two competent barriers to the release of well pressure. A10 16.004 Amended April 17, 2019 Page 2 of 2 Accordingly, the AOGCC believes that the well's condition does not compromise overall well integrity so as to threaten human safety or the environment AOGCC's approval to continue WAG injection in KRU 2L-310 is conditioned upon the following: 1. CPA] shall record wellhead pressures and injection rate daily; 2. CPAI shall submit to the AOGCC a monthly report of well pressures, injection rates, and pressure bleeds for all annuli. A maximum of two non -thermal related IA bleeds per month while injecting gas. Bleeds to be flagged on the report; 3. CPAI shall perform a mechanical integrity test of the inner annulus (MITIA) every 2 years to the maximum anticipated injection pressure, but not less than 1500 psi; 4. CPA] shall perform a mechanical integrity test of the outer annulus (MITOA) every 2 years to not less than 1200 psi or a passing surface casing leak detect (SCLD) log; 5. CPAI shall limit the well's IA operating pressure to 2400 psi and the OA operating pressure to 1000 psi while on gas injection; 6. CPAI shall I imit the well's IA operating pressure to 2000 psi and the OA operating pressure 8. ZI 10. to 1000 psi while on water injection; CPAI shall maintain real time monitoring and alarm notifications preset on the IA and OA; CPAI shall immediately shut in the well and notify the AOGCC if there is any change in the well's mechanical condition; After well shut in due to a change in the well's mechanical condition, AOGCC approval shall be required to restart injection; and The next required MIT is to be before or during the month of August 2020. This is to align with the agreed upon CPAI Underground Injection Control MIT permanent test schedule for pad testing. DONE at Anchorage, Alaska and dated April 17, 2019. //signature on file// Daniel T. Seamount, Jr. Commissioner //signature on file// Jessie L. Chmielowski Commissioner As provided in AS 31.05.080(a), within 20 days after written notice of the entry of this order or decision, or such further time w the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration of the matter determined by it. If the notice was mailed, then the period of time shall be 23 days. An application for reconsideration must set out the respect in which the order or decision is believed to be erroneous. The AOGCC shall grant or refuse the application for reconsideration in whole or in part within 10 days after it is filed. Failure to act on it within 10 -days is a denial of reconsideration, If the AOGCC denies reconsideration, upon denial, this order or decision and the denial of reconsideration are FINAL and may be appealed to superior court. The appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision denying reconsideration, UNLESS the denial is by inaction, in which case the appeal MUST be filed within 40 days after the date on which the application for reconsideration was filed. If the AOGCC grants an application for reconsideration, this order or decision does not become final. Rather, the order or decision on reconsideration will be the FINAL order or decision of the AOGCC, and it may be appealed to superior court. That appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision on reconsideration. In computing a period of time above, the date of the event or default after which the designated period begins to run is not included in the period; the Iasi day of the period is included, unless it falls on a weekend or state holiday, in which event the period runs until 5:00 p.m. on the next day that does not fall on a weekend or state holiday. Bernie Karl K&K Recycling Inc. P.O. Box 58055 Fairbanks, AK 99711 Gordon Severson 3201 Westmar Cir. Anchorage, AK 99508-4336 Penny Vadla 399 W. Riverview Ave. Soldotna, AK 99669-7714 George Vaught, Jr. Darwin Waldsmith Richard Wagner P.O. Box 13557 P.O. Box 39309 P.O. Box 60868 Denver, CO 80201-3557 Ninilchik, AK 99639 Fairbanks, AK 99706 Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.alaska.gov ADMINISTRATIVE APPROVAL AREA INJECTION ORDER NO. 16.002 AMENDED Mr. Dusty Freeborn Well Integrity Specialist ConocoPhillips Alaska, Inc. P.O. Box 100360 Anchorage, AK 99510-0360 Re: Docket Number: AIO-22-016 Request to Amend Area Injection Order 16.002: Water Alternating Gas Injection Operations Kuparuk River Unit (KRU) 2L-305 (PTD 1982400), Tarn Oil Pool Dear Mr. Freeborn: By letter dated July 6, 2022, ConocoPhillips Alaska, Inc. (CPAI) requested administrative approval to amend Area Injection Order (AIO) 16.002 to include water alternating gas (WAG) injection with a known inner annulus (IA) repressurization. In accordance with 20 AAC 25.556(d) 1, the Alaska Oil and Gas Conservation Commission (AOGCC) hereby GRANTS, subject to conditions, CPAI’s request to amend the administrative approval to continue WAG injection in the subject well. CPAI reported a potential IA repressurization to AOGCC on June 18, 2011, while the well was on miscible gas injection (MI). CPAI performed diagnostics and confirmed the IA repressurization was only present during gas injection. AOGCC issued AIO 16.002 on December 21, 2011, restricting the well to water-only injection. CPAI has recently changed an internal policy to allow WAG injection in wells that have casing rated to support the higher pressures of gas injection should a barrier fail, and that can meet stringent testing criteria. CPAI has performed additional diagnostics including a passing non-state witnessed mechanical integrity test (MIT) of the inner annulus (to a test pressure greater than the anticipated gas injection pressure of 3,900 psi) on April 27, 2022. CPAI has also performed a passing surface casing leak detect (SCLD) log/MIT of the outerannulus to 1,200 psi on April 30, 2022, as well as a passing IA draw down test. This indicates that 2L-305 exhibits at least two competent barriers to the release of well pressure. CPAI has installed an injection line choke and surface safety valve (SSV) on 2L-pad wells. Both of these devices have remote shut down capability by the Kuparuk Board Operator. Combining this with 1 The application asked for an administrative approval under Rule 10 of AIO 16, which granted the AOGCC the authority to administratively amend the order. This rule was made obsolete on February 10, 2018, when 20 AAC 25.556(d) became effective and authorized the AOGCC to administratively amend any order it has issued. AIO 16.002 Amended August 2, 2022 Page 2 of 3 live transmitters on the inner and outer annulus and the alarm functions in the Supervisory Control and Data Acquisition (SCADA) system create robust layers of protection from an over-pressure event. These inner and outer annulus alarms and shut-in protocols combined with the planned inner and outer annulus operating pressure limits enable AOGCC to remove the original water-only restriction and re-authorize gas injection. AOGCC believes CPAI can safely manage the IA repressurization with periodic pressure bleeds by maintaining the inner annulus to a pressure not to exceed 2,400 psi when on gas injection and 2,000 psi when injecting water. Accordingly, the AOGCC believes that the well’s condition does not compromise overall well integrity so as to threaten human safety or the environment. AOGCC’s approval to continue WAG injection in KRU 2L-305is conditioned upon the following: 1. CPAI shall record wellhead pressures and injection rate daily; 2. CPAI shall submit to the AOGCC a monthly report of well pressures, injection rates, and pressure bleeds for all annuli. Bleeds to be flagged on the report; 3. CPAI shall perform a MIT of the inner annulus every two years to the greater of the maximum anticipated injection pressure or 0.25 x packer TVD, but not less than 1500 psi; 4. CPAI shall perform a mechanical integrity test of the outer annulus (MITOA) every 2 years to not less than 1200 psi or a passing surface casing leak detect (SCLD) log; 5. CPAI shall limit the well’s inner annulus operating pressure to 2,400 psi when on gas injection and 2,000 psi when on water injection. Audible control room alarms shall be set at or below these limits; 6. CPAI shall limit the well’s outer annulus operating pressure to 1,000 psi. Audible control room alarms shall be set at or below these limits; 7. CPAI shall maintain the injection line choke and SSV remote shut down protocols. This will include a drill site operator outer annulus high alarm set at 1000 psi. During gas injection, the inner annulus protocols will include a drill site operator high alarm set at 2,200 psi, and a high high alarm set at 2,400 psi that will prompt the control room Board Operator (manned 24 hours a day) to remotely shut in the choke or SSV. 8. CPAI shall monitor the inner and outer annulus pressures in real time with its SCADA system; 9. CPAI shall immediately shut in the well and notify the AOGCC if there is any change in the well's mechanical condition; 10. After well shut in due to a change in the well's mechanical condition, AOGCC approval shall be required to restart injection; and 11. The next required MIT shall be completed before or during the month of August 2022. This is to align with the agreed upon CPAI Underground Injection Control MIT permanent test schedule for pad testing. DONE at Anchorage, Alaska and dated August 2, 2022. Daniel T. Seamount, Jr. Jessie L. Chmielowski Commissioner Commissioner Daniel Seamount Digitally signed by Daniel Seamount Date: 2022.08.02 12:04:49 -08'00' Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2022.08.02 13:46:02 -08'00' AIO 16.002 Amended August 2, 2022 Page 3 of 3 RECONSIDERATION AND APPEAL NOTICE As provided in AS 31.05.080(a), within 20 days after written notice of the entry of this order or decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration of the matter determined by it. If the notice was mailed, then the period of time shall be 23 days. An application for reconsideration must set out the respect in which the order or decision is believed to be erroneous. The AOGCC shall grant or refuse the application for reconsideration in whole or in part within 10 days after it is filed. Failure to act on it within 10 days is a denial of reconsideration. If the AOGCC denies reconsideration, upon denial, this order or decision and the denial of reconsideration are FINAL and may be appealed to superior court. The appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision denying reconsideration, UNLESS the denial is by inaction, in which case the appeal MUST be filed within 40 days after the date on which the application for reconsideration was filed. If the AOGCC grants an application for reconsideration, this order or decision does not become final. Rather, the order or decision on reconsideration will be the FINAL order or decision of the AOGCC, and it may be appealed to superior court. That appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision on reconsideration. In computing a period of time above, the date of the event or default after which the designated period begins to run is not included in the period; the last day of the period is included, unless it falls on a weekend or state holiday, in which event the period runs until 5:00 p.m. on the next day that does not fall on a weekend or state holiday. From:Carlisle, Samantha J (OGC) To:AOGCC_Public_Notices Subject:[AOGCC_Public_Notices] Area Injection Orders 16.002, .003, and .006 amended (Kuparuk River Unit) Date:Tuesday, August 2, 2022 3:22:58 PM Attachments:aio16.002 amended.pdf aio16.003 amended.pdf aio16.006 amended.pdf Samantha Carlisle AOGCC Special Assistant Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage, AK 99501 (907) 793-1223 __________________________________ List Name: AOGCC_Public_Notices@list.state.ak.us You subscribed as: samantha.carlisle@alaska.gov Unsubscribe at: https://list.state.ak.us/mailman/options/aogcc_public_notices/samantha.carlisle%40alaska.gov Bernie Karl K&K Recycling Inc. P.O. Box 58055 Fairbanks, AK 99711 mailed 8/2/22 Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.alaska.gov ADMINISTRATIVE APPROVAL AREA INJECTION ORDER NO. 16.003 AMENDED Mr. Dusty Freeborn Well Integrity Specialist ConocoPhillips Alaska, Inc. P.O. Box 100360 Anchorage, AK 99510-0360 Re: Docket Number: AIO-22-017 Request to Amend Area Injection Order 16.003: Water Alternating Gas Injection Operations Kuparuk River Unit (KRU) 2L-319 (PTD 2071120), Tarn Oil Pool Dear Mr. Freeborn: By letter dated July 7, 2022, ConocoPhillips Alaska, Inc. (CPAI) requested administrative approval to amend Area Injection Order (AIO) 16.003 to include water alternating gas (WAG) injection with a known tubing by inner annulus (TxIA) pressure communication. In accordance with 20 AAC 25.556(d) 1, the Alaska Oil and Gas Conservation Commission (AOGCC) hereby GRANTS, subject to conditions, CPAI’s request to amend the administrative approval to continue WAG injection in the subject well. CPAI reported a potential TxIA pressure communication to AOGCC on September 23, 2021, while the well was on miscible gas injection (MI). CPAI performed diagnostics and confirmed the TxIA pressure communication was only present during gas injection. AOGCC issued AIO 16.003 on November 7, 2012, restricting the well to water-only injection. CPAI has recently changed an internal policy to allow WAG injection in wells that have casing rated to support the higher pressures of gas injection should a barrier fail, and that can meet stringent testing criteria. CPAI has performed additional diagnostics including a passing non-state witnessed mechanical integrity test (MIT) of the inner annulus (to a test pressure greater than the anticipated gas injection pressure of 3,900 psi) on May 2, 2022. CPAI has also performed a passing surface casing leak detect (SCLD) log/MIT of the outer annulus to 1,200 psi on May 3, 2022, as well as a passing IA draw down test. This indicates that 2L-319 exhibits at least two competent barriers to the release of well pressure. CPAI has installed an injection line choke and surface safety valve (SSV) on 2L-pad wells. Both of these devices have remote shut down capability by the Kuparuk Board Operator. 1 The application asked for an administrative approval under Rule 10 of AIO 16, which granted the AOGCC the authority to administratively amend the order. This rule was made obsolete on February 10, 2018, when 20 AAC 25.556(d) became effective and authorized the AOGCC to administratively amend any order it has issued. AIO 16.003 Amended August 2, 2022 Page 2 of 3 Combining this with live transmitters on the inner and outer annulus and the alarm functions in the Supervisory Control and Data Acquisition (SCADA) system create robust layers of protection from an over-pressure event. These inner and outer annulus alarms and shut-in protocols combined with the planned inner and outer annulus operating pressure limits enable AOGCC to remove the original water-only restriction and re-authorize gas injection.AOGCC believes CPAI can safely manage the TxIA communication with periodic pressure bleeds by maintaining the inner annulus to a pressure not to exceed 2,400 psi when on gas injection and 2,000 psi when injecting water. Accordingly, the AOGCC believes that the well’s condition does not compromise overall well integrity so as to threaten human safety or the environment. AOGCC’s approval to continue WAG injection in KRU 2L-319is conditioned upon the following: 1. CPAI shall record wellhead pressures and injection rate daily; 2. CPAI shall submit to the AOGCC a monthly report of well pressures, injection rates, and pressure bleeds for all annuli. Bleeds to be flagged on the report; 3. CPAI shall perform a MIT of the inner annulus every two years to the greater of the maximum anticipated injection pressure or 0.25 x packer TVD, but not less than 1500 psi; 4. CPAI shall perform a mechanical integrity test of the outer annulus (MITOA) every 2 years to not less than 1200 psi or a passing surface casing leak detect (SCLD) log; 5. CPAI shall limit the well’s inner annulus operating pressure to 2,400 psi when on gas injection and 2,000 psi when on water injection. Audible control room alarms shall be set at or below these limits; 6. CPAI shall limit the well’s outer annulus operating pressure to 1,000 psi. Audible control room alarms shall be set at or below these limits; 7. CPAI shall maintain the injection line choke and SSV remote shut down protocols. This will include a drill site operator outer annulus high alarm set at 1000 psi. During gas injection, the inner annulus protocols will include a drill site operator high alarm set at 2,200 psi, and a high high alarm set at 2,400 psi that will prompt the control room Board Operator (manned 24 hours a day) to remotely shut in the choke or SSV. 8. CPAI shall monitor the inner and outer annulus pressures in real time with its SCADA system; 9. CPAI shall immediately shut in the well and notify the AOGCC if there is any change in the well's mechanical condition; 10. After well shut in due to a change in the well's mechanical condition, AOGCC approval shall be required to restart injection; and 11. The next required MIT shall be completed before or during the month of August 2022. This is to align with the agreed upon CPAI Underground Injection Control MIT permanent test schedule for pad testing. DONE at Anchorage, Alaska and dated August 2, 2022. Daniel T. Seamount, Jr. Jessie L. Chmielowski Commissioner Commissioner Daniel Seamount Digitally signed by Daniel Seamount Date: 2022.08.02 12:06:17 -08'00' Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2022.08.02 13:46:49 -08'00' AIO 16.003 Amended August 2, 2022 Page 3 of 3 RECONSIDERATION AND APPEAL NOTICE As provided in AS 31.05.080(a), within 20 days after written notice of the entry of this order or decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration of the matter determined by it. If the notice was mailed, then the period of time shall be 23 days. An application for reconsideration must set out the respect in which the order or decision is believed to be erroneous. The AOGCC shall grant or refuse the application for reconsideration in whole or in part within 10 days after it is filed. Failure to act on it within 10 days is a denial of reconsideration. If the AOGCC denies reconsideration, upon denial, this order or decision and the denial of reconsideration are FINAL and may be appealed to superior court. The appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision denying reconsideration, UNLESS the denial is by inaction, in which case the appeal MUST be filed within 40 days after the date on which the application for reconsideration was filed. If the AOGCC grants an application for reconsideration, this order or decision does not become final. Rather, the order or decision on reconsideration will be the FINAL order or decision of the AOGCC, and it may be appealed to superior court. That appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision on reconsideration. In computing a period of time above, the date of the event or default after which the designated period begins to run is not included in the period; the last day of the period is included, unless it falls on a weekend or state holiday, in which event the period runs until 5:00 p.m. on the next day that does not fall on a weekend or state holiday. From:Carlisle, Samantha J (OGC) To:AOGCC_Public_Notices Subject:[AOGCC_Public_Notices] Area Injection Orders 16.002, .003, and .006 amended (Kuparuk River Unit) Date:Tuesday, August 2, 2022 3:22:58 PM Attachments:aio16.002 amended.pdf aio16.003 amended.pdf aio16.006 amended.pdf Samantha Carlisle AOGCC Special Assistant Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage, AK 99501 (907) 793-1223 __________________________________ List Name: AOGCC_Public_Notices@list.state.ak.us You subscribed as: samantha.carlisle@alaska.gov Unsubscribe at: https://list.state.ak.us/mailman/options/aogcc_public_notices/samantha.carlisle%40alaska.gov Bernie Karl K&K Recycling Inc. P.O. Box 58055 Fairbanks, AK 99711 mailed 8/2/22 Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.alaska.gov ADMINISTRATIVE APPROVAL AREA INJECTION ORDER NO. 16.006 AMENDED Mr. Dusty Freeborn Well Integrity Specialist ConocoPhillips Alaska, Inc. P.O. Box 100360 Anchorage, AK 99510-0360 Re: Docket Number: AIO-22-018 Request to Amend Area Injection Order 16.006: Water Alternating Gas Injection Operations Kuparuk River Unit (KRU) 2N-306 (PTD 2040620), Tarn Oil Pool Dear Mr. Freeborn: By letter dated July 7, 2022, ConocoPhillips Alaska, Inc. (CPAI) requested administrative approval to amend Area Injection Order (AIO) 16.006 to include water alternating gas (WAG) injection with a known tubing by inner annulus (TxIA) pressure communication. In accordance with 20 AAC 25.556(d) 1, the Alaska Oil and Gas Conservation Commission (AOGCC) hereby GRANTS, subject to conditions, CPAI’s request to amend the administrative approval to continue WAG injection in the subject well. CPAI reported a potential TxIA pressure communication to AOGCC on April 18, 2016, while the well was injecting gas. CPAI performed diagnostics and confirmed the TxIA pressure communication was only present during gas injection. AOGCC issued AIO 16.006 on June 23, 2016, restricting the well to water-only injection. CPAI has recently changed an internal policy to allow WAG injection in wells that have casing rated to support the higher pressures of gas injection should a barrier fail, and that can meet stringent testing criteria. CPAI has performed additional diagnostics including a passing non-state witnessed mechanical integrity test (MIT) of the inner annulus (to a test pressure greater than the anticipated gas injection pressure of 3,900 psi) on May 4, 2022. CPAI has also performed a passing surface casing leak detect (SCLD) log/MIT of the outer annulus to 1,200 psi on May 4, 2022, as well as a passing IA draw down test. This indicates that 2N-306 exhibits at least two competent barriers to the release of well pressure. CPAI has installed an injection line choke and surface safety valve (SSV) on 2N-306. Both of these devices have remote shut down capability by the Kuparuk Board Operator. Combining this with live 1 The application asked for an administrative approval under Rule 10 of AIO 16, which granted the AOGCC the authority to administratively amend the order. This rule was made obsolete on February 10, 2018, when 20 AAC 25.556(d) became effective and authorized the AOGCC to administratively amend any order it has issued. AIO 16.006 Amended August 2, 2022 Page 2 of 3 transmitters on the inner and outer annulus and the alarm functions in the Supervisory Control and Data Acquisition (SCADA) system create robust layers of protection from an over-pressure event. These inner and outer annulus alarms and shut-in protocols combined with the planned inner and outer annulus operating pressure limits enable AOGCC to remove the original water-only restriction and re-authorize gas injection. AOGCC believes CPAI can safely manage the TxIA communication with periodic pressure bleeds by maintaining the inner annulus to a pressure not to exceed 2,400 psi when on gas injection and 2,000 psi when injecting water. Accordingly, the AOGCC believes that the well’s condition does not compromise overall well integrity so as to threaten human safety or the environment. AOGCC’s approval to continue WAG injection in KRU2N-306is conditioned upon the following: 1. CPAI shall record wellhead pressures and injection rate daily; 2. CPAI shall submit to the AOGCC a monthly report of well pressures, injection rates, and pressure bleeds for all annuli. Bleeds to be flagged on the report; 3. CPAI shall perform a MIT of the inner annulus every two years to the greater of the maximum anticipated injection pressure or 0.25 x packer TVD, but not less than 1500 psi; 4. CPAI shall perform a mechanical integrity test of the outer annulus (MITOA) every 2 years to not less than 1200 psi or a passing surface casing leak detect (SCLD) log; 5. CPAI shall limit the well’s inner annulus operating pressure to 2,400 psi when on gas injection and 2,000 psi when on water injection. Audible control room alarms shall be set at or below these limits; 6. CPAI shall limit the well’s outer annulus operating pressure to 1,000 psi. Audible control room alarms shall be set at or below these limits; 7. CPAI shall maintain the injection line choke and SSV remote shut down protocols. This will include a drill site operator outer annulus high alarm set at 1000 psi. During gas injection, the inner annulus protocols will include a drill site operator high alarm set at 2,200 psi, and a high high alarm set at 2,400 psi that will prompt the control room Board Operator (manned 24 hours a day) to remotely shut in the choke or SSV. 8. CPAI shall monitor the inner and outer annulus pressures in real time with its SCADA system; 9. CPAI shall immediately shut in the well and notify the AOGCC if there is any change in the well's mechanical condition; 10. After well shut in due to a change in the well's mechanical condition, AOGCC approval shall be required to restart injection; and 11. The next required MIT shall be completed before or during the month of August 2022. This is to align with the agreed upon CPAI Underground Injection Control MIT permanent test schedule for pad testing. DONE at Anchorage, Alaska and dated August 2, 2022. Daniel T. Seamount, Jr. Jessie L. Chmielowski Commissioner Commissioner Daniel Seamount Digitally signed by Daniel Seamount Date: 2022.08.02 12:07:49 -08'00' Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2022.08.02 13:47:38 -08'00' AIO 16.006 Amended August 2, 2022 Page 3 of 3 RECONSIDERATION AND APPEAL NOTICE As provided in AS 31.05.080(a), within 20 days after written notice of the entry of this order or decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration of the matter determined by it. If the notice was mailed, then the period of time shall be 23 days. An application for reconsideration must set out the respect in which the order or decision is believed to be erroneous. The AOGCC shall grant or refuse the application for reconsideration in whole or in part within 10 days after it is filed. Failure to act on it within 10 days is a denial of reconsideration. If the AOGCC denies reconsideration, upon denial, this order or decision and the denial of reconsideration are FINAL and may be appealed to superior court. The appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision denying reconsideration, UNLESS the denial is by inaction, in which case the appeal MUST be filed within 40 days after the date on which the application for reconsideration was filed. If the AOGCC grants an application for reconsideration, this order or decision does not become final. Rather, the order or decision on reconsideration will be the FINAL order or decision of the AOGCC, and it may be appealed to superior court. That appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision on reconsideration. In computing a period of time above, the date of the event or default after which the designated period begins to run is not included in the period; the last day of the period is included, unless it falls on a weekend or state holiday, in which event the period runs until 5:00 p.m. on the next day that does not fall on a weekend or state holiday. From:Carlisle, Samantha J (OGC) To:AOGCC_Public_Notices Subject:[AOGCC_Public_Notices] Area Injection Orders 16.002, .003, and .006 amended (Kuparuk River Unit) Date:Tuesday, August 2, 2022 3:22:58 PM Attachments:aio16.002 amended.pdf aio16.003 amended.pdf aio16.006 amended.pdf Samantha Carlisle AOGCC Special Assistant Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage, AK 99501 (907) 793-1223 __________________________________ List Name: AOGCC_Public_Notices@list.state.ak.us You subscribed as: samantha.carlisle@alaska.gov Unsubscribe at: https://list.state.ak.us/mailman/options/aogcc_public_notices/samantha.carlisle%40alaska.gov Bernie Karl K&K Recycling Inc. P.O. Box 58055 Fairbanks, AK 99711 mailed 8/2/22 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.alaska.gov ADMINISTRATIVE APPROVAL AREA INJECTION ORDER NO. 16.007 Ms. Kelly Lyons Well Integrity Supervisor ConocoPhillips Alaska, Inc. P.O. Box 100360 Anchorage, AK 99510-0360 Re: Docket Number: AIO-19-009 Request for administrative approval to allow well 2N-337C (PTD 2141210) to be online in water only injection service with a known tubing by inner annulus communication. Kuparuk River Unit (KRU) 2N-337C (PTD 2141210) Kuparuk River Field Tarn Oil Pool Dear Ms. Lyons: By letter dated March 17, 2019, ConocoPhillips Alaska, Inc. (CPAI) requested administrative approval to continue water only injection in the subject well. In accordance with Rule 10 of Area Injection Order (AIO) 16.000, the Alaska Oil and Gas Conservation Commission (AOGCC) hereby GRANTS CPAI’s request for administrative approval to continue water only injection in the subject well. CPAI reported a potential tubing (T) by Inner Annulus (IA) pressure communication to AOGCC on January 31, 2019 while the well was injecting gas. CPAI WAG’ed the well from gas to water for an AOGCC approved 30-day monitoring period in which there were no further signs of pressure communication. CPAI performed diagnostics including a passing non-state witnessed Mechanical Integrity Test of the Inner Annulus (MITIA) on February 4, 2019 which indicates that 2N-337C exhibits at least two competent barriers to the release of well pressure. The well does not exhibit signs of pressure communication while on water injection. Accordingly, the AOGCC believes that the well’s condition does not compromise overall well integrity so as to threaten human safety or the environment. AOGCC’s approval to continue water injection only in KRU 2N-337C is conditioned upon the following: 1. CPAI shall record wellhead pressures and injection rate daily; AIO 16.007 March 27, 2019 Page 2 of 2 2. CPAI shall submit to the AOGCC a monthly report of well pressures, injection rates, and pressure bleeds for all annuli. Bleeds to be flagged on the report; 3. CPAI shall perform a mechanical integrity test of the inner annulus every 2 years to the maximum anticipated injection pressure, but not less than 1500 psi; 4.CPAI shall limit the well’s IA operating pressure to 2000 psi and the OA operating pressure to 1000 psi; 5. CPAI shall immediately shut in the well and notify the AOGCC if there is any change in the well's mechanical condition; 6. After well shut in due to a change in the well's mechanical condition, AOGCC approval shall be required to restart injection; and 7. The next required MIT is to be before or during the month of August 2020. This is to align with the agreed upon CPAI Underground Injection Control MIT permanent test schedule for pad testing. DONE at Anchorage, Alaska and dated March 27, 2019. //signature on file// //signature on file// Daniel T. Seamount, Jr. Jessie L. Chmielowski Commissioner Commissioner RECONSIDERATION AND APPEAL NOTICE As provided in AS 31.05.080(a), within 20 days after written notice of the entry of this order or decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration of the matter determined by it. If the notice was mailed, then the period of time shall be 23 days. An application for reconsideration must set out the respect in which the order or decision is believed to be erroneous. The AOGCC shall grant or refuse the application for reconsideration in whole or in part within 10 days after it is filed. Failure to act on it within 10-days is a denial of reconsideration. If the AOGCC denies reconsideration, upon denial, this order or decision and the denial of reconsideration are FINAL and may be appealed to superior court. The appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision denying reconsideration, UNLESS the denial is by inaction, in which case the appeal MUST be filed within 40 days after the date on which the application for reconsideration was filed. If the AOGCC grants an application for reconsideration, this order or decision does not become final. Rather, the order or decision on reconsideration will be the FINAL order or decision of the AOGCC, and it may be appealed to superior court. That appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision on reconsideration. In computing a period of time above, the date of the event or default after which the designated period begins to run is not included in the period; the last day of the period is included, unless it falls on a weekend or state holiday, in which event the period runs until 5:00 p.m. on the next day that does not fall on a weekend or state holiday. Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.alaska.gov ADMINISTRATIVE APPROVAL AREA INJECTION ORDER NO. 16.007 AMENDED Mr. Dusty Freeborn Well Integrity Specialist ConocoPhillips Alaska, Inc. P.O. Box 100360 Anchorage, AK 99510-0360 Re: Docket Number: AIO-22-024 Request to Amend Area Injection Order 16.007: Water Alternating Gas Injection Operations Kuparuk River Unit (KRU) 2N-337C (PTD 2141210), Tarn Oil Pool Dear Mr. Freeborn: By letter dated August 2, 2022, ConocoPhillips Alaska, Inc. (CPAI) requested administrative approval to amend Area Injection Order (AIO) 16.007 to include water alternating gas (WAG) injection with a known tubing by inner annulus (TxIA) pressure communication. In accordance with 20 AAC 25.556(d) 1, the Alaska Oil and Gas Conservation Commission (AOGCC) hereby GRANTS, subject to conditions, CPAI’s request to amend the administrative approval to continue WAG injection in the subject well. CPAI reported a potential TxIA pressure communication to AOGCC on January 31, 2019, while the well was injecting gas. CPAI performed diagnostics and confirmed the TxIA pressure communication was only present during gas injection. AOGCC issued AIO 16.007 on March 27, 2019, restricting the well to water-only injection. CPAI has recently changed an internal policy to allow WAG injection in wells that have casing rated to support the higher pressures of gas injection should a barrier fail, and that can meet stringent testing criteria. CPAI has performed additional diagnostics including a passing statewitnessed mechanical integrity test (MIT) of the inner annulus (to a test pressure greater than the anticipated gas injection pressure of 3,900 psi) on August 1, 2022. CPAI has also performed a passing surface casing leak detect (SCLD) log/MIT of the outer annulus to 1,200 psi on May 8, 2022, as well as a passing IA draw down test. This indicates that 2N-337C exhibits at least two competent barriers to the release of well pressure. CPAI has installed an injection line choke and surface safety valve (SSV) on 2N-337C. Both of these devices have remote shut down capability by the Kuparuk Board Operator. Combining this with live 1 The application asked for an administrative approval under Rule 10 of AIO 16, which granted the AOGCC the authority to administratively amend the order. This rule was made obsolete on February 10, 2018, when 20 AAC 25.556(d) became effective and authorized the AOGCC to administratively amend any order it has issued. AIO 16.007 Amended August 18, 2022 Page 2 of 3 transmitters on the inner and outer annulus and the alarm functions in the Supervisory Control and Data Acquisition (SCADA) system create robust layers of protection from an over-pressure event. These inner and outer annulus alarms and shut-in protocols combined with the planned inner and outer annulus operating pressure limits enable AOGCC to remove the original water-only restriction and re-authorize gas injection. AOGCC believes CPAI can safely manage the TxIA communication with periodic pressure bleeds by maintaining the inner annulus to a pressure not to exceed 2,400 psi when on gas injection and 2,000 psi when injecting water. Accordingly, the AOGCC believes that the well’s condition does not compromise overall well integrity so as to threaten human safety or the environment. AOGCC’s approval to continue WAG injection in KRU 2N-337C is conditioned upon the following: 1. CPAI shall record wellhead pressures and injection rate daily; 2. CPAI shall submit to the AOGCC a monthly report of well pressures, injection rates, and pressure bleeds for all annuli. Bleeds to be flagged on the report; 3. CPAI shall perform a MIT of the inner annulus every two years to the greater of the maximum anticipated injection pressure or 0.25 x packer TVD, but not less than 1500 psi; 4. CPAI shall perform a mechanical integrity test of the outer annulus (MITOA) every 2 years to not less than 1200 psi or a passing surface casing leak detect (SCLD) log; 5. CPAI shall limit the well’s inner annulus operating pressure to 2,400 psi when on gas injection and 2,000 psi when on water injection. Audible control room alarms shall be set at or below these limits; 6. CPAI shall limit the well’s outer annulus operating pressure to 1,000 psi. Audible control room alarms shall be set at or below these limits; 7. CPAI shall maintain the injection line choke and SSV remote shut down protocols. This will include a drill site operator outer annulus high alarm set at 1000 psi. During gas injection, the inner annulus protocols will include a drill site operator high alarm set at 2,200 psi, and a high high alarm set at 2,400 psi that will prompt the control room Board Operator (manned 24 hours a day) to remotely shut in the choke or SSV. 8. CPAI shall monitor the inner and outer annulus pressures in real time with its SCADA system; 9. CPAI shall immediately shut in the well and notify the AOGCC if there is any change in the well's mechanical condition; 10. After well shut in due to a change in the well's mechanical condition, AOGCC approval shall be required to restart injection; and 11. The next required MIT shall be completed before or during the month of August 2022. This is to align with the agreed upon CPAI Underground Injection Control MIT permanent test schedule for pad testing. DONE at Anchorage, Alaska and dated August 18, 2022. Jeremy M. Price Daniel T. Seamount, Jr. Jessie L. Chmielowski Chair, Commissioner Commissioner Commissioner Daniel Seamount Digitally signed by Daniel Seamount Date: 2022.08.18 14:15:21 -08'00' Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2022.08.18 14:56:54 -08'00' Jeremy Price Digitally signed by Jeremy Price Date: 2022.08.19 08:37:52 -08'00' AIO 16.007 Amended August 18, 2022 Page 3 of 3 RECONSIDERATION AND APPEAL NOTICE As provided in AS 31.05.080(a), within 20 days after written notice of the entry of this order or decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration of the matter determined by it. If the notice was mailed, then the period of time shall be 23 days. An application for reconsideration must set out the respect in which the order or decision is believed to be erroneous. The AOGCC shall grant or refuse the application for reconsideration in whole or in part within 10 days after it is filed. Failure to act on it within 10 days is a denial of reconsideration. If the AOGCC denies reconsideration, upon denial, this order or decision and the denial of reconsideration are FINAL and may be appealed to superior court. The appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision denying reconsideration, UNLESS the denial is by inaction, in which case the appeal MUST be filed within 40 days after the date on which the application for reconsideration was filed. If the AOGCC grants an application for reconsideration, this order or decision does not become final. Rather, the order or decision on reconsideration will be the FINAL order or decision of the AOGCC, and it may be appealed to superior court. That appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision on reconsideration. In computing a period of time above, the date of the event or default after which the designated period begins to run is not included in the period; the last day of the period is included, unless it falls on a weekend or state holiday, in which event the period runs until 5:00 p.m. on the next day that does not fall on a weekend or state holiday. Bernie Karl K&K Recycling Inc. P.O. Box 58055 Fairbanks, AK 99711 mailed 3/27/22 1 Prysunka, Anne E (OGC) From:Carlisle, Samantha J (OGC) <samantha.carlisle@alaska.gov> Sent:Friday, August 19, 2022 12:04 PM To:AOGCC_Public_Notices Subject:[AOGCC_Public_Notices] Area Injection Order 16.007 amended Attachments:aio16.007 amended.pdf Request to Amend Area Injection Order 16.007: Water Alternating Gas Injection Operations Kuparuk River Unit (KRU) 2N-337C (PTD 2141210), Tarn Oil Pool Samantha Carlisle AOGCC Special Assistant Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage, AK 99501 (907) 793-1223 __________________________________ List Name: AOGCC_Public_Notices@list.state.ak.us You subscribed as: samantha.carlisle@alaska.gov Unsubscribe at: https://list.state.ak.us/mailman/options/aogcc_public_notices/samantha.carlisle%40alaska.gov Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.alaska.gov ADMINISTRATIVE APPROVAL AREA INJECTION ORDER 16.008 Ms. Jaime Bronga Well Integrity Specialist ConocoPhillips Alaska, Inc. P.O. Box 100360 Anchorage, AK 99510-0360 Re: Docket Number: AIO-25-003 Request for Administrative Approval to Area Injection Order 16; Water Injection Kuparuk River Unit (KRU) 2L-301 (PTD 2081920), Tarn Oil Pool Dear Ms. Bronga: By emailed letter dated February 3, 2025, ConocoPhillips Alaska, Inc. (CPAI) requested administrative approval to continue water only injection with a known inner annulus by outer annulus (IAxOA) pressure communication. In accordance with 20 AAC 25.556(d), the Alaska Oil and Gas Conservation Commission (AOGCC) hereby GRANTS, subject to conditions, CPAI’s request for administrative approval to continue water only injection in the subject well. CPAI reported a potential IAxOA pressure communication to AOGCC on January 9, 2025, while on water injection service. CPAI completed a passing non-state witnessed mechanical integrity test (MIT) of the inner annulus on January 10, 2025, which indicates that 2L-301 exhibits at least two competent barriers to the release of well pressure. CPAI ran passing inner casing pack off tests and a passing surface casing leak detection log which could not detect the location of the leak. AOGCC believes CPAI can safely manage the IAxOA communication with periodic pressure bleeds by allowing the OA to equalize with the IA at an OA pressure not to exceed 1,000 psi. Accordingly, the AOGCC believes that the well’s condition does not compromise overall well integrity so as to threaten human safety or the environment AOGCC’s approval to continue water only injection in KRU 2L-301 is conditioned upon the following: 1) CPAI shall record wellhead pressures and injection rate daily; 2) CPAI shall submit to the AOGCC a monthly report of well pressures, injection rates, and pressure bleeds for all annuli. Bleeds to be flagged on the report; 3) CPAI shall perform a MIT of the inner annulus every two years to the greater of the maximum anticipated injection pressure or 0.25 x packer TVD, but not less than 1,500 psi; AIO 16.008 February 5, 2025 Page 2 of 2 4) CPAI shall perform a Surface Casing Leak Detect (SCLD) log every two years on the OA rather than a MIT of the OA. It is not a requirement to have this SCLD log state-witnessed. 5) CPAI shall limit the well’s inner annulus operating pressure to 2,000 psi. Audible control room alarms shall be set at or below these limits; 6) CPAI shall limit the well’s outer annulus operating pressure to 1,000 psi. Audible control room alarms shall be set at or below these limits; 7) CPAI shall monitor the inner and outer annulus pressures in real time with its SCADA system; 8) CPAI shall immediately shut in the well and notify the AOGCC if there is any change in the well's mechanical condition; 9) After well shut in due to a change in the well's mechanical condition, AOGCC approval shall be required to restart injection; and 10) The next required MIT is to be before or during the month of August 2026. This is to align with the agreed upon CPAI Underground Injection Control MIT permanent test schedule for pad testing. DONE at Anchorage, Alaska and dated February 5, 2025. Jessie L. Chmielowski Gregory C. Wilson Commissioner Commissioner RECONSIDERATION AND APPEAL NOTICE As provided in AS 31.05.080(a), within 20 days after written notice of the entry of this order or decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration of the matter determined by it. If the notice was mailed, then the period of time shall be 23 days. An application for reconsideration must set out the respect in which the order or decision is believed to be erroneous. The AOGCC shall grant or refuse the application for reconsideration in whole or in part within 10 days after it is filed. Failure to act on it within 10 days is a denial of reconsideration. If the AOGCC denies reconsideration, upon denial, this order or decision and the denial of reconsideration are FINAL and may be appealed to superior court. The appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision denying reconsideration, UNLESS the denial is by inaction, in which case the appeal MUST be filed within 40 days after the date on which the application for reconsideration was filed. If the AOGCC grants an application for reconsideration, this order or decision does not become final. Rather, the order or decision on reconsideration will be the FINAL order or decision of the AOGCC, and it may be appealed to superior court. That appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision on reconsideration. In computing a period of time above, the date of the event or default after which the designated period begins to run is not included in the period; the last day of the period is included, unless it falls on a weekend or state holiday, in which event the period runs until 5:00 p.m. on the next day that does not fall on a weekend or state holiday. Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2025.02.05 16:00:48 -09'00' Gregory C. Wilson Digitally signed by Gregory C. Wilson Date: 2025.02.06 16:03:59 -09'00' From:Coldiron, Samantha J (OGC) To:AOGCC_Public_Notices Subject:[AOGCC_Public_Notices] Area Injection Order 16.008 (CPAI) Date:Thursday, February 6, 2025 4:23:10 PM Attachments:aio16.008.pdf Docket Number: AIO-25-003 Request for Administrative Approval to Area Injection Order 16; Water Injection Kuparuk River Unit (KRU) 2L-301 (PTD 2081920), Tarn Oil Pool Samantha Coldiron AOGCC Special Assistant Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage, AK 99501 (907) 793-1223 __________________________________ List Name: AOGCC_Public_Notices@list.state.ak.us You subscribed as: samantha.coldiron@alaska.gov Unsubscribe at: https://list.state.ak.us/mailman/options/aogcc_public_notices/samantha.coldiron%40alaska.go v Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.alaska.gov ADMINISTRATIVE APPROVALS AREA INJECTION ORDER NO. 2C.096 AREA INJECTION ORDER NO. 16.009 AREA INJECTION ORDER NO. 18E.008 AREA INJECTION ORDER NO. 28.011 AREA INJECTION ORDER NO. 35A.002 AREA INJECTION ORDER NO. 39A.001 AREA INJECTION ORDER NO. 40.005 AREA INJECTION ORDER NO. 43.003 Greg Hobbs, Regulatory Engineer ConocoPhillips Alaska, Inc. P.O. Box 100360 Anchorage, AK 99510-0360 Re: Docket Number: AIO-25-001 Request to change language of Area Injection Order Rule 7 Well Integrity and Confinement Dear Mr. Hobbs: By letter dated January 15, 2025, ConocoPhillips Alaska, Inc. (CPAI) requested the amendment to Rule 7 of the Area Injection Orders listed below: •AIO 18E: Colville River Field, Colville River Unit, Alpine Oil Pool • AIO 28: Colville River Field, Colville River Unit, Nanuq Oil Pool • AIO 35A: Colville River Field, Colville River Unit, Qannik Oil Pool • AIO 39A: Kuparuk River Field, Kuparuk River Unit, Torok Oil Pool • AIO 40: Greater Moose's Tooth Field, Greater Moose's Tooth Unit, Lookout Oil Pool • AIO 43: Greater Moose's Tooth Field, Greater Moose's Tooth and Bear Tooth Units, Rendezvous Oil Pool The purpose of the amendment is to clarify the appropriate process and current practice when pressure communication, leakage or lack of injection zone isolation is indicated by certain data observed by the operator. CPAIproposed adopting the Rule 7 language from the recently approved AIO 45 Coyote Oil Pool. AIO 2C.096, AIO 16.009, AIO 18E.008, AIO 28.011, AIO 35A.002, AIO 39A.001, AIO 40.005, and AIO 43.003 May 12, 2025 Page 2 of 3 In accordance with 20 AAC 25.556(d), the Alaska Oil and Gas Conservation Commission (AOGCC) hereby GRANTS CPAI’s request to amend Rule 7 of the AIOs listed above. Additionally, on its own motion, and in accordance with 20 AAC 25.556(d), the AOGCC has determined that Rule 7 of the CPAI AIO’s listed below should also be amended for the same reasons. • AIO 2C: Kuparuk River Field, Kuparuk River Unit, Kuparuk River, West Sak, and Tabasco Oil Pools • AIO 16: Kuparuk River Field, Kuparuk River Unit, Tarn Oil Pool Now Therefore it is Ordered: Rule 7 of each of the AIO’s listed is amended to read as follows: Rule 7 Well Integrity and Confinement Whenever an indication of pressure communication, leakage, or lack of injection zone isolation occurs, the operator must notify the AOGCC by the next business day. Such indication may arise from information including but not limited to injection rate, operating pressure observation, test, survey, log, or outer anulus pressure monitoring in wells within one-quarter mile radius of where the applicable defined oil pool is not cemented. If the operator's investigation supports a conclusion of pressure communication, leaking, or lack of injection zone isolation, the operator must submit a corrective action plan to the AOGCC, following the applicable unit sundry matrix order. The operator must shut in any well for which: (a) continued operation would be unsafe, (b) continued operation would threaten contamination of freshwater; or (c) the AOGCC directs the operator to shut in the well. The operator must submit a monthly report of daily tubing and casing annuli pressures and injection rate for injection wells that (a) are subject to administrative approval (AA) to operate; or (b) lack injection zone isolation. DONE at Anchorage, Alaska and dated May 12, 2025. Jessie L. Chmielowski Gregory C. Wilson. Commissioner, Chair Commissioner Gregory C. Wilson Digitally signed by Gregory C. Wilson Date: 2025.05.12 12:12:38 -08'00' Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2025.05.12 13:42:57 -08'00' AIO 2C.096, AIO 16.009, AIO 18E.008, AIO 28.011, AIO 35A.002, AIO 39A.001, AIO 40.005, and AIO 43.003 May 12, 2025 Page 3 of 3 RECONSIDERATION AND APPEAL NOTICE As provided in AS 31.05.080(a), within 20 days after written notice of the entry of this order or decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration of the matter determined by it. If the notice was mailed, then the period of time shall be 23 days. An application for reconsideration must set out the respect in which the order or decision is believed to be erroneous. The AOGCC shall grant or refuse the application for reconsideration in whole or in part within 10 days after it is filed. Failure to act on it within 10 days is a denial of reconsideration. If the AOGCC denies reconsideration, upon denial, this order or decision and the denial of reconsideration are FINAL and may be appealed to superior court. The appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision denying reconsideration, UNLESS the denial is by inaction, in which case the appeal MUST be filed within 40 days after the date on which the application for reconsideration was filed. If the AOGCC grants an application for reconsideration, this order or decision does not become final. Rather, the order or decision on reconsideration will be the FINAL order or decision of the AOGCC, and it may be appealed to superior court. That appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision on reconsideration. In computing a period of time above, the date of the event or default after which the designated period begins to run is not included in the period; the last day of the period is included, unless it falls on a weekend or state holiday, in which event the period runs until 5:00 p.m. on the next day that does not fall on a weekend or state holiday. From:Coldiron, Samantha J (OGC) To:AOGCC_Public_Notices Subject:[AOGCC_Public_Notices] Area Injection Orders Admin Approvals (CPAI) Date:Monday, May 12, 2025 1:54:34 PM Attachments:AIO2C.096, AIO16.009, AIO18E.008, AIO28.011, AIO35A.002, AIO39A.001, AIO40.005, and AIO43.003.pdf Docket Number: AIO-25-001 Request to change language of Area Injection Order Rule 7 Well Integrity and Confinement Samantha Coldiron AOGCC Special Assistant Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage, AK 99501 (907) 793-1223 __________________________________ List Name: AOGCC_Public_Notices@list.state.ak.us You subscribed as: samantha.coldiron@alaska.gov Unsubscribe at: https://list.state.ak.us/mailman/options/aogcc_public_notices/samantha.coldiron%40alaska.go v INDEXES 25 January 15, 2025 VIA E-MAIL DELIVERY Victoria Loepp Senior Petroleum Engineer Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue, Suite 100 Anchorage, Alaska 99501-3572 Subject: Area Injection Order Rule 7 Proposed Language Change Dear Ms. Loepp, ConocoPhillips Alaska Inc. (CPAI) makes this application to amend the Area Injection Orders listed below to clarify the appropriate process and current practice when pressure communication, leakage or lack of injection zone isolation is indicated by certain data observed by the operator. An example of the current area injection order language from the Alpine Area Injection Order (AIO 18E) is as follows: Whenever any pressure communication, leakage or lack of injection zone isolation is indicated by an injection rate, operating pressure observation, test, survey, log, or other evidence, the operator shall, by the next business day, notify the Commission and submit a plan of corrective action on a Form 10-403 for Commission approval. The Operator shall immediately shut in the well if continued operation would be unsafe or would threaten contamination of freshwater, or if so directed by the AOGCC. A monthly report of daily tubing and casing annuli pressures and injection rates must be provided to the AOGCC for all injection wells indicating well integrity failure or lack of injection zone isolation. There are two concerns with the current language. First, the rule requires the filing of a form 10-403 report with the AOGCC on the next business day. This does not represent current practice. Instead, the rule should require the Operator to notify the AOGCC by the next business day and file a report following the applicable AOGCC Sundry matrix only if the Operator’s investigation supports a conclusion of pressure communication, leaking, or lack of injection zone isolation. Second, the current rule requires the submission of daily tubing and casing annuli pressure for all injection wells indicating well integrity failure or lack of injection zone isolation. The current practice is not to submit this information for wells that are shut in. The shut in wells are separately tracked in the annual long-term shut-in wells report to the AOGCC. Greg Hobbs Principal Regulatory Engineer 700 G Street, ATO 1562 Anchorage, AK 99510 (907) 263-4749 (office) Greg.S.Hobbs@conocophillips.com By Samantha Coldiron at 12:09 pm, Jan 15, 2025 2 CPAI proposes the following language from the recent Coyote Oil Pool area injection order to resolve both issues: Whenever an indication of pressure communication, leakage, or lack of injection zone isolation occurs, the operator must notify the AOGCC by the next business day. Such indication may arise from information including but not limited to injection rate, operating pressure observation, test, survey, log, or outer anulus pressure monitoring in wells within one-quarter mile radius of where the COP is not cemented. If the operator’s investigation supports a conclusion of pressure communication, leaking, or lack of injection zone isolation, the operator must submit a corrective action plan to the AOGCC, following the [KRU, CRU or GMTU sundry matrix order as applicable]. The operator must shut in any well for which: (a) continued operation would be unsafe, (b) continued operation would threaten contamination of freshwater; or (c) the AOGCC directs the operator to shut in the well. The operator must submit a monthly report of daily tubing and casing annuli pressures and injection rate for injection wells that (a) are subject to administrative approval (AA) to operate; or (b) lack injection zone isolation. If acceptable, CPAI requests that the rule be modified in the following orders with appropriate reference to the applicable sundry matrix order: x AIO 18E: Colville River Field, Colville River Unit, Alpine Oil Pool x AIO 28: Colville River Field, Colville River Unit, Nanuq Oil Pool x AIO 35A: Colville River Field, Colville River Unit, Qannik Oil Pool x AIO 39A: Kuparuk River Field, Kuparuk River Unit, Torok Oil Pool x AIO 40: Greater Moose’s Tooth Field, Greater Moose’s Tooth Unit, Lookout Oil Pool x AIO 43: Greater Moose’s Tooth Field, Greater Moose’s Tooth and Bear Tooth Units, Rendezvous Oil Pool CPAI appreciates your consideration of this request. Feel free to contact me at 907-263-4749 or greg.s.hobbs@conocophillips.com with any questions. Sincerely, Greg Hobbs Regulatory Engineer ConocoPhillips Alaska, Inc. Digitally signed by Greg Hobbs DN: OU=Regulatory Engineer, O= ConocoPhillips Alaska Wells, CN=Greg Hobbs, E=greg.s.hobbs@ conocophillips.com Reason: I am the author of this document Location: Date: 2025.01.15 10:49:29-09'00' Foxit PDF Editor Version: 13.0.0 Greg Hobbs 24 February 3, 2025 Commissioner Jessie Chmielowski Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, AK 99501 Commissioner Chmielowski, ConocoPhillips Alaska, Inc. presents the attached proposal per AIO 2C, Rule 11, to apply for Administrative Approval to allow KRU injection well 2L-301 (PTD 208-192) to remain in water only injection service with known inner and outer annulus communication. Please contact me at jaime.bronga@conocophillips.com if you have any questions. Sincerely, Jaime Bronga Well Integrity Specialist ConocoPhillips Alaska, Inc. Digitally signed by Jaime Bronga DN: OU=Conoco Phillips Alaska, CN=Jaime Bronga, E=jaime.bronga@conocophillips.com Reason: I am the author of this document Location: Date: 2025.02.03 14:36:06-09'00' Foxit PDF Editor Version: 13.0.0 Jaime Bronga Well Integrity Specialist 2/3/2025 1 ConocoPhillips Alaska, Inc. Kuparuk Well 2L-301 (PTD 208-192) Technical Justification for Administrative Relief Request Purpose ConocoPhillips Alaska, Inc. proposes that the AOGCC approve this Administrative Relief request as per Area Injection Order 2C, Rule 11, to continue water injection only with known inner annulus by outer annulus communication for Kuparuk injection well 2L-301. Well History and Status Kuparuk River Unit well 2L-301 (PTD 208-192) was originally completed in January 16, 2009 as a development well and converted to injection in September 21, 2010. 2L-301 was reported to the Commission on the January 9, 2025 with indications of IAxOA pressure convergence while on water injection. Diagnostics conducted yielded a passing MIT- IA, passing SCLD and passing inner casing pack off tests. The IA pressure was bled below the OA pressure and the well was monitored. The IA pressure increased toward the OA pressure. This indicates the leak is in both directions. The attached TIO trend shows definite IAxOA communication with pressure differential. ConocoPhillips intends to pursue repairs if the leak worsens enough to be detectable and located. However, until the leak is detectable, ConocoPhillips requests Administrative Approval which will allow the OA to equalize with the IA at a pressure not to exceed 1000psi. Barrier and Hazard Evaluation Tubing: The 3.5” 9.3 lb/ft, L-80 tubing has integrity to the top of the packer at 14285’ RKB based on a passing MITIA and TIO trends. Production casing: The 7-5/8” 29.7 lb/ft, L-80 production casing has integrity from the formation and injection pressure based on a passing MITIA and TIO trends. Integrity is demonstrated by a passing MITIA with a known but minor leak of indeterminate location to the OA. The internal yield pressure rating of the casing is 6890 psi, the collapse resistance is 4790 psi. Surface casing: The 10-3/4” 45.5 lb/ft, L-80 surface casing has integrity based on a passing SCLD (1200psi to 1008’md). The internal yield pressure rating of the surface casing is 5209 psi. Primary barrier: The primary barrier to prevent a release from the well and provide zonal isolation is the tubing. Secondary barrier: The production casing is the secondary barrier in the event of a release. The leak does not have a measurable liquid leak rate. Tertiary barrier: The surface casing will provide a third barrier in the event of a release. Monitoring: Each well is monitored daily for wellhead pressure changes. Should additional leaks develop in the well bore it will be noted during the daily monitoring process. Any pressure trends that indicate annular communication require investigation, Commission notification, and Well Integrity Specialist 2/3/2025 2 corrective action, up to and including a shut-in of the well. T/I/O plots are compiled, reviewed, and submitted to the AOGCC for review monthly. Proposed Operating and Monitoring Plan 1. The well will be used for water injection only (no gas or MI allowed). 2. Perform 2-year MITIA to maximum anticipated injection pressure. 3. Perform 2-year non witnessed SCLD on the OA. 4. IA pressure is not to exceed 2000 psi, OA pressure is not to exceed 1000 psi. 5. Submit monthly reports of daily tubing & IA pressures, injection volumes and pressure bleeds for all annuli. 6. Shut-in the well should diagnostics, injection rates and/or pressures changes indicate further problems with appropriate notification to the AOGCC. 7. Anniversary date to be set the month of August 2026 to align the AOGCC biennial AA witnessed testing with the UIC MIT permanent 4-year scheduled pad testing. 2L-301 90-Day Bleed History WELL DATE STR-PRES END-PRES DIF-PRES CASING 2L-301 2025-01-10 262.0 100 -162.0 OA 2L-301 2025-01-10 154.0 92 -62.0 OA 2L-301 2025-01-10 205.0 217 12.0 IA 2L-301 2025-01-29 225.0 135 -90.0 OA 2L-301 2025-02-01 162.0 940 778.0 OA 2L-301 2025-02-02 940.0 400 -540.0 OA Last Tag Annotation Depth (ftKB) End Date Wellbore Last Mod By Last Tag: RKB 14,787.0 11/5/2020 2L-301 fergusp Last Rev Reason Annotation End Date Wellbore Last Mod By Rev Reason: Tag & updated composite plug to milled out & pushed to BTM. 11/5/2020 2L-301 fergusp Casing Strings Casing Description CONDUCTOR OD (in) 16 ID (in) 15.06 Top (ftKB) 28.0 Set Depth (ftKB) 116.0 Set Depth (TVD) … 116.0 Wt/Len (l… 62.50 Grade H-40 Top Thread WELDED Casing Description SURFACE OD (in) 10 3/4 ID (in) 9.95 Top (ftKB) 28.5 Set Depth (ftKB) 3,315.0 Set Depth (TVD) … 2,272.8 Wt/Len (l… 45.50 Grade L-80 Top Thread BTC Casing Description PRODUCTION OD (in) 7 5/8 ID (in) 6.87 Top (ftKB) 39.3 Set Depth (ftKB) 15,049.9 Set Depth (TVD) … 5,841.1 Wt/Len (l… 29.70 Grade L-80 Top Thread BTCM Tubing Strings Tubing Description TUBING String Ma… 3 1/2 ID (in) 2.99 Top (ftKB) 22.0 Set Depth (ft… 14,344.4 Set Depth (TVD) (… 5,377.4 Wt (lb/ft) 9.30 Grade L-80 Top Connection EUE8rdABMOD Completion Details Top (ftKB) Top (TVD) (ftKB) Top Incl (°) Item Des Com Nominal ID (in) 22.0 22.0 0.00 HANGER Tubing Hanger w/ 2.32' Pup 2.992 511.3 510.2 7.32 NIPPLE Camco 3 1/2" x 2.875" "DS" Nipple 2.875 14,226.1 5,321.6 64.68 SLEEVE-C 3 1/2" Baker CMU Sliding Sleeve w 2.813" DS profile (CLOSED 11/2/18) 2.813 14,272.1 5,342.0 62.50 PBR Seal Assembly locator "PBR" 5.87" OD x 3.00" ID 3.000 14,285.8 5,348.4 61.85 PACKER Baker FHL Packer,29.7# 7.625" OD X 2.94" ID 2.940 14,305.7 5,357.9 60.89 NIPPLE Camco 3 1/2" D Nipple w/ 2.75" profile 2.750 14,343.9 5,377.2 58.64 WLEG 3 1/2" Wireline Entry Guide OD 4.54" ID 3.00" 3.000 Other In Hole (Wireline retrievable plugs, valves, pumps, fish, etc.) Top (ftKB) Top (TVD) (ftKB) Top Incl (°) Des Com Run Date ID (in) SN 14,787. 0 5,652.6 46.45 Milled up composite bridge plug 2.73" Mill E-Z Composite Bridge Plug. Milled out and pushed to 14,338' CTM 10/03/20 (OAL 1.5') Tagged bottom 11/05/20 @ 14787' RKB. 10/3/2020 0.000 Perforations & Slots Top (ftKB) Btm (ftKB) Top (TVD) (ftKB) Btm (TVD) (ftKB) Linked Zone Date Shot Dens (shots/ft )Type Com 14,257.0 14,259.0 5,335.1 5,336.0 8/25/2020 4.0 CMT SQZ 2" Tubing Punch 4spf 0 deg ph 14,670.0 14,690.0 5,573.7 5,587.0 T2, 2L-301 1/29/2009 6.0 IPERF 2.5" HJ 2506, 60 deg phase Frac Summary Start Date 1/31/2009 Proppant Designed (lb) Proppant In Formation (lb) Stg # 1 Start Date 1/31/2009 Top Depth (ftKB) 14,670.0 Btm (ftKB) 14,690.0 Link to Fluid System Vol Clean (bbl) Vol Slurry (bbl) Mandrel Inserts St ati on N o/Top (ftKB) Top (TVD) (ftKB) Make Model OD (in) Serv Valve Type Latch Type Port Size (in) TRO Run (psi) Run Date Com 1 3,787.8 2,437.6 CAMCO KBMG 1 Gas Lift DMY BK 0.000 0.0 3/27/2009 2 7,585.6 3,492.5 CAMCO KBMG- LTS 1 Chemical DMY BK5 0.000 0.0 9/25/2010 Notes: General & Safety End Date Annotation 9/13/2010 NOTE: CONVERTED FROM PRODUCTION TO INJECTOR HORIZONTAL, 2L-301, 11/8/2020 7:50:02 AM Vertical schematic (actual) PRODUCTION; 39.3-15,049.9 IPERF; 14,670.0-14,690.0 FRAC; 14,670.0 WLEG; 14,343.9 NIPPLE; 14,305.7 PACKER; 14,285.8 PBR; 14,272.1 CMT SQZ; 14,257.0-14,259.0 SLEEVE-C; 14,226.1 CHEMICAL; 7,585.6 GAS LIFT; 3,787.8 SURFACE; 28.5-3,315.0 NIPPLE; 511.3 CONDUCTOR; 28.0-116.0 HANGER; 22.0 KUP INJ KB-Grd (ft) 28.00 Rig Release Date 1/16/2009 2L-301 ... TD Act Btm (ftKB) 15,064.0 Well Attributes Field Name TARN PARTICIPATING AREA Wellbore API/UWI 501032058800 Wellbore Status INJ Max Angle & MD Incl (°) 76.02 MD (ftKB) 7,596.85 WELLNAME WELLBORE2L-301 Annotation Last WO: End DateH2S (ppm) DateComment SSSV: NIPPLE 24-JAN-25 10:14 Well Annulus Test Report DS WL TIME DURATION STR-PRES END-PRES DIF-PRES CASING SERVICE 2L 301 1/10/2025 15:26 +002:00 135 250 -115 OUTER PWI 2L 301 1/10/2025 15:26 +002:00 205 217 -12 INNER PWI 2L 301 1/6/2025 14:29 +000:05 154 92 62 OUTER PWI 2L 301 1/1/2025 10:44 +000:10 262 100 162 OUTER PWI 2L 301 10/20/2024 17:35 +000:07 285 600 -315 INNER PWI 2L 301 8/29/2024 8:46 +000:10 1567 886 681 INNER PWI 2L 301 SI 5/22/2023 13:52 +000:07 230 530 -300 INNER PWI 2L 301 10/10/2022 9:55 +000:02 610 1050 -440 INNER PWI 2L 301 10/9/2022 9:32 +000:09 1680 100 1580 INNER PWI 2L 301 10/9/2021 12:18 +000:10 1450 1150 300 INNER PWI 2L 301 11/14/2020 8:50 +000:05 310 500 -190 INNER PWI 2L 301 10/31/2020 1:37 +000:08 1800 850 950 INNER PWI 2L 301 10/31/2020 1:37 +000:08 708 275 433 OUTER PWI 2L 301 SI 9/29/2020 10:43 +001:30 1 1 0 INNER PWI 2L 301 10/1/2019 13:27 +000:15 1880 1150 730 INNER PWI 2L 301 9/24/2019 14:34 +000:50 1184 496 688 OUTER MIS 2L 301 9/23/2019 17:28 +003:00 582 987 -405 OUTER MIS 2L 301 8/12/2019 14:05 +000:26 1985 1000 985 INNER MIS 2L 301 SI 8/8/2019 16:20 +003:00 761 875 -114 OUTER MIS 2L 301 8/7/2019 14:15 +004:00 78 880 -802 OUTER MIS 2L 301 8/6/2019 16:12 +000:23 300 104 196 OUTER MIS 2L 301 8/6/2019 16:12 +000:23 256 182 74 INNER MIS 2L 301 6/21/2019 9:58 +000:18 1500 500 1000 INNER PWI 2L 301 SI 5/26/2019 10:49 +000:03 180 100 80 INNER PWI 2L 301 SI 12/10/2018 12:18 +000:03 307 425 -118 INNER PWI 2L 301 SI 11/3/2018 17:52 +000:25 1800 500 1300 INNER PWI 2L 301 10/29/2018 12:48 +000:10 1990 1000 990 INNER PWI 2L 301 10/27/2018 9:31 +000:20 1360 765 595 INNER PWI 2L 301 10/26/2018 13:49 +000:25 1960 730 1230 INNER PWI 2L 301 10/26/2018 3:29 +000:10 2200 1400 800 INNER PWI 2L 301 SI 10/25/2018 21:36 +000:10 2304 1318 986 INNER PWI 2L 301 10/25/2018 11:17 +000:25 2320 935 1385 INNER MIS 2L 301 3/14/2017 12:02 +000:05 1200 850 350 INNER PWI 2L 301 8/28/2015 3:35 +000:05 329 645 -316 INNER PWI 2L 301 1/26/2015 2:26 +000:12 1100 500 600 INNER PWI 2L 301 12/22/2014 22:36 +000:35 2436 402 2034 INNER GIN 2L 301 10/13/2014 8:41 +000:10 150 750 -600 INNER GIN 2L 301 9/9/2014 12:25 +000:09 1170 485 685 INNER PWI 2L 301 9/8/2014 18:17 +000:04 1160 962 198 INNER PWI 2L 301 7/4/2014 16:38 +000:10 1157 977 180 INNER PWI 2L 301 6/30/2014 8:06 +000:20 2050 800 1250 INNER PWI 2L 301 6/29/2014 2:38 +000:35 2753 1950 803 INNER PWI 2L 301 12/24/2013 9:02 +000:12 1788 1239 549 INNER OIL 2L 301 11/25/2013 19:46 +000:10 1834 1237 597 INNER MIS 2L 301 9/5/2013 4:23 +000:10 2955 2700 255 INNER GIN 2L 301 2/19/2011 4:51 +000:05 354 200 154 INNER PWI 2L 301 2/16/2011 6:24 +000:25 1635 550 1085 INNER PWI 2L 301 1/30/2011 12:47 +000:00 1325 950 375 INNER PWI 2L 301 1/11/2011 17:52 +000:00 100 150 -50 INNER PWI 2L 301 1/6/2011 17:33 +000:00 1198 915 283 INNER PWI 2L 301 12/31/2010 15:24 +000:30 1500 750 750 INNER PWI Submit to: OOPERATOR: FFIELD / UNIT / PAD: DDATE: OOPERATOR REP: AAOGCC REP: Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD 208-192 Type Inj W Tubing 2000 2000 2000 2000 Type Test P Packer TVD 5348 BBL Pump 4.6 IA 207 3000 2980 2975 Interval O Test psi 1500 BBL Return 4.0 OA 136 325 325 324 Result P Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result TYPE INJ Codes TYPE TEST Codes INTERVAL Codes Result Codes W = Water P = Pressure Test I = Initial Test P = Pass G = Gas O = Other (describe in Notes) 4 = Four Year Cycle F = Fail S = Slurry V = Required by Variance I = Inconclusive I = Industrial Wastewater O = Other (describe in notes) N = Not Injecting Notes: ConocoPhillips Alaska Inc, Kuparuk / KRU / 2L-301 Non Witnessed Matt Miller 01/10/25 Notes:Non Witnessed MIT-IA to support AA Application Notes: Notes: Notes: 2L-301 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION MMechani cal Integrity Test jim.regg@alaska.gov;AOGCC.Inspectors@alaska.gov;phoebe.brooks@alaska.gov chris.wallace@alaska.gov Notes: Notes: Notes: Form 10-426 (Revised 01/2017)2L-301 MIT-IA.xlsx 23 November 11, 2024 Commissioner Jessie Chmielowski: Alaska Oil & Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, AK 99501 Commissioner Chmielowski: ConocoPhillips Alaska, Inc. presents the attached proposal per AIO 16, Rule 10, to apply for an Administrative Amendment to AIO 16.004 Amended to allow KRU Tarn injection well 2L-310 (PTD 210-028) to allow WAG injection service without bleed criteria. Currently the well has known tubing by inner annulus communication only while on gas injection. If you need additional information, please contact us at your convenience. Sincerely, Jaime Bronga Well Integrity –CPF2 –ConocoPhillips Alaska Office: +1 907-265-1053 By Samantha Coldiron at 2:09 pm, Nov 19, 2024 Digitally signed by Jaime Bronga DN: OU=Conoco Phillips Alaska, CN=Jaime Bronga, E= jaime.bronga@conocophillips.com Reason: I am the author of this document Location: Date: 2024.11.18 13:14:04-09'00' Foxit PDF Editor Version: 13.0.0 Jaime Bronga P.O. BOX 100360 ANCHORAGE, ALASKA 99510-0360 Well Integrity Supervisor 11/18/2024 1 Kuparuk River Unit Tarn Well 2L-310 (PTD 210-028) Technical Justification for Amendment to Area Injection Order 16.004 Purpose ConocoPhillips Alaska, Inc. (CPAI) requests that the AOGCC approve this Administrative Amendment to AIO 16.004 Amended, as per AIO 16, Rule 10, to allow water alternating gas (WAG) injection for Kuparuk River Unit Tarn injection well 2L-310 (PTD 210-028). Currently AIO 16.004 Amended contains monthly bleed quantity limitations. The well displays tubing by inner annulus (IA) communication only during gas injection and stabilizes below the gas IA pressure limit. Well History and Status Kuparuk River Unit Tarn well 2L-310 was completed in 2010 as a producer. It was converted to WAG injection in 2013. 2L-310 was initially reported to the Commission in February 2014 for a suspect IA pressure increase while on miscible gas injection. Diagnostics confirmed that the leak was a gas-only and the AOGCC granted CPAI’s request to for Administrative Amendment to allow the well to continue operating with water-only injection on April 14, 2014. In 2019, CPAI developed criteria under which it believes a gas injection well may operate safely with TxIA communication. Under this criteria, AIO 16.004 Amended was issued by the AOGCC on April 17, 2019. At that time CPAI proposed a limit of 2 non-thermal bleeds per month and AIO 16.0004 Amended was issued with a limit on the non thermal bleeds per month. On September 25, 2024, CPAI reported to the AOGCC that 2L-310 had exceeded its non thermal bleeds per month while on gas injection. CPAI then continued to monitor for IA pressure stabilization on gas injection and review the continued gas operability criteria with TxIA on gas. The IA pressure stabilized at 2150 psi and did not require additional bleeds. The well was WAG’ed to water injection on October 15, 2024 and still does not show any signs of TxIA on water. The well is currently on water injection. It is no longer CPAI internal policy to specify the allowable quantity of non-thermal bleeds per month. In efforts to amend waivers for consistency, CPAI proposed the removal of the limit on non-thermal bleeds per month from this Administrative Amendment to AIO 16.004 Amended. CPAI also proposed to continue to conduct the Surface Casing Leak Detection Logs every 2 years without the AOGCC witnessing. The AOGCC frequently waives the witness of SCLD Logs. CPAI proposes continue to conduct these logs as non witnessed. All other criteria for AIO 16.004 Amended are proposed to remain the same. Therefore, CPAI request an Administrative Amendment to AIO 16.004 Amended that will allow 2L-310 to resume WAG injection. P.O. BOX 100360 ANCHORAGE, ALASKA 99510-0360 Well Integrity Supervisor 11/18/2024 2 Barrier and Hazard Evaluation Barriers in place are sufficient to allow safe operation with water alternating gas injection service. Tubing: The 3-1/2”, 9.3 lb/ft, L-80 tubing has integrity to the Baker FHL packer at 9737’ MD (5238’ TVD) based on the passing MITIA to 4210 psi on August 6, 2024 and TIO trends. Production casing: The 7-5/8”, 29.7 lb/ft, L-80 production casing has integrity to the Baker FHL packer at 9737’ MD (5238’ TVD) based on the aforementioned passing MITIA and TIO trends. Surface casing: The well is completed with 10-3/4”, 45.5 lb/ft, L-80 surface casing with an internal yield pressure rating of 5210 psi. The surface casing has integrity based on the passing SCLD performed August 16, 2024 and TIO trends. Primary barrier: The primary barrier during water injection to prevent a release from the well and provide zonal isolation is the tubing, tubing patches and packer. The primary barrier during gas injection to prevent a release from the well and provide zonal isolation is the production casing. The tubing and packer also act as a limited barrier, so that the pressure build-up is manageable. Secondary barrier: The production casing is the secondary barrier during water injection, should the tubing fail. The surface casing is the secondary barrier during gas injection, should the production casing fail. Tertiary barrier: The surface casing will act as a tertiary barrier during water injection, in the unlikely case that the first two normal barriers have failures. Monitoring: This well will be monitored real time for wellhead pressure changes. The IA will be bled in order to maintain pressure within operating limits. Any pressure trends that indicate further annular communication require investigation, Commission notification, and corrective action, up to and including a shut-in of the well. TIO trends are compiled, reviewed, and submitted to the AOGCC for review on a monthly basis. Proposed Operating and Monitoring Plan 1. Well will be used for water alternating gas injection; 2. Perform a passing MITIA every 2-years to maximum anticipated injection pressure; 3. Allow operating IA pressure up to 2,400 psi during gas injection service and 2,000 psi during water injection service; operating OA pressure up to 1,000 psi; 4. Bleed pressure from the IA as necessary to maintain pressure within operating limits; 5. Submit monthly reports of daily tubing, IA, and OA pressures, injection volumes and pressure bleeds for all annuli; 6. Shut-in the well should diagnostic testing or injection rates and pressures indicate further problems with appropriate notification to the AOGCC; 7. MIT Anniversary date to be set the month of August 2026 to align the 2-year AOGCC witnessed testing with the UIC MIT permanent 4-year scheduled pad testing; P.O. BOX 100360 ANCHORAGE, ALASKA 99510-0360 Well Integrity Supervisor 11/18/2024 3 8. CPAI proposed that they conduct non witnessed SCLD log every 2 years on the OA rather than State Witnessed SCLD logs. 2L-310 90-Day Bleed History WELL DATE STR-PRES END-PRES DIF-PRES CASING 2L-310 2024-08-19 454.0 230 -224.0 OA 2L-310 2024-09-11 2500.0 1950 -550.0 IA 2L-310 2024-09-24 2265.0 1000 -1265.0 IA 2L-310 2024-09-25 2090.0 1250 -840.0 IA 2L-310 2024-10-22 1919.0 1043 -876.0 IA Last Tag Annotation Depth (ftKB) End Date Wellbore Last Mod By Last Tag: RKB 10,104.0 11/18/2019 2L-310 zembaej Last Rev Reason Annotation End Date Wellbore Last Mod By Rev Reason: SET PATCH 4/14/2020 2L-310 condijw Casing Strings Casing Description CONDUCTOR OD (in) 16 ID (in) 15.06 Top (ftKB) 28.0 Set Depth (ftKB) 112.0 Set Depth (TVD) … 112.0 Wt/Len (l… 62.50 Grade H-40 Top Thread WELDED Casing Description SURFACE OD (in) 10 3/4 ID (in) 9.95 Top (ftKB) 27.6 Set Depth (ftKB) 3,521.0 Set Depth (TVD) … 2,416.7 Wt/Len (l… 45.50 Grade L-80 Top Thread BTC Casing Description PRODUCTION OD (in) 7 5/8 ID (in) 6.87 Top (ftKB) 25.6 Set Depth (ftKB) 10,247.0 Set Depth (TVD) … 5,615.2 Wt/Len (l… 29.70 Grade L-80 Top Thread BTC-m Tubing Strings Tubing Description TUBING String Ma… 3 1/2 ID (in) 2.99 Top (ftKB) 23.3 Set Depth (ft… 9,800.0 Set Depth (TVD) (… 5,283.2 Wt (lb/ft) 9.30 Grade L-80 Top Connection EUE8rdABMOD Completion Details Top (ftKB) Top (TVD) (ftKB) Top Incl (°) Item Des Com Nominal ID (in) 23.3 23.3 0.00 HANGER FMC GEN V TUBING HANGER 2.992 516.4 515.9 4.54 NIPPLE CAMCO DS NIPPLE w/2.875" PROFILE 2.875 9,671.2 5,194.0 48.89 SLEEVE-C BAKER CMU SLIDING SLEEVE w/2.812 'D' PROFILE 2.812 9,723.8 5,229.4 46.52 PBR BAKER 80-40 PBR 2.990 9,737.2 5,238.6 46.02 PACKER BAKER FHL PACKER 2.990 9,790.3 5,276.2 44.03 NIPPLE CAMCO 'D' NIPPLE w/ 2.75" NO GO 2.750 9,799.5 5,282.8 43.69 WLEG WIRELINE ENTRY GUIDE 2.920 Other In Hole (Wireline retrievable plugs, valves, pumps, fish, etc.) Top (ftKB) Top (TVD) (ftKB) Top Incl (°) Des Com Run Date ID (in) 3,653.0 2,476.8 63.09 PATCH - UPR PKR (ME) 2.72" P2P SPACER & ANCHOR LATCH, OAL 25.09' / SN: CPP35228 / CPAL35147) 4/14/2020 1.620 3,657.0 2,478.6 63.14 SPACER 2-1/16" SPACER & ANCHOR LATCH @ 3653' RKB (ME) (OAL 25.09' / SN: CPP35228 / CPAL35147), MITT 3000 PASS. COMPLETE. 4/14/2020 1.620 3,675.0 2,486.7 63.40 SPACER 2.70" PBR, 2-1/16" SPACER PIPE, ANCHOR LATCH, OAL 31.62' / SN: CPPBR35026 / CPAL35118 4/14/2020 1.620 3,708.0 2,501.4 63.87 PATCH - LWR PKR (ME) 2.72" P2P, OAL 4.01' , SN:CPP35254 4/13/2020 1.620 6,938.0 3,929.7 62.90 PATCH 2.72" SOS UPPER PARAGON II PACKER (ser# cpp 35040) W/ 15.49' SPACER PIPE & LATCH ASSEMBLY (ser# cpal 35018) 1/15/2016 1.625 6,953.0 3,936.6 62.92 PATCH 2.72" SOS LOWER PARAGON II PACKER (ser# cpp35043) 1/15/2016 1.625 Perforations & Slots Top (ftKB) Btm (ftKB) Top (TVD) (ftKB) Btm (TVD) (ftKB) Linked Zone Date Shot Dens (shots/ft )Type Com 10,005.0 10,019.0 5,434.5 5,444.9 Bermuda, 2L- 310 6/8/2010 6.0 IPERF 2.5" Prospector RDX DP charges, 60 deg phase Frac Summary Start Date 6/10/2010 Proppant Designed (lb) Proppant In Formation (lb) Stg # 1 Start Date 6/10/2010 Top Depth (ftKB) 10,005.0 Btm (ftKB) 10,019.0 Link to Fluid System Vol Clean (bbl) Vol Slurry (bbl) Mandrel Inserts St ati on N o/Top (ftKB) Top (TVD) (ftKB) Make Model OD (in) Serv Valve Type Latch Type Port Size (in) TRO Run (psi) Run Date Com 1 3,697.2 2,496.6 Camco KBG-2- 9 1 GAS LIFT DMY INT 0.000 4/12/2020 2 8,716.8 4,728.9 Camco KBG-2- 9 1 GAS LIFT DMY INT 0.000 0.0 5/12/2010 5:00 3 9,617.2 5,159.3 Camco KBG-2- 9 1 GAS LIFT DMY INT 0.000 0.0 5/12/2013 1:00 Notes: General & Safety End Date Annotation 5/15/2014 NOTE: WAIVERED FOR WAG INJ WITH T x IA ON MI. 5/16/2013 NOTE: CONVERTED TO INJECTION (PRE-PRODUCED 3 YEARS) 5/18/2010 NOTE: VIEW SCHEMATIC w/Alaska Schematic9.0 HORIZONTAL, 2L-310, 4/15/2020 6:01:26 AM Vertical schematic (actual) PRODUCTION; 25.6-10,247.0 IPERF; 10,005.0-10,019.0 FRAC; 10,005.0 PACKER; 9,737.2 GAS LIFT; 9,617.2 GAS LIFT; 8,716.8 PATCH; 6,953.0 PATCH; 6,938.0 PATCH - LWR PKR (ME); 3,708.0 GAS LIFT; 3,697.2 SPACER; 3,675.0 SPACER; 3,657.0 PATCH - UPR PKR (ME); 3,653.0 SURFACE; 27.6-3,521.0 NIPPLE; 516.4 CONDUCTOR; 28.0-112.0 KUP INJ KB-Grd (ft) 33.20 Rig Release Date 5/13/2010 2L-310 ... TD Act Btm (ftKB) 10,252.0 Well Attributes Field Name TARN PARTICIPATING AREA Wellbore API/UWI 501032061600 Wellbore Status INJ Max Angle & MD Incl (°) 67.51 MD (ftKB) 2,780.72 WELLNAME WELLBORE2L-310 Annotation Last WO: End DateH2S (ppm) DateComment SSSV: NIPPLE Submit to: OOPERATOR: FFIELDD // UNITT // PAD: DDATE: OOPERATORR REP: AAOGCCC REP: Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD 1982400 Type Inj W Tubing 1890 1900 1890 1890 Type Test P Packer TVD 5244 BBL Pump 3.4 IA 520 4210 4085 4080 Interval V Test psi 3900 BBL Return 3.1 OA 200 350 350 350 Result P Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD 2100280 Type Inj W Tubing 1800 1800 1800 1800 Type Test P Packer TVD 5239 BBL Pump 6.3 IA 700 4210 4090 4070 Interval V Test psi 3900 BBL Return 6.1 OA 521 531 530 530 Result P Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD 2071120 Type Inj W Tubing 1800 1800 1800 1800 Type Test P Packer TVD 5225 BBL Pump 8.2 IA 840 4180 4060 4025 Interval V Test psi 3900 BBL Return 7.8 OA 79 349 330 314 Result P Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD 1982510 Type Inj W Tubing 1620 1620 1620 1620 Type Test P Packer TVD 5237 BBL Pump 2.3 IA 380 3340 3265 3260 Interval V Test psi 3000 BBL Return 1.7 OA 200 250 250 250 Result P Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result TYPE INJ Codes TYPE TEST Codes INTERVAL Codes Result Codes W = Water P = Pressure Test I = Initial Test P = Pass G = Gas O = Other (describe in Notes) 4 = Four Year Cycle F = Fail S = Slurry V = Required by Variance I = Inconclusive I = Industrial Wastewater O = Other (describe in notes) N = Not Injecting Notes:MITIA to maximum anticipated injection pressure per AIO 16.005 2L-323 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION MMechani call Integrityy Test jim.regg@alaska.gov;AOGCC.Inspectors@alaska.gov;phoebe.brooks@alaska.gov chris.wallace@alaska.gov Notes:MITIA to maximum anticipated injection pressure per amended AIO 16.004 2L-319 Notes:MITIA to maximum anticipated injection pressure per ameneded AIO 16.003 Notes: ConocoPhillips Alaska Inc, Kuparuk / KRU / 2L Pad Josh Hunt Beck/Borge 08/06/24 Notes:MITIA to maximum anticipated injection pressure per amended AIO 16.002 Notes: Notes: Notes: 2L-305 2L-310 Form 10-426 (Revised 01/2017)MIT KRU 2L-305,310,319 and 323 08-6-24.xlsx 2L-310 Submit to: OOPERATOR: FIELD / UNIT / PAD: DATE: OPERATOR REP: AOGCC REP: Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD 2100280 Type Inj N Tubing Type Test P Packer TVD 5239 BBL Pump IA Interval O Test psi 1200 BBL Return OA Result P Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result TYPE INJ Codes TYPE TEST Codes INTERVAL Codes Result Codes W = Water P = Pressure Test I = Initial Test P = Pass G = Gas O = Other (describe in Notes) 4 = Four Year Cycle F = Fail S = Slurry V = Required by Variance I = Inconclusive I = Industrial Wastewater O = Other (describe in notes) N = Not Injecting STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION MMechanic al Integri ty Tes t jim.regg@alaska.gov;AOGCC.Inspectors@alaska.gov;phoebe.brooks@alaska.gov chris.wallace@alaska.gov Notes:Surface casing leak detect per AIO 16.004 Amended. Witnessed waived by Adam Earl. SCLD passed per the 1000' OA fluid level criteria. Notes: 2L-310 Notes: Notes: Notes: ConocoPhillips Alaska Inc, Kuparuk / KRU / 2L Pad Waived Fowler / Galle 08/16/24 Form 10-426 (Revised 01/2017)SCLD KRU 2L-310 08-16-24.xlsx 22 P.O. BOX 100360 ANCHORAGE, ALASKA 99510-0360 2th of August, 2022 Commissioner Jessie Chmielowski Alaska Oil & Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, AK 99501 Commissioner Chmielowski: ConocoPhillips Alaska, Inc. presents the attached proposal per AIO 16, Rule 10, to apply for Administrative Approval to allow KRU Tarn injection well 2N-337C (PTD #214- 121) to continue WAG injection service with known TxIA communication while on gas injection. If you need additional information, please contact us at your convenience. Sincerely, Dusty Freeborn Well Integrity Specialist ConocoPhillips Alaska, Inc. Office phone: (907) 659-7224 Cell phone: (907) 830-9777 By Samantha Carlisle at 10:31 am, Aug 04, 2022 Digitally signed by Dusty Freeborn DN: OU=AK WELLS, O=ConocoPhillips, CN=Dusty Freeborn, E=dusty.freeborn@conocophillips.com Reason: I am the author of this document Location: Eagle River, Alaska Date: 2022.08.03 15:54:19-08'00' Foxit PDF Editor Version: 11.2.1 Dusty Freeborn P.O. BOX 100360 ANCHORAGE, ALASKA 99510-0360 1 Kuparuk River Unit Tarn Well 2N-337C (PTD #214-121) Technical Justification for Administrative Relief Request Purpose ConocoPhillips Alaska, Inc. (CPAI) requests that the AOGCC approve an amendment to AIO 16.007 Administrative Approval request as per AIO 16, Rule 10, to allow water alternating gas (WAG) injection for Tarn WAG injector 2N-337C (PTD #214-121). The well displays tubing by inner annulus communication only during gas injection. Well History and Status Kuparuk River Unit Tarn well 2N-337C was completed in December of 2014. 2N-337C was approved for water injection only due to TxIA while on gas injection in April of 2016 under AIO 16.007. On the 27th of May 2022, CPAI communicated a plan to the AOGCC that included intent to observe the well on MI injection for a 30-day monitor period. The MI monitor period was completed, and the IA pressure displayed the capability to stabilize under the DNE of 2400 psi. Additional diagnostics yielded a passing MIT-IA to maximum anticipated injection pressure (4200 psi), passing tubing and inner casing pack off tests, a passing IA draw down test and passing surface casing leak detect. CPAI has developed criteria under which it believes a gas injection well may operate safely with TxIA communication. That criterion includes the well having casing rated high enough to support MAIP of gas injection should a barrier fail, passing a MITIA to MAIP of gas injection, passing a MITOA or SCLD, and passing an IA DDT on water or gas injection. During gas injection service the IA pressure must maintain below the MAOP of 2400 psi. In addition, pressure transmitters will be maintained on the IA and OA allowing real time monitoring and alarm notifications. CPAI believes that 2N-337C current condition along with the well testing and operating criteria above will allow the well to be operated safely without threatening human safety or the environment. Therefore, CPAI request Administrative Approval that will allow 2N-337C to continue WAG injection with known TxIA communication. Barrier and Hazard Evaluation Barriers in place are sufficient to allow safe operation with water alternating gas injection service. Tubing: The 3-1/2”, 9.2 lb/ft, L-80 tubing has integrity to the seal assembly at 6,840’ MD (4,909’ TVD) based on the passing MITIA to 4,170 psi on the 1th of Aug 2022 (MIT-IA results are attached) and TIO trends. There is known TxIA communication while on gas injection based on TIO trend data. P.O. BOX 100360 ANCHORAGE, ALASKA 99510-0360 2 Production casing: The 5.5”, 15.5 lb/ft, L-80 intermediate casing have integrity to seal assembly at 7,030’ MD (5,054’’ TVD) based on the aforementioned passing MITIA and TIO trends. Surface casing: The 7-5/8”, 29.7 lb/ft, L-80 surface casing has an internal yield pressure rating of 6,890 psi. The surface casing has integrity based on a passing SCLD/gas MITOA to 1,200 psi on the 8th of May 2022 and TIO trends. Primary barrier: The primary barrier during water injection to prevent a release from the well and provide zonal isolation is the tubing and seal assembly. The primary barrier during gas injection to prevent a release from the well and provide zonal isolation is the production casing. The tubing and seal assembly also act as a limited barrier, so that the pressure build-up is manageable below 2,400 psi. Secondary barrier: The production casing is the secondary barrier during water injection, should the tubing fail. The surface casing is the secondary barrier during gas injection, should the production casing fail. Tertiary barrier: The surface casing will act as a tertiary barrier during water injection, in the unlikely case that the first two normal barriers have failures. Monitoring: This well will be monitored real time for wellhead pressure changes. Any pressure trends that indicate further annular communication require investigation, Commission notification, and corrective action, up to and including a shut-in of the well. TIO trends are compiled, reviewed, and submitted to the AOGCC for review monthly. Proposed Operating and Monitoring Plan 1. Well will be used for water alternating gas injection. 2. Perform a passing MITIA every 2-years to maximum anticipated injection pressure. 3. Perform a mechanical integrity test of the outer annulus (MITOA) every 2 years to not less than 1200 psi or a passing surface casing leak detect (SCLD) log 4. Allow operating IA pressure up to 2,400 psi during gas injection service and 2,000 psi during water injection service. The operating OA pressure is allowed up to 1,000 psi. 5. Pressure transmitters will be maintained on the IA and OA allowing real time monitoring and alarm notifications. 6. Submit monthly reports of daily tubing, IA, and OA pressures, injection volumes and pressure bleeds for all annuli. 7. Shut-in the well should diagnostic testing or injection rates and pressures indicate further problems with appropriate notification to the AOGCC. 8. Maintain the injection line choke and SSV remote shut down capability. During gas injection, the inner annulus protocols will include a drill site operator alarm set at 2,200 psi, and a high alarm set at 2,400 psi that will prompt the control room Board Operator to remotely shut in the choke or SSV. P.O. BOX 100360 ANCHORAGE, ALASKA 99510-0360 3 9. MIT Anniversary date to be set the month of August 2022 to align the 2-year AOGCC witnessed testing with the UIC MIT permanent 4-year scheduled pad testing. Submit to: OOPERATOR: FIELD / UNIT / PA D: DATE: OPERATOR REP: AOGCC REP: Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD 1982040 Type Inj G Tubing 2820 2820 2820 2820 Type Test P Packer TVD 4963 BBL Pump 0.5 IA 1600 2200 2170 2170 Interval 4 Test psi 1500 BBL Return 0.5 OA 320 380 365 360 Result P Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD 2141210 Type Inj G Tubing 3390 3390 3390 3390 Type Test P Packer TVD 4894 BBL Pump 2.1 IA 100 4170 3980 3950 Interval V Test psi 3900 BBL Return 2.0 OA 300 400 400 390 Result P Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD 1980920 Type Inj W Tubing 1450 1450 1400 1400 Type Test P Packer TVD 4938 BBL Pump 2.5 IA 440 2190 2110 2100 Interval 4 Test psi 1500 BBL Return 2.4 OA 250 250 250 250 Result P Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD 2001390 Type Inj W Tubing 1740 1740 1740 1740 Type Test P Packer TVD 5079 BBL Pump 0.7 IA 850 2510 2450 2450 Interval 4 Test psi 1500 BBL Return 0.7 OA 130 250 225 225 Result P Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result TYPE INJ Codes TYPE TEST Codes INTERVAL Codes Result Codes W = Water P = Pressure Test I = Initial Test P = Pass G = Gas O = Other (describe in Notes) 4 = Four Year Cycle F = Fail S = Slurry V = Required by Variance I = Inconclusive I = Industrial Wastewater O = Other (describe in notes) N = Not Injecting STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION MMec h an i c al Int egr i t y Tes t jim.regg@alaska.gov;AOGCC.Inspectors@alaska.gov;phoebe.brooks@alaska.gov chris.wallace@alaska.gov Notes: Notes: 2N-335 2N-337C 2N-349A Notes:MITIA to maximum anticipated injection pressure per AIO 16.007. NOTE: AMENDED WAIVER BEING PROCESSED FOR T x IA ON GAS. 2N-343 Notes: Notes: ConocoPhillips Alaska Inc, Kuparuk / KRU / 2N Pad Adam Earl Hembree / Hills 08/01/22 Form 10-426 (Revised 01/2017)MIT KRU 2N PAD PAGE 2 08-01-22.xlsx Last Tag Annotation Depth (ftKB) End Date Wellbore Last Mod By Last Tag: SLM 7,532.0 1/17/2017 2N-337C pproven Last Rev Reason Annotation End Date Wellbore Last Mod By Rev Reason: PULL BOMB HANGER W/DUAL GAUGES 3/15/2017 2N-337C pproven Casing Strings Casing Description PRODUCTION 5 1/2 " OD (in) 5 1/2 ID (in) 4.95 Top (ftKB) 28.0 Set Depth (ftKB) 7,029.8 Set Depth (TVD) … 5,054.2 Wt/Len (l… 15.50 Grade L-80 Top Thread Hyd 563 Casing Description LINER 3 1/2" - CEMENTED OD (in) 3 1/2 ID (in) 2.99 Top (ftKB) 6,819.4 Set Depth (ftKB) 7,653.0 Set Depth (TVD) … 5,536.6 Wt/Len (l… 9.20 Grade L-80 Top Thread 511 Liner Details Top (ftKB) Top (TVD) (ftKB) Top Incl (°) Item Des Com Nominal ID (in) 6,819.4 4,892.8 40.08 SLEEVE SETTING SLEEVE 4.130 6,840.4 4,908.9 40.06 PACKER ZXP PACKER 3.000 6,848.8 4,915.3 40.05 HANGER FLEX LOCK LINER HANGER 2.980 Tubing Strings Tubing Description TUBING WO - 2014 String Ma… 3 1/2 ID (in) 2.99 Top (ftKB) 25.8 Set Depth (ft… 6,839.9 Set Depth (TVD) (… 4,908.5 Wt (lb/ft) 9.20 Grade L-80 Top Connection EUE 8rd Completion Details Top (ftKB) Top (TVD) (ftKB) Top Incl (°) Item Des Com Nominal ID (in) 25.8 25.8 0.00 HANGER FMC HANGER - PORTED DRIFTED TO 2.91" 2.992 483.8 483.4 6.06 NIPPLE CAMCO DS NIPPLE 2.875 6,681.3 4,787.1 39.90 SLEEVE BAKER CMU DS SLIDING SLEEVE DS PROFILE - CLOSED 2.810 6,767.1 4,852.8 40.10 NIPPLE CAMCO D NIPPLE 2.750 6,820.6 4,893.7 40.08 SEAL ASY BAKER BULLET TIE BACK SEAL ASSEMBLY W/ 7' SPACE OUT 2.900 Perforations & Slots Top (ftKB) Btm (ftKB) Top (TVD) (ftKB) Btm (TVD) (ftKB) Linked Zone Date Shot Dens (shots/ft )Type Com 7,285.0 7,345.0 5,251.5 5,298.4 4/13/2015 6.0 IPERF 2.5" HOLLOW STEEL CARRIER SCALLOPED GUNS, 11.1 GRAM MILLENNIUM CHARGES 7,345.0 7,390.0 5,298.4 5,333.3 4/12/2015 6.0 IPERF 2.5" HOLLOW STEEL CARRIER SCALLOPED GUNS, 11.1 GRAM MILLENNIUM CHARGES, 60 DEG PHASING 7,435.0 7,455.0 5,368.1 5,383.5 4/12/2015 6.0 IPERF 2.5" HOLLOW STEEL CARRIER SCALLOPED GUNS, 11.1 GRAM MILLEINNUM CHARGES, 60 DEG PHASING 7,455.0 7,475.0 5,383.5 5,398.8 4/11/2015 6.0 IPERF 2.5" HOLLOW STEEL CARRIER, 11.1 GRAM MILLEINNUM DP CHARGES, 60 DEG PHASING 7,475.0 7,490.0 5,398.8 5,410.3 3/24/2015 6.0 IPERF 2.5" 11.1 GRAM MILLENIUM DP CHARGES Frac Summary Start Date 5/7/2007 Proppant Designed (lb) Proppant In Formation (lb) Stg # 1 Start Date 5/7/2007 Top Depth (ftKB) 9,600.0 Btm (ftKB) 9,615.0 Link to Fluid System Vol Clean (bbl) Vol Slurry (bbl) Mandrel Inserts St ati on N o/Top (ftKB) Top (TVD) (ftKB) Make Model OD (in) Serv Valve Type Latch Type Port Size (in) TRO Run (psi) Run Date Com 1 3,355.0 2,490.6 CAMCO KBG-2- 9 1 GAS LIFT DMY INT 0.000 0.0 12/25/2014 2 5,129.6 3,606.9 CAMCO KBG-2- 9 1 GAS LIFT DMY INT 0.000 0.0 12/25/2014 3 6,168.2 4,395.6 CAMCO KBG-2- 9 1 GAS LIFT DMY INT 0.000 0.0 12/25/2014 4 6,623.9 4,743.1 CAMCO KBG-2- 9 1 GAS LIFT DMY INT 0.000 0.0 3/5/2015 Notes: General & Safety End Date Annotation 4/12/2019 NOTE: WAIVERED WELL - T x IA COMMUNICATION ON GAS ONLY. WATER ONLY INJECTION ALLOWED Comment SSSV: NIPPLE 2N-337C, 4/12/2019 2:28:05 PM Vertical schematic (actual) LINER 3 1/2" - CEMENTED; 6,819.4-7,653.0 IPERF; 7,475.0-7,490.0 IPERF; 7,455.0-7,475.0 IPERF; 7,435.0-7,455.0 IPERF; 7,345.0-7,390.0 IPERF; 7,285.0-7,345.0 3-1/2 Production liner; 6,825.0 ftKB PRODUCTION 5 1/2 "; 28.0- 7,029.8 SEAL ASY; 6,820.6 NIPPLE; 6,767.1 SLEEVE; 6,681.3 GAS LIFT; 6,623.9 GAS LIFT; 6,168.2 Intermediate Casing Cement; 5,200.0 ftKB GAS LIFT; 5,129.6 GAS LIFT; 3,355.0 SURFACE; 29.3-2,858.4 Cement Plug; 2,658.0 ftKB NIPPLE; 516.3 NIPPLE; 483.8 CONDUCTOR; 29.2-108.0 HANGER; 25.8 KUP INJ KB-Grd (ft) 29.25 Rig Release Date 3/14/2007 Annotation Last WO: End Date 2N-337C H2S (ppm) 30 Date 7/1/2008... TD Act Btm (ftKB) 7,547.0 Well Attributes Field Name TARN PARTICIPATING AREA Wellbore API/UWI 501032026203 Wellbore Status INJ Max Angle & MD Incl (°) 69.65 MD (ftKB) 2,901.28 WELLNAME WELLBORE2N-337C 21 P.O. BOX 100360 ANCHORAGE, ALASKA 99510-0360 7th of July 2022 Commissioner Jessie Chmielowski Alaska Oil & Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, AK 99501 Commissioner Chmielowski: ConocoPhillips Alaska, Inc. presents the attached proposal per AIO 16, Rule 10, to apply for Administrative Approval to allow KRU Tarn injection well 2N-306 (PTD #204-062) to continue WAG injection service with known TxIA communication while on gas injection. If you need additional information, please contact us at your convenience. Sincerely, Dusty Freeborn Well Integrity Specialist ConocoPhillips Alaska, Inc. Office phone: (907) 659-7224 Cell phone: (907) 830-9777 By Samantha Carlisle at 1:39 pm, Jul 08, 2022 Digitally signed by Dusty Freeborn DN: OU=AK WELLS, O=ConocoPhillips, CN=Dusty Freeborn, E=dusty.freeborn@conocophillips.com Reason: I am the author of this document Location: Anchorage, Alaska Date: 2022.07.07 14:59:42-08'00' Foxit PDF Editor Version: 11.2.1 Dusty Freeborn P.O. BOX 100360 ANCHORAGE, ALASKA 99510-0360 1 Kuparuk River Unit Tarn Well 2N-306 (PTD #204-062) Technical Justification for Administrative Relief Request Purpose ConocoPhillips Alaska, Inc. (CPAI) requests that the AOGCC approve an amendment to AIO 16.006 Administrative Approval request as per AIO 16, Rule 10, to allow water alternating gas (WAG) injection for Tarn WAG injector 2N-306 (PTD #204-062). The well displays tubing by inner annulus communication only during gas injection. Well History and Status Kuparuk River Unit Tarn well 2L-306 was completed in June of 2004. 2N-306 was approved for water injection only due to TxIA while on gas injection in June of 2016 under AIO 16.006. On the 27th of May 2022, CPAI communicated a plan to the AOGCC that included intent to observe the well on MI injection for a 30-day monitor period. The MI monitor period was completed, and the IA pressure displayed the capability to stabilize under the DNE of 2400 psi. Additional diagnostics yielded a passing MIT-IA to maximum anticipated injection pressure (4200 psi), passing tubing and inner casing pack off tests, a passing IA draw down test and passing surface casing leak detect. CPAI has developed criteria under which it believes a gas injection well may operate safely with TxIA communication. That criterion includes the well having casing rated high enough to support MAIP of gas injection should a barrier fail, passing a MITIA to MAIP of gas injection, passing a MITOA or SCLD, and passing an IA DDT on water or gas injection. During gas injection service the IA pressure must maintain below the MAOP of 2400 psi. In addition, pressure transmitters will be maintained on the IA and OA allowing real time monitoring and alarm notifications. CPAI believes that 2N-306 current condition along with the well testing and operating criteria above will allow the well to be operated safely without threatening human safety or the environment. Therefore, CPAI request Administrative Approval that will allow 2N-306 to continue WAG injection with known TxIA communication. Barrier and Hazard Evaluation Barriers in place are sufficient to allow safe operation with water alternating gas injection service. Tubing:The 3-1/2”, 9.2 lb/ft, L-80 tubing has integrity to the seal assembly at 6,944’MD (5,174’’ TVD)based on the passing MITIA to 4,200 psi on the 4 th of May 2022 (MIT-IA results are attached) and TIO trends. There is known TxIA communication while on gas injection based on TIO trend data. P.O. BOX 100360 ANCHORAGE, ALASKA 99510-0360 2 Production casing: The 5.5”, 15.5 lb/ft, L-80 intermediate casing have integrity to seal assembly at 6,944’ MD (5,174’’ TVD) based on the aforementioned passing MITIA and TIO trends. Surface casing: The 7-5/8”, 29.7 lb/ft, L-80 surface casing has an internal yield pressure rating of 6,890 psi. The surface casing has integrity based on a passing SCLD/gas MITOA to 1,200 psi on the 4th of May 2022 and TIO trends. Primary barrier: The primary barrier during water injection to prevent a release from the well and provide zonal isolation is the tubing and packer. The primary barrier during gas injection to prevent a release from the well and provide zonal isolation is the production casing. The tubing and packer also act as a limited barrier, so that the pressure build-up is manageable below 2,400 psi. Secondary barrier: The production casing is the secondary barrier during water injection, should the tubing fail. The surface casing is the secondary barrier during gas injection, should the production casing fail. Tertiary barrier: The surface casing will act as a tertiary barrier during water injection, in the unlikely case that the first two normal barriers have failures. Monitoring: This well will be monitored real time for wellhead pressure changes. Any pressure trends that indicate further annular communication require investigation, Commission notification, and corrective action, up to and including a shut-in of the well. TIO trends are compiled, reviewed, and submitted to the AOGCC for review monthly. Proposed Operating and Monitoring Plan 1. Well will be used for water alternating gas injection. 2. Perform a passing MITIA every 2-years to maximum anticipated injection pressure. 3. Allow operating IA pressure up to 2,400 psi during gas injection service and 2,000 psi during water injection service. The operating OA pressure is allowed up to 1,000 psi. 4. Pressure transmitters will be maintained on the IA and OA allowing real time monitoring and alarm notifications. 5. Submit monthly reports of daily tubing, IA, and OA pressures, injection volumes and pressure bleeds for all annuli. 6. Shut-in the well should diagnostic testing or injection rates and pressures indicate further problems with appropriate notification to the AOGCC. 7. Maintain the injection line choke and SSV remote shut down capability. During gas injection, the inner annulus protocols will include a drill site operator alarm set at 2,200 psi, and a high alarm set at 2,400 psi that will prompt the control room Board Operator to remotely shut in the choke or SSV. 8. MIT Anniversary date to be set the month of August 2022 to align the 2-year AOGCC witnessed testing with the UIC MIT permanent 4-year scheduled pad testing. Casing Strings Casing Description CONDUCTOR OD (in) 16 ID (in) 15.062 Top (ftKB) 29.8 Set Depth (ftKB) 139.0 Set Depth (TVD) … 139.0 Wt/Len (l… 62.50 Grade H-40 Top Thread WELDED Casing Description SURFACE OD (in) 7 5/8 ID (in) 6.875 Top (ftKB) 29.8 Set Depth (ftKB) 2,794.0 Set Depth (TVD) … 2,438.8 Wt/Len (l… 29.70 Grade L-80 Top Thread BTCM Casing Description PRODUCTION 5.5"x3.5" @ 6964' OD (in) 5 1/2 ID (in) 4.950 Top (ftKB) 28.3 Set Depth (ftKB) 7,594.7 Set Depth (TVD) … 5,602.4 Wt/Len (l… 15.50 Grade L-80 Top Thread BTCMOD Tubing Strings Tubing Description TUBING String Ma… 3 1/2 ID (in) 2.992 Top (ftKB) 25.4 Set Depth (ft… 6,961.4 Set Depth (TVD) (… 5,186.3 Wt (lb/ft) 9.30 Grade L-80 Top Connection EUE8RDMOD Completion Details Top (ftKB) Top (TVD) (ftKB) Top Incl (°) Item Des Com Nominal ID (in) 25.4 25.4 0.00 HANGER FMC TUBING HANGER 3.500 493.9 493.7 3.17 NIPPLE CAMCO DS LANDING NIPPLE 2.875 6,882.1 5,133.3 48.75 SLEEVE BAKER CMU SLIDING SLEEVE 2.813 6,898.2 5,144.0 48.62 NIPPLE CAMCO D NIPPLE 2.750 6,942.6 5,173.6 47.61 LOCATOR G-22 LOCATOR SUB 3.000 6,943.5 5,174.2 47.58 SEAL ASSY BAKER GBH 80-40 SEAL ASSEMBLY 3.000 Other In Hole (Wireline retrievable plugs, valves, pumps, fish, etc.) Top (ftKB) Top (TVD) (ftKB) Top Incl (°) Des Com Run Date ID (in) 7,504.0 5,546.2 51.56 FISH Plug off Gauge LOST BULL PLUG OFF PANEX GAUGES IN RATHOLE - 6/27/2007 6/27/2007 0.000 Perforations & Slots Top (ftKB) Btm (ftKB) Top (TVD) (ftKB) Btm (TVD) (ftKB) Zone Date Shot Dens (shots/f t)Type Com 7,258.0 7,266.0 5,387.7 5,393.1 S-3, S-5, 2N- 306 6/26/2004 6.0 IPERF 2.5" HSD PJ 2506, EHD 0.31" 7,270.0 7,286.0 5,395.7 5,406.4 S3, 2N-306 6/26/2004 6.0 IPERF 2.5" HSD PJ 2506, EHD 0.31" 7,292.0 7,310.0 5,410.3 5,422.2 S3, 2N-306 6/26/2004 6.0 IPERF 2.5" HSD PJ 2506, EHD 0.31" 7,364.0 7,382.0 5,457.5 5,469.2 Top Purple, 2N-306 4/30/2008 6.0 APERF 7,394.0 7,440.0 5,476.9 5,506.1 Top/Base Purple, 2N- 306 4/29/2008 6.0 APERF Mandrel Inserts St ati on N o/Top (ftKB) Top (TVD) (ftKB) Make Model OD (in) Serv Valve Type Latch Type Port Size (in) TRO Run (psi) Run Date Com 1 6,833.7 5,101.5 CAMCO KBG-2- 9 1 GAS LIFT SOV BTM 0.000 0.0 5/23/2004 Notes: General & Safety End Date Annotation 11/19/2010 NOTE: View Schematic w/ Alaska Schematic9.0 6/27/2016 NOTE: Waivered Well TxIA communication on gas. Water injection only allowed. Comment SSSV: NIPPLE2N-306, 3/11/2017 11:25:06 AM Vertical schematic (actual) PRODUCTION 5.5"x3.5" @ 6964'; 28.3-7,594.7 FISH; 7,504.0 APERF; 7,394.0-7,440.0 APERF; 7,364.0-7,382.0 IPERF; 7,292.0-7,310.0 IPERF; 7,270.0-7,286.0 IPERF; 7,258.0-7,266.0 SEAL ASSY; 6,943.5 LOCATOR; 6,942.6 NIPPLE; 6,898.2 SLEEVE; 6,882.1 GAS LIFT; 6,833.7 SURFACE; 29.8-2,794.0 NIPPLE; 493.9 CONDUCTOR; 29.8-139.0 HANGER; 25.4 Annotation Last Tag: SLM Depth (ftKB) 7,569.0 End Date 3/10/2017 Annotation Rev Reason: TAG Last Mod By pproven End Date 3/11/2017 KUP INJ KB-Grd (ft) 36.51 Rig Release Date 6/2/2004 Annotation Last WO: End Date 2N-306 H2S (ppm) Date ... TD Act Btm (ftKB) 7,605.0 Well Attributes Wellbore API/UWI 501032049000 Field Name TARN PARTICIPATING AREA Wellbore Status INJ Max Angle & MD Incl (°) 52.43 MD (ftKB) 3,116.17 Submit to: OOPERATOR: FIELD / UNIT / PA D: DATE: OPERATOR REP: AOGCC REP: Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD 204-062 Type Inj W Tubing 1783 1784 1784 1784 Type Test P Packer TVD 5174 BBL Pump 1.7 IA 733 4200 4115 4110 Interval O Test psi 1500 BBL Return N/A OA 245 642 625 620 Result P Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result TYPE INJ Codes TYPE TEST Codes INTERVAL Codes Result Codes W = Water P = Pressure Test I = Initial Test P = Pass G = Gas O = Other (describe in Notes) 4 = Four Year Cycle F = Fail S = Slurry V = Required by Variance I = Inconclusive I = Industrial Wastewater O = Other (describe in notes) N = Not Injecting ConocoPhillips Alaska Inc, Kuparuk / KRU / 2N Pad Galle 05/04/22 Notes:Non-witnessed diagnostic MIT-IA Notes: 2N-306 Notes: Notes: Notes: STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION MMec h an i c al Int egr i t y Tes t jim.regg@alaska.gov;AOGCC.Inspectors@alaska.gov;phoebe.brooks@alaska.gov chris.wallace@alaska.gov Form 10-426 (Revised 01/2017)2N-306 Non-witnessed diagnostics MIT-IA.xlsx 1 Prysunka, Anne E (OGC) From:Well Integrity Specialist CPF2 <n2549@conocophillips.com> Sent:Thursday, July 21, 2022 12:58 PM To:Wallace, Chris D (OGC) Subject:RE: [EXTERNAL]RE: CPAI 2L-319 (PTD #207-112) & 2N-306 (PTD #204-062) 30 day monitor period for diagnostic testing. Chris‐ CPAI intends to perform the MIT‐OA/SCLD on a two year basis as an internal requirement but in our experience with AIO 16.004 the SCLD can be a multiple day event in which the AOGCC inspectors have previously waived witness. It is not a problem to add the MIT‐OA/SCLD to the AA requirement and offer the opportunity to the inspectors to witness and if that is the preferential approach CPAI has no problems with that. In the cases of these three wells, each has been completed without an OA shoe so it will always be a SCLD vs a MIT‐OA. What would be the preference for reporting the results of the SCLD? The technique/results don’t match the formatting on the 10‐426 forms. Are we just reporting them as a pass or fail in an email? On another note, we started the discussion of the UIC compliance testing for 2P‐pad injectors. After additional thought, CPAI intends to complete the tests within the normal testing month (AUG 2022) with the wells shut in. This will both keep us within our normal testing operations and will provide an initial set of data regarding the conditions of the tubing, production casing and packers. The non‐witnessed tests will be reported as usual. Let me know if you would like to approach this in a different manner. Great to see you the other day, its been a long time! Dusty Freeborn Wells Integrity Specialist ConocoPhillips Alaska, Inc. Office phone: (907) 659-7224 Cell phone: (907) 830-9777 From: Wallace, Chris D (OGC) <chris.wallace@alaska.gov> Sent: Wednesday, July 20, 2022 1:57 PM To: Well Integrity Specialist CPF2 <n2549@conocophillips.com> Subject: [EXTERNAL]RE: CPAI 2L‐319 (PTD #207‐112) & 2N‐306 (PTD #204‐062) 30 day monitor period for diagnostic testing. CAUTION:This email originated from outside of the organization. Do not click links or open attachments unless you recognize the sender and know the content is safe. Dusty, I am progressing the AA amendment requests for these two wells and 2L‐305. The requests all mention the MITOA or SCLD criteria and testing but this requirement has not been carried over to the proposed operating and monitoring plan. 2 As with AIO 16.004 amendment, we plan to add the MITOA/SCLD requirement via this language: 4. CPAI shall perform a mechanical integrity test of the outer annulus (MITOA) every 2 years to not less than 1200 psi or a passing surface casing leak detect (SCLD) log; Please let me know if I am missing something or why the MITOA/SCLD should not be a two year requirement. I also note CPAI criteria of IA draw down test ‐ but I haven’t made that an AOGCC requirement. Thanks and Regards, Chris Wallace, Sr. Petroleum Engineer, Alaska Oil and Gas Conservation Commission, 333 West 7th Avenue, Anchorage, AK 99501, (907) 793‐1250 (phone), (907) 276‐7542 (fax), chris.wallace@alaska.gov CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Chris Wallace at 907-793-1250 or chris.wallace@alaska.gov. From: Well Integrity Specialist CPF2 <n2549@conocophillips.com> Sent: Thursday, July 7, 2022 2:53 PM To: Wallace, Chris D (OGC) <chris.wallace@alaska.gov> Cc: Well Integrity Specialist CPF2 <n2549@conocophillips.com> Subject: CPAI 2L‐319 (PTD #207‐112) & 2N‐306 (PTD #204‐062) 30 day monitor period for diagnostic testing. Chris‐ Kuparuk Tarn injectors 2L‐319 (PTD #207‐112) and 2N‐306 (PTD #204‐062) have completed their 30 day monitor periods. Both IAs have shown stabilization below the DNE of 2400 psi while on gas injection and have now met all of the criteria in which CPAI requires to continue WAG injection with known tubing by inner annulus communication. It is CPAI’s intention to submit an application for continued WAG injection with known tubing by inner annulus communication. While the AAs are in process the well will be left in gas injection service. Attached are the current 90 day TIO plot and well bore schematic. Please let me know if you have any questions or disagree with the plan. Dusty Freeborn Wells Integrity Specialist ConocoPhillips Alaska, Inc. Office phone: (907) 659-7224 Cell phone: (907) 830-9777 From: Well Integrity Specialist CPF2 Sent: Friday, May 27, 2022 7:50 AM To: Wallace, Chris D (CED) <chris.wallace@alaska.gov> Cc: Well Integrity Specialist CPF2 <n2549@conocophillips.com> Subject: CPAI 2L‐305 (PTD #198‐240), 2L‐319 (PTD #207‐112), 2N‐306 (PTD #204‐062) & 2N‐337C (PTD #214‐121) 30 day monitor period for diagnostic testing. CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. 3 Chris‐ CPAI has identified four Tarn injectors 2L‐305 (PTD #198‐240), 2L‐319 (PTD #207‐112), 2N‐306 (PTD #204‐062) & 2N‐ 337C (PTD #214‐121) that were previously waivered for water injection only due to known TxIA while on gas injection. During a recent reservoir evaluation, these 4 wells were identified to have a significant production benefit from the ability to inject MI. CPAI has developed criteria under which it believes a gas injection well may operate safely with TxIA communication. That criterion includes the well having casing rated high enough to support maximum anticipated injection pressure of gas injection should a barrier fail, passing a MITIA to maximum anticipated injection pressure of gas injection, passing a MITOA or SCLD, and passing an IA DDT on water or gas injection and during gas injection service the IA pressure must sustain below the “do not exceed” of 2400 psi. These wells meet the above criteria and CPAI has conducted diagnostic MIT‐IAs and SCLDs all with passing results. The remaining criteria yet to be met is the ability to maintain IA pressure under DNE of 2400 psi while on gas injection. Therefore, CPAI intends to place 2L‐305, 2L‐319, 2N‐306 & 2N‐337C into gas injection service for a 30 day monitor period. If the 30 day monitor period displays the ability of the IAs to sustain a pressure below the DNE, CPAI intends to apply for administrative approval for continued WAG injection with known TxIA communication while on gas injection. Attached are the current 90 day TIO plots and wellbore schematics. Please let me know if you have any questions or disagree with the plan. Dusty Freeborn Wells Integrity Specialist ConocoPhillips Alaska, Inc. Office phone: (907) 659-7224 Cell phone: (907) 830-9777 20 P.O. BOX 100360 ANCHORAGE, ALASKA 99510-0360 7th of July 2022 Commissioner Jessie Chmielowski Alaska Oil & Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, AK 99501 Commissioner Chmielowski: ConocoPhillips Alaska, Inc. presents the attached proposal per AIO 16, Rule 10, to apply for Administrative Approval to allow KRU Tarn injection well 2L-319 (PTD #207-112) to continue WAG injection service with known TxIA communication while on gas injection. If you need additional information, please contact us at your convenience. Sincerely, Dusty Freeborn Well Integrity Specialist ConocoPhillips Alaska, Inc. Office phone: (907) 659-7224 Cell phone: (907) 830-9777 By Samantha Carlisle at 1:39 pm, Jul 08, 2022 Digitally signed by Dusty Freeborn DN: OU=AK WELLS, O=ConocoPhillips, CN=Dusty Freeborn, E=dusty.freeborn@conocophillips.com Reason: I am the author of this document Location: Anchorage, Alaska Date: 2022.07.07 12:47:44-08'00' Foxit PDF Editor Version: 11.2.1 Dusty Freeborn P.O. BOX 100360 ANCHORAGE, ALASKA 99510-0360 1 Kuparuk River Unit Tarn Well 2L-319 (PTD #207-112) Technical Justification for Administrative Relief Request Purpose ConocoPhillips Alaska, Inc. (CPAI) requests that the AOGCC approve an amendment to AIO 16.003 Administrative Approval request as per AIO 16, Rule 10, to allow water alternating gas (WAG) injection for Tarn WAG injector 2L-319 (PTD# 207-112). The well displays tubing by inner annulus communication only during gas injection. Well History and Status Kuparuk River Unit Tarn well 2L-305 was completed in December of 2007. 2L-319 was approved for water injection only due to TxIA while on gas injection in November of 2012 under AIO 16.003. On the 27th of May 2022, CPAI communicated a plan to the AOGCC that included intent to observe the well on MI injection for a 30-day monitor period. The MI monitor period was completed, and the IA pressure displayed the capability to stabilize under the DNE of 2400 psi. Additional diagnostics yielded a passing MIT-IA to maximum anticipated injection pressure (4200 psi), passing tubing and inner casing pack off tests, a passing IA draw down test and passing surface casing leak detect. CPAI has developed criteria under which it believes a gas injection well may operate safely with TxIA communication. That criterion includes the well having casing rated high enough to support MAIP of gas injection should a barrier fail, passing a MITIA to MAIP of gas injection, passing a MITOA or SCLD, and passing an IA DDT on water or gas injection. During gas injection service the IA pressure must maintain below the MAOP of 2400 psi. In addition, pressure transmitters will be maintained on the IA and OA allowing real time monitoring and alarm notifications. CPAI believes that 2L-319 current condition along with the well testing and operating criteria above will allow the well to be operated safely without threatening human safety or the environment. Therefore, CPAI request Administrative Approval that will allow 2L-319 to continue WAG injection with known TxIA communication. Barrier and Hazard Evaluation Barriers in place are sufficient to allow safe operation with water alternating gas injection service. Tubing: The 3-1/2”, 9.2 lb/ft, L-80 tubing has integrity to the seal assembly at 12,143’ MD (5,225’ TVD) based on the passing MITIA to 4,200 psi on the 2nd of May 2022 (MIT-IA results are attached) and TIO trends. There is known TxIA communication while on gas injection based on TIO trend data. P.O. BOX 100360 ANCHORAGE, ALASKA 99510-0360 2 Production casing: The 7”, 26 lb/ft, L-80 intermediate casing have integrity to seal assembly at 12,143’ MD (5,225’ TVD) based on the aforementioned passing MITIA and TIO trends. Surface casing: The 9-5/8”, 40 lb/ft, L-80 surface casing has an internal yield pressure rating of 5750 psi. The surface casing has integrity based on a passing SCLD/gas MITOA to 1,200 psi on the 3rd of May 2022 and TIO trends. Primary barrier: The primary barrier during water injection to prevent a release from the well and provide zonal isolation is the tubing and packer. The primary barrier during gas injection to prevent a release from the well and provide zonal isolation is the production casing. The tubing and packer also act as a limited barrier, so that the pressure build-up is manageable below 2,400 psi. Secondary barrier: The production casing is the secondary barrier during water injection, should the tubing fail. The surface casing is the secondary barrier during gas injection, should the production casing fail. Tertiary barrier: The surface casing will act as a tertiary barrier during water injection, in the unlikely case that the first two normal barriers have failures. Monitoring: This well will be monitored real time for wellhead pressure changes. Any pressure trends that indicate further annular communication require investigation, Commission notification, and corrective action, up to and including a shut-in of the well. TIO trends are compiled, reviewed, and submitted to the AOGCC for review monthly. Proposed Operating and Monitoring Plan 1. Well will be used for water alternating gas injection. 2. Perform a passing MITIA every 2-years to maximum anticipated injection pressure. 3. Allow operating IA pressure up to 2,400 psi during gas injection service and 2,000 psi during water injection service. The operating OA pressure is allowed up to 1,000 psi. 4. Pressure transmitters will be maintained on the IA and OA allowing real time monitoring and alarm notifications. 5. Submit monthly reports of daily tubing, IA, and OA pressures, injection volumes and pressure bleeds for all annuli. 6. Shut-in the well should diagnostic testing or injection rates and pressures indicate further problems with appropriate notification to the AOGCC. 7. Maintain the injection line choke and SSV remote shut down capability. During gas injection, the inner annulus protocols will include a drill site operator alarm set at 2,200 psi, and a high alarm set at 2,400 psi that will prompt the control room Board Operator to remotely shut in the choke or SSV. 8. MIT Anniversary date to be set the month of August 2022 to align the 2-year AOGCC witnessed testing with the UIC MIT permanent 4-year scheduled pad testing. Last Tag Annotation Depth (ftKB) End Date Wellbore Last Mod By Last Tag: SLM 12,517.0 10/7/2019 2L-319 fergusp Last Rev Reason Annotation End Date Wellbore Last Mod By Rev Reason: Tag 10/7/2019 2L-319 fergusp Casing Strings Casing Description CONDUCTOR OD (in) 16 ID (in) 15.25 Top (ftKB) 30.0 Set Depth (ftKB) 110.0 Set Depth (TVD) … 110.0 Wt/Len (l… 65.00 Grade H-40 Top Thread WELDED Casing Description SURFACE OD (in) 9 5/8 ID (in) 8.83 Top (ftKB) 30.0 Set Depth (ftKB) 4,294.8 Set Depth (TVD) … 2,385.7 Wt/Len (l… 40.00 Grade L-80 Top Thread BTC Casing Description PRODUCTION 7"x4.5" @ 12130' OD (in) 7 ID (in) 6.28 Top (ftKB) 28.6 Set Depth (ftKB) 12,963.2 Set Depth (TVD) … 5,852.3 Wt/Len (l… 26.00 Grade L-80 Top Thread BTCM Tubing Strings Tubing Description TUBING String Ma… 3 1/2 ID (in) 2.99 Top (ftKB) 26.3 Set Depth (ft… 12,143.4 Set Depth (TVD) (… 5,225.7 Wt (lb/ft) 9.20 Grade L-80 Top Connection EUE 8rd Mod Completion Details Top (ftKB) Top (TVD) (ftKB) Top Incl (°) Item Des Com Nominal ID (in) 26.3 26.3 0.00 HANGER FMC HANGER 3.500 510.4 510.3 2.68 NIPPLE CAMCO "DS" NIPPLE w/ 2.875" Profile 2.875 12,000.0 5,126.5 47.34 SLEEVE BAKER CMU SLIDING SLEEVE w/2.813" DS Profile 2.812 12,072.8 5,176.3 46.28 NIPPLE CAMCO 'D' NIPPLE w/ 2.75" No-Go Profile 2.750 12,141.9 5,224.6 44.95 LOCATOR BAKER LOCATOR SUB (2' above Top PBR @ 12145' DrlD) 3.000 12,142.7 5,225.2 44.93 SEAL ASSY BAKER 80-40 GBH-22 SEAL ASSEMBLY w/ 16' Stroke w/Baker Locator Sub 2' above No GO 3.000 Other In Hole (Wireline retrievable plugs, valves, pumps, fish, etc.) Top (ftKB) Top (TVD) (ftKB) Top Incl (°) Des Com Run Date ID (in) 26.3 26.3 0.00 CHEM LINE .375" Encapsulated line run from CIM to Surface. Used 5 (1/2) cannon clamps and 123 full clamps. 11/1/2007 12,190.0 5,258.9 44.21 FISH Remnant of Rubber wiper plug and cmt left after cementing. Unable to C/O when running completion. 10/27/200 7 0.010 Perforations & Slots Top (ftKB) Btm (ftKB) Top (TVD) (ftKB) Btm (TVD) (ftKB) Linked Zone Date Shot Dens (shots/ft )Type Com 12,480.0 12,500.0 5,473.3 5,488.5 T-2, 2L-319 12/31/2007 6.0 IPERF HYPERJET PERFS Mandrel Inserts St ati on N o/Top (ftKB) Top (TVD) (ftKB) Make Model OD (in) Serv Valve Type Latch Type Port Size (in) TRO Run (psi) Run Date Com 1 4,737.1 2,543.4 CAMCO KBMG 1 GAS LIFT DMY BK-5 0.000 0.0 11/1/2007 2 7,415.8 3,448.3 CAMCO KBMG- LTS- CIV 1 CHEM DMY BK-5 0.000 0.0 11/1/2007 Chem INJ VLV 3 8,184.0 3,698.0 CAMCO KBMG 1 GAS LIFT DMY BK-5 0.000 0.0 11/1/2007 4 10,962.0 4,631.2 CAMCO KBMG 1 GAS LIFT DMY BK-5 0.000 0.0 11/1/2007 5 11,918.2 5,072.0 CAMCO KBMG 1 GAS LIFT DMY BK 0.000 0.0 11/29/2009 Notes: General & Safety End Date Annotation 7/20/2008 NOTE: VIEW SCHEMATIC w/9.0 11/8/2012 NOTE: T x IA ON MI. WATER INJECTION ONLY. 2L-319, 10/8/2019 8:16:37 AM Vertical schematic (actual) PRODUCTION 7"x4.5" @ 12130'; 28.6-12,963.2 FISH; 12,190.0 IPERF; 12,480.0-12,500.0 SEAL ASSY; 12,142.7 LOCATOR; 12,141.9 NIPPLE; 12,072.8 SLEEVE; 12,000.0 GAS LIFT; 11,918.2 GAS LIFT; 10,962.0 GAS LIFT; 8,184.0 CHEMICAL; 7,415.8 GAS LIFT; 4,737.1 SURFACE; 30.0-4,294.8 CHEM LINE; 26.3 NIPPLE; 510.4 CONDUCTOR; 30.0-110.0 HANGER; 26.3 KUP INJ KB-Grd (ft) 35.63 Rig Release Date 11/2/2007 2L-319 ... TD Act Btm (ftKB) 13,010.0 Well Attributes Field Name TARN PARTICIPATING AREA Wellbore API/UWI 501032055200 Wellbore Status INJ Max Angle & MD Incl (°) 73.42 MD (ftKB) 2,913.12 WELLNAME WELLBORE2L-319 Annotation Last WO: End DateH2S (ppm) DateComment SSSV: NIPPLE Submit to: OOPERATOR: FIELD / UNIT / PA D: DATE: OPERATOR REP: AOGCC REP: Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD 207-112 Type Inj W Tubing 1800 1800 1800 1800 Type Test P Packer TVD 5225 BBL Pump 9.8 IA 15 4200 4130 4110 Interval O Test psi 1500 BBL Return N/A OA 233 580 565 555 Result P Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result TYPE INJ Codes TYPE TEST Codes INTERVAL Codes Result Codes W = Water P = Pressure Test I = Initial Test P = Pass G = Gas O = Other (describe in Notes) 4 = Four Year Cycle F = Fail S = Slurry V = Required by Variance I = Inconclusive I = Industrial Wastewater O = Other (describe in notes) N = Not Injecting ConocoPhillips Alaska Inc, Kuparuk / KRU / 2L Pad Galle 05/02/22 Notes:Non-witnessed diagnostic MIT-IA Notes: 2L-319 Notes: Notes: Notes: STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION MMec h an i c al Int egr i t y Tes t jim.regg@alaska.gov;AOGCC.Inspectors@alaska.gov;phoebe.brooks@alaska.gov chris.wallace@alaska.gov Form 10-426 (Revised 01/2017)2L-319 Diagnostic MIT-IA 2 May 22.xlsx From:Well Integrity Specialist CPF2 To:Wallace, Chris D (OGC) Subject:RE: [EXTERNAL]RE: CPAI 2L-319 (PTD #207-112) & 2N-306 (PTD #204-062) 30 day monitor period for diagnostic testing. Date:Thursday, July 21, 2022 12:58:21 PM Attachments:image001.png Chris- CPAI intends to perform the MIT-OA/SCLD on a two year basis as an internal requirement but in our experience with AIO 16.004 the SCLD can be a multiple day event in which the AOGCC inspectors have previously waived witness. It is not a problem to add the MIT-OA/SCLD to the AA requirement and offer the opportunity to the inspectors to witness and if that is the preferential approach CPAI has no problems with that. In the cases of these three wells, each has been completed without an OA shoe so it will always be a SCLD vs a MIT-OA. What would be the preference for reporting the results of the SCLD? The technique/results don’t match the formatting on the 10-426 forms. Are we just reporting them as a pass or fail in an email? On another note, we started the discussion of the UIC compliance testing for 2P-pad injectors. After additional thought, CPAI intends to complete the tests within the normal testing month (AUG 2022) with the wells shut in. This will both keep us within our normal testing operations and will provide an initial set of data regarding the conditions of the tubing, production casing and packers. The non-witnessed tests will be reported as usual. Let me know if you would like to approach this in a different manner. Great to see you the other day, its been a long time! Dusty Freeborn Wells Integrity Specialist ConocoPhillips Alaska, Inc. Office phone: (907) 659-7224 Cell phone: (907) 830-9777 From: Wallace, Chris D (OGC) <chris.wallace@alaska.gov> Sent: Wednesday, July 20, 2022 1:57 PM To: Well Integrity Specialist CPF2 <n2549@conocophillips.com> Subject: [EXTERNAL]RE: CPAI 2L-319 (PTD #207-112) & 2N-306 (PTD #204-062) 30 day monitor period for diagnostic testing. CAUTION:This email originated from outside of the organization. Do not click links or open attachments unless you recognize the sender and know the content is safe. Dusty, CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. I am progressing the AA amendment requests for these two wells and 2L-305. The requests all mention the MITOA or SCLD criteria and testing but this requirement has not been carried over to the proposed operating and monitoring plan. As with AIO 16.004 amendment, we plan to add the MITOA/SCLD requirement via this language: 4. CPAI shall perform a mechanical integrity test of the outer annulus (MITOA) every 2 years to not less than 1200 psi or a passing surface casing leak detect (SCLD) log; Please let me know if I am missing something or why the MITOA/SCLD should not be a two year requirement. I also note CPAI criteria of IA draw down test - but I haven’t made that an AOGCC requirement. Thanks and Regards, Chris Wallace, Sr. Petroleum Engineer, Alaska Oil and Gas Conservation Commission, 333 West 7th Avenue, Anchorage, AK 99501, (907) 793-1250 (phone), (907) 276-7542 (fax), chris.wallace@alaska.gov CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Chris Wallace at 907-793-1250 or chris.wallace@alaska.gov. From: Well Integrity Specialist CPF2 <n2549@conocophillips.com> Sent: Thursday, July 7, 2022 2:53 PM To: Wallace, Chris D (OGC) <chris.wallace@alaska.gov> Cc: Well Integrity Specialist CPF2 <n2549@conocophillips.com> Subject: CPAI 2L-319 (PTD #207-112) & 2N-306 (PTD #204-062) 30 day monitor period for diagnostic testing. Chris- Kuparuk Tarn injectors 2L-319 (PTD #207-112) and 2N-306 (PTD #204-062) have completed their 30 day monitor periods. Both IAs have shown stabilization below the DNE of 2400 psi while on gas injection and have now met all of the criteria in which CPAI requires to continue WAG injection with known tubing by inner annulus communication. It is CPAI’s intention to submit an application for continued WAG injection with known tubing by inner annulus communication. While the AAs are in process the well will be left in gas injection service. Attached are the current 90 day TIO plot and well bore schematic. Please let me know if you have any questions or disagree with the plan. Dusty Freeborn Wells Integrity Specialist ConocoPhillips Alaska, Inc. Office phone: (907) 659-7224 Cell phone: (907) 830-9777 From: Well Integrity Specialist CPF2 Sent: Friday, May 27, 2022 7:50 AM To: Wallace, Chris D (CED) <chris.wallace@alaska.gov> Cc: Well Integrity Specialist CPF2 <n2549@conocophillips.com> Subject: CPAI 2L-305 (PTD #198-240), 2L-319 (PTD #207-112), 2N-306 (PTD #204-062) & 2N-337C (PTD #214-121) 30 day monitor period for diagnostic testing. Chris- CPAI has identified four Tarn injectors 2L-305 (PTD #198-240), 2L-319 (PTD #207-112), 2N-306 (PTD #204-062) & 2N-337C (PTD #214-121) that were previously waivered for water injection only due to known TxIA while on gas injection. During a recent reservoir evaluation, these 4 wells were identified to have a significant production benefit from the ability to inject MI. CPAI has developed criteria under which it believes a gas injection well may operate safely with TxIA communication. That criterion includes the well having casing rated high enough to support maximum anticipated injection pressure of gas injection should a barrier fail, passing a MITIA to maximum anticipated injection pressure of gas injection, passing a MITOA or SCLD, and passing an IA DDT on water or gas injection and during gas injection service the IA pressure must sustain below the “do not exceed” of 2400 psi. These wells meet the above criteria and CPAI has conducted diagnostic MIT-IAs and SCLDs all with passing results. The remaining criteria yet to be met is the ability to maintain IA pressure under DNE of 2400 psi while on gas injection. Therefore, CPAI intends to place 2L-305, 2L-319, 2N- 306 & 2N-337C into gas injection service for a 30 day monitor period. If the 30 day monitor period displays the ability of the IAs to sustain a pressure below the DNE, CPAI intends to apply for administrative approval for continued WAG injection with known TxIA communication while on gas injection. Attached are the current 90 day TIO plots and wellbore schematics. Please let me know if you have any questions or disagree with the plan. Dusty Freeborn Wells Integrity Specialist ConocoPhillips Alaska, Inc. Office phone: (907) 659-7224 Cell phone: (907) 830-9777 19 P.O. BOX 100360 ANCHORAGE, ALASKA 99510-0360 6 July 2022 Commissioner Jessie Chmielowski Alaska Oil & Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, AK 99501 Commissioner Chmielowski: ConocoPhillips Alaska, Inc. presents the attached proposal per AIO 16, Rule 10, to apply for Administrative Approval to allow KRU Tarn injection well 2L-305 (PTD #198-240) to continue WAG injection service with known TxIA communication while on gas injection. If you need additional information, please contact us at your convenience. Sincerely, Dusty Freeborn Well Integrity Specialist ConocoPhillips Alaska, Inc. Office phone: (907) 659-7224 Cell phone: (907) 830-9777 Digitally signed by Dusty Freeborn DN: OU=AK WELLS, O=ConocoPhillips, CN=Dusty Freeborn, E=dusty.freeborn@conocophillips.com Reason: I am the author of this document Location: Anchorage, Alaska Date: 2022.07.06 13:11:54-08'00' Foxit PDF Editor Version: 11.2.1 Dusty Freeborn P.O. BOX 100360 ANCHORAGE, ALASKA 99510-0360 1 Kuparuk River Unit Tarn Well 2L-305 (PTD #198-240) Technical Justification for Administrative Relief Request Purpose ConocoPhillips Alaska, Inc. (CPAI) requests that the AOGCC approve an amendment to AIO 16.002 Administrative Approval request as per AIO 16, Rule 10, to allow water alternating gas (WAG) injection for Tarn WAG injector 2L-305 (PTD# 198-240). The well displays tubing by inner annulus communication only during gas injection. Well History and Status Kuparuk River Unit Tarn well 2L-305 was completed in December of 1998. 2L-305 was approved for water injection only due to TxIA while on gas injection in December of 2011 under AIO 16.002. On the 27th of May 2022, CPAI communicated a plan to the AOGCC that included intent to observe the well on MI injection for a 30 day monitor period. The MI monitor period was completed, and the IA pressure displayed the capability to stabilize under the DNE of 2400 psi. Additional diagnostics yielded a passing MIT-IA to maximum anticipated injection pressure (4200 psi), passing tubing and inner casing pack off tests, a passing IA draw down test and passing surface casing leak detect. CPAI has developed criteria under which it believes a gas injection well may operate safely with TxIA communication. That criterion includes the well having casing rated high enough to support MAIP of gas injection should a barrier fail, passing a MITIA to MAIP of gas injection, passing a MITOA or SCLD, and passing an IA DDT on water or gas injection. During gas injection service the IA pressure must maintain below the MAOP of 2400 psi. In addition, pressure transmitters will be maintained on the IA and OA allowing real time monitoring and alarm notifications. CPAI believes that 2l-305 current condition along with the well testing and operating criteria above will allow the well to be operated safely without threatening human safety or the environment. Therefore, CPAI request Administrative Approval that will allow 2l-305 to continue WAG injection with known TxIA communication. Barrier and Hazard Evaluation Barriers in place are sufficient to allow safe operation with water alternating gas injection service. Tubing: The 3-1/2”, 9.3 lb/ft, L-80 tubing has integrity to the seal assembly at 8,367’ MD (5,244’ TVD) based on the passing MITIA to 4,200 psi on the 27th of April 2022 (MIT-IA results are attached) and TIO trends. There is known TxIA communication while on gas injection based on TIO trend data. P.O. BOX 100360 ANCHORAGE, ALASKA 99510-0360 2 Production casing: The 5.5”, 15.5 lb/ft, L-80 intermediate casing have integrity to seal assembly at 8,367’ MD (5,244’ TVD) based on the aforementioned passing MITIA and TIO trends. Surface casing: The 7-5/8”, 45.5 lb/ft, L-80 surface casing has an internal yield pressure rating of 10,490 psi. The surface casing has integrity based on a passing SCLD/gas MITOA to 1,200 psi on the 30th of April 2022 and TIO trends. Primary barrier: The primary barrier during water injection to prevent a release from the well and provide zonal isolation is the tubing and packer. The primary barrier during gas injection to prevent a release from the well and provide zonal isolation is the production casing. The tubing and packer also act as a limited barrier, so that the pressure build-up is manageable below 2,400 psi. Secondary barrier: The production casing is the secondary barrier during water injection, should the tubing fail. The surface casing is the secondary barrier during gas injection, should the production casing fail. Tertiary barrier: The surface casing will act as a tertiary barrier during water injection, in the unlikely case that the first two normal barriers have failures. Monitoring: This well will be monitored real time for wellhead pressure changes. Any pressure trends that indicate further annular communication require investigation, Commission notification, and corrective action, up to and including a shut-in of the well. TIO trends are compiled, reviewed, and submitted to the AOGCC for review monthly. Proposed Operating and Monitoring Plan 1. Well will be used for water alternating gas injection. 2. Perform a passing MITIA every 2-years to maximum anticipated injection pressure. 3. Allow operating IA pressure up to 2,400 psi during gas injection service and 2,000 psi during water injection service. The operating OA pressure is allowed up to 1,000 psi. 4. Pressure transmitters will be maintained on the IA and OA allowing real time monitoring and alarm notifications. 5. Submit monthly reports of daily tubing, IA, and OA pressures, injection volumes and pressure bleeds for all annuli. 6. Shut-in the well should diagnostic testing or injection rates and pressures indicate further problems with appropriate notification to the AOGCC. 7. Maintain the injection line choke and SSV remote shut down capability. During gas injection, the inner annulus protocols will include a drill site operator alarm set at 2,200 psi, and a high alarm set at 2,400 psi that will prompt the control room Board Operator to remotely shut in the choke or SSV. 8. MIT Anniversary date to be set the month of August 2022 to align the 2-year AOGCC witnessed testing with the UIC MIT permanent 4-year scheduled pad testing. Submit to: OOPERATOR: FIELD / UNIT / PA D: DATE: OPERATOR REP: AOGCC REP: Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD 198-240 Type Inj W Tubing 1900 1900 1900 1900 Type Test P Packer TVD 5244 BBL Pump 2.3 IA 800 4200 4145 4135 Interval O Test psi 1500 BBL Return 2.1 OA 480 480 480 480 Result P Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result TYPE INJ Codes TYPE TEST Codes INTERVAL Codes Result Codes W = Water P = Pressure Test I = Initial Test P = Pass G = Gas O = Other (describe in Notes) 4 = Four Year Cycle F = Fail S = Slurry V = Required by Variance I = Inconclusive I = Industrial Wastewater O = Other (describe in notes) N = Not Injecting STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION MMec h an i c al Int egr i t y Tes t jim.regg@alaska.gov;AOGCC.Inspectors@alaska.gov;phoebe.brooks@alaska.gov chris.wallace@alaska.gov Notes:Non-witnessed diagnostics MIT-IA Notes: 2L-305 Notes: Notes: Notes: ConocoPhillips Alaska Inc, Kuparuk / KRU / 2L Pad Galle 04/27/22 Form 10-426 (Revised 01/2017)2L-305 Diagnostic MIT-IA 27 April 22.xlsx Last Tag Annotation Depth (ftKB) End Date Wellbore Last Mod By Last Tag: SLM 8,534.0 8/30/2014 2L-305 hipshkf Last Rev Reason Annotation End Date Wellbore Last Mod By Rev Reason: Welded a 9" Conductor extension 5/27/2022 2L-305 bsgreen Casing Strings Casing Description CONDUCTOR OD (in) 16 ID (in) 15.06 Top (ftKB) 29.7 Set Depth (ftKB) 108.8 Set Depth (TVD) (ftK 108.7 Wt/Len (lb/ft) 62.58 Grade H-40 Top Connection WELDED Casing Description SURFACE OD (in) 7 5/8 ID (in) 6.44 Top (ftKB) 28.5 Set Depth (ftKB) 2,667.2 Set Depth (TVD) (ftK 2,291.1 Wt/Len (lb/ft) 45.50 Grade L-80 Top Connection BTC-MOD Casing Description PRODUCTION 5.5"x3.5" OD (in) 5 1/2 ID (in) 4.95 Top (ftKB) 25.3 Set Depth (ftKB) 9,198.6 Set Depth (TVD) (ftK 5,656.1 Wt/Len (lb/ft) 15.50 Grade L-80 Top Connection LTC MOD Tubing Strings: string max indicates LONGEST segment of string Tubing Description TUBING String Ma 3 1/2 ID (in) 2.99 Top (ftKB) 23.4 Set Depth (ftKB) 8,384.1 Set Depth (TVD) (ftK 5,252.5 Wt (lb/ft) 9.30 Grade L-80 Top Connection EUE8rd Completion Details: excludes tubing, pup, space out, thread, RKB... Top (ftKB) Top (TVD) (ftKB)Top Incl (°) Item Des Nominal ID (in) OD Nominal (in)Make Model 23.4 23.4 0.00 HANGER 3.500 8.000 511.7 511.7 0.66 NIPPLE 2.875 4.470 5,283.5 3,535.6 57.91 GAS LIFT 2.900 4.725 CAMCO KBG-2-9 8,257.0 5,186.5 58.53 SLEEVE 2.813 4.500 8,307.0 5,212.6 58.70 GAS LIFT 2.900 4.725 CAMCO KBG-2-9 8,359.2 5,239.6 58.75 NIPPLE 2.750 4.470 8,366.3 5,243.3 58.75 LOCATOR 2.985 4.000 8,367.1 5,243.7 58.75 SEAL ASSY 2.985 4.000 Other In Hole (Wireline retrievable plugs, valves, pumps, fish, etc.) Top (ftKB) Top (TVD) Top Incl (°)Des Com Run Date ID (in) SN 9,000.0 5,563.1 61.33 FISH FISH 1.85" ROLLER WHEEL LOST IN RATHOLE 6/4/2001 6/4/2001 0.000 Mandrel Inserts : excludes pulled inserts St ati on N Top (ftKB) Top (TVD) (ftKB) Top Incl (°)Make Model OD (in) Serv Valve Type Latch Type Port Size (in) TRO Run (psi)Run Date Com 1 5,283.5 3,535.6 57.91 1 GAS LIFT DMY INT 0.000 0.0 12/6/1998 2 8,307.0 5,212.6 58.70 1 GAS LIFT DMY INT 0.000 0.0 11/13/2004 Perforations & Slots Top (ftKB) Btm (ftKB) Top (TVD) (ftKB) Btm (TVD) (ftKB)Linked Zone Date Shot Dens (shots/ft)Type Com 8,526.0 8,534.0 5,326.0 5,330.1 S-8, 2L-305 6/7/2005 6.0 APERF 2.5"HSD PJ/2506 PJ,60deg ph 8,548.0 8,556.0 5,337.3 5,341.4 S-7, 2L-305 6/7/2005 6.0 APERF 2.5"HSD PJ/2506 PJ, 60deg ph 8,586.0 8,604.0 5,356.7 5,365.8 S-5, S-3, 2L-305 6/7/2005 6.0 APERF 2.5"HSD PJ/2506 PJ,60deg ph 8,648.0 8,688.0 5,388.2 5,408.4 T-2, 2L-305 12/22/1998 6.0 IPERF 2.5" HC, BH,60 DEG PH 8,690.0 8,700.0 5,409.4 5,414.5 T-2, 2L-305 6/7/2005 6.0 APERF 2.5"HSD PJ/2506 PJ,60deg ph 8,712.0 8,722.0 5,420.5 5,425.5 T-1.5, 2L-305 6/7/2005 6.0 APERF 2.5"HSD PJ/2506 PJ,60deg ph Notes: General & Safety End Date Annotation 5/22/2022 NOTE: Welded a 9" Conductor extesnion 1/9/2012 NOTE: T x IA ON MI. WATER INJECTION ONLY. 6/15/2009 NOTE: VIEW SCHEMATIC w/Alaska Schematic9.0 2L-305, 5/27/2022 4:25:02 PM Vertical schematic (actual) PRODUCTION 5.5"x3.5"; 25.3-9,198.6 CASING SHOE; 9,196.7-9,198.6 FLOAT COLLAR; 9,102.3-9,103.4 FISH; 9,000.0 APERF; 8,712.0-8,722.0 APERF; 8,690.0-8,700.0 IPERF; 8,648.0-8,688.0 APERF; 8,586.0-8,604.0 APERF; 8,548.0-8,556.0 APERF; 8,526.0-8,534.0 PROD CASING XO; 8,388.4-8,389.1 PROD CASING CSR; 8,369.1-8,388.4 SEAL ASSY; 8,367.1 LOCATOR; 8,366.3 NIPPLE; 8,359.2 GAS LIFT; 8,307.0 SLEEVE; 8,257.0 GAS LIFT; 5,283.5 SURFACE; 28.5-2,667.2 CASING SHOE; 2,665.7-2,667.2 FLOAT COLLAR; 2,581.2-2,582.6 NIPPLE; 511.7 CONDUCTOR; 29.7-108.7 CASING HANGER; 28.5-31.2 CASING HANGER; 25.3-28.3 HANGER; 23.4 KUP INJ KB-Grd (ft) 37.50 RR Date 12/6/1998 Other Elevatio 2L-305 ... TD Act Btm (ftKB) 9,210.0 Well Attributes Field Name TARN PARTICIPATING AREA Wellbore API/UWI 501032027900 Wellbore Status INJ Max Angle & MD Incl (°) 65.77 MD (ftKB) 4,469.95 WELLNAME WELLBORE2L-305 Annotation Last WO: End DateH2S (ppm) DateComment SSSV: NIPPLE From:Well Integrity Specialist CPF2 To:Wallace, Chris D (OGC) Subject:RE: [EXTERNAL]RE: CPAI 2L-319 (PTD #207-112) & 2N-306 (PTD #204-062) 30 day monitor period for diagnostic testing. Date:Thursday, July 21, 2022 12:58:21 PM Attachments:image001.png Chris- CPAI intends to perform the MIT-OA/SCLD on a two year basis as an internal requirement but in our experience with AIO 16.004 the SCLD can be a multiple day event in which the AOGCC inspectors have previously waived witness. It is not a problem to add the MIT-OA/SCLD to the AA requirement and offer the opportunity to the inspectors to witness and if that is the preferential approach CPAI has no problems with that. In the cases of these three wells, each has been completed without an OA shoe so it will always be a SCLD vs a MIT-OA. What would be the preference for reporting the results of the SCLD? The technique/results don’t match the formatting on the 10-426 forms. Are we just reporting them as a pass or fail in an email? On another note, we started the discussion of the UIC compliance testing for 2P-pad injectors. After additional thought, CPAI intends to complete the tests within the normal testing month (AUG 2022) with the wells shut in. This will both keep us within our normal testing operations and will provide an initial set of data regarding the conditions of the tubing, production casing and packers. The non-witnessed tests will be reported as usual. Let me know if you would like to approach this in a different manner. Great to see you the other day, its been a long time! Dusty Freeborn Wells Integrity Specialist ConocoPhillips Alaska, Inc. Office phone: (907) 659-7224 Cell phone: (907) 830-9777 From: Wallace, Chris D (OGC) <chris.wallace@alaska.gov> Sent: Wednesday, July 20, 2022 1:57 PM To: Well Integrity Specialist CPF2 <n2549@conocophillips.com> Subject: [EXTERNAL]RE: CPAI 2L-319 (PTD #207-112) & 2N-306 (PTD #204-062) 30 day monitor period for diagnostic testing. CAUTION:This email originated from outside of the organization. Do not click links or open attachments unless you recognize the sender and know the content is safe. Dusty, CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. I am progressing the AA amendment requests for these two wells and 2L-305. The requests all mention the MITOA or SCLD criteria and testing but this requirement has not been carried over to the proposed operating and monitoring plan. As with AIO 16.004 amendment, we plan to add the MITOA/SCLD requirement via this language: 4. CPAI shall perform a mechanical integrity test of the outer annulus (MITOA) every 2 years to not less than 1200 psi or a passing surface casing leak detect (SCLD) log; Please let me know if I am missing something or why the MITOA/SCLD should not be a two year requirement. I also note CPAI criteria of IA draw down test - but I haven’t made that an AOGCC requirement. Thanks and Regards, Chris Wallace, Sr. Petroleum Engineer, Alaska Oil and Gas Conservation Commission, 333 West 7th Avenue, Anchorage, AK 99501, (907) 793-1250 (phone), (907) 276-7542 (fax), chris.wallace@alaska.gov CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Chris Wallace at 907-793-1250 or chris.wallace@alaska.gov. From: Well Integrity Specialist CPF2 <n2549@conocophillips.com> Sent: Thursday, July 7, 2022 2:53 PM To: Wallace, Chris D (OGC) <chris.wallace@alaska.gov> Cc: Well Integrity Specialist CPF2 <n2549@conocophillips.com> Subject: CPAI 2L-319 (PTD #207-112) & 2N-306 (PTD #204-062) 30 day monitor period for diagnostic testing. Chris- Kuparuk Tarn injectors 2L-319 (PTD #207-112) and 2N-306 (PTD #204-062) have completed their 30 day monitor periods. Both IAs have shown stabilization below the DNE of 2400 psi while on gas injection and have now met all of the criteria in which CPAI requires to continue WAG injection with known tubing by inner annulus communication. It is CPAI’s intention to submit an application for continued WAG injection with known tubing by inner annulus communication. While the AAs are in process the well will be left in gas injection service. Attached are the current 90 day TIO plot and well bore schematic. Please let me know if you have any questions or disagree with the plan. Dusty Freeborn Wells Integrity Specialist ConocoPhillips Alaska, Inc. Office phone: (907) 659-7224 Cell phone: (907) 830-9777 From: Well Integrity Specialist CPF2 Sent: Friday, May 27, 2022 7:50 AM To: Wallace, Chris D (CED) <chris.wallace@alaska.gov> Cc: Well Integrity Specialist CPF2 <n2549@conocophillips.com> Subject: CPAI 2L-305 (PTD #198-240), 2L-319 (PTD #207-112), 2N-306 (PTD #204-062) & 2N-337C (PTD #214-121) 30 day monitor period for diagnostic testing. Chris- CPAI has identified four Tarn injectors 2L-305 (PTD #198-240), 2L-319 (PTD #207-112), 2N-306 (PTD #204-062) & 2N-337C (PTD #214-121) that were previously waivered for water injection only due to known TxIA while on gas injection. During a recent reservoir evaluation, these 4 wells were identified to have a significant production benefit from the ability to inject MI. CPAI has developed criteria under which it believes a gas injection well may operate safely with TxIA communication. That criterion includes the well having casing rated high enough to support maximum anticipated injection pressure of gas injection should a barrier fail, passing a MITIA to maximum anticipated injection pressure of gas injection, passing a MITOA or SCLD, and passing an IA DDT on water or gas injection and during gas injection service the IA pressure must sustain below the “do not exceed” of 2400 psi. These wells meet the above criteria and CPAI has conducted diagnostic MIT-IAs and SCLDs all with passing results. The remaining criteria yet to be met is the ability to maintain IA pressure under DNE of 2400 psi while on gas injection. Therefore, CPAI intends to place 2L-305, 2L-319, 2N- 306 & 2N-337C into gas injection service for a 30 day monitor period. If the 30 day monitor period displays the ability of the IAs to sustain a pressure below the DNE, CPAI intends to apply for administrative approval for continued WAG injection with known TxIA communication while on gas injection. Attached are the current 90 day TIO plots and wellbore schematics. Please let me know if you have any questions or disagree with the plan. Dusty Freeborn Wells Integrity Specialist ConocoPhillips Alaska, Inc. Office phone: (907) 659-7224 Cell phone: (907) 830-9777 April 9, 2019 Commissioner Jessie Chmielowski: Alaska Oil & Gas Conservation Commission 333 West 71h Avenue, Suite 100 Anchorage, AK 99501 Commissioner Chmielowski: APR 11 2019 AOGCC ConocoPhillips Alaska, Inc. presents the attached proposal per AIO 16, Rule 10, to apply for an Administrative Amendment to AIO 16.004 to allow KRU Tarn injection well 2L- 310 (PTD 210-028) to allow WAG injection service. Currently the well has known tubing by inner annulus communication only while on gas injection. If you need additional information, please contact us at your convenience. Sincerely, Jan Byrne / Kelly Lyons Well Integrity Supervisor ConocoPhillips Alaska, Inc. Office phone: (907) 659-7224 WELLS TEAM ConocoPhillips Alaska P.O. BOX 100360 ANCHORAGE, ALASKA 99510-0360 Kuparuk River Unit Tarn Well 2L-310 (PTD 210-028) Technical Justification for Amendment to Area Injection Order 16.004 Purpose ConocoPhillips Alaska, Inc. (CPAI) requests that the AOGCC approve this Administrative Amendment to AIO 16.004, as per AIO 16, Rule 10, to allow water alternating gas (WAG) injection for Kuparuk River Unit Tarn injection well 2L-310 (PTD 210-028). Currently AIO 16.004 allows water -only injection. The well displays tubing by inner annulus (IA) communication only during gas injection. Well History and Status Kuparuk River Unit Tarn well 2L-310 was completed in 2010 as a producer. It was converted to WAG injection in 2013. 2L-310 was initially reported to the Commission in February 2014 for a suspect IA pressure increase while on miscible gas injection. Diagnostics confirmed that the leak was a gas -only and the AOGCC granted CPAI's request to for Administrative Amendment to allow the well to continue operating with water -only injection on April 14, 2014. At the time of the initial request, ConocoPhillips policy did not allow gas injection wells with gas -only tubing leaks. CPAI has since developed criteria under which it believes a gas injection well may operate safely with TxIA communication. That criteria includes the well having casing rated high enough to support MAIP of gas injection should a barrier fail, passing an MITIA to MAIP of gas injection, passing a MITOA or SCLD, passing Pack Off Tests (POTS), and passing a IA DDT on water injection. During gas injection service the IA pressure must maintain below the MAOP of 2400 psi with no more than two non -thermal bleeds per month. In addition, pressure transmitters will be maintained on the IA and OA allowing real time monitoring and alarm notifications. Adhering to this new criteria CPAI performed passing test including POTS, SCLD, and MITIA to 3850 psi in preparation for an AOGCC approved monitor period on MI to determine IA pressure Build Up Rate (BUR). From September 30, 2019 to November 23, 2019 the well was on miscible injection. During the first 27 days The IA pressure BUR was approximately 55 psi per day with one IA pressure bleed during that time. Then the IA pressure stabilized around 2000 psi with only a 5 psi per day BUR the last 27 days. After the BUR was determined to be manageable by bleed the well was logged with an ultrasonic acoustic tool, but the report found no verifiable anomalies. At this time CPAI is unable to locate the leak(s) with current technology and the well does not currently meet RWO metrics. However, CPAI believes that 2L -310's current condition along with the new well testing and operating criteria outlined above will allow the well to be operated safely without threatening human safety or the environment. Therefore, CPAI request an Administrative Amendment to AIO 16.004 that will allow 2L-310 to resume WAG injection. Well Integrity Supervisor 4/9/2019 ConocoPhillips Alaska P.O. BOX 100360 ANCHORAGE, ALASKA 99510-0360 Barrier and Hazard Evaluation Barriers in place are sufficient to allow safe operation with water alternating gas injection service. Tubing: The 3-1/2", 9.3 lb/ft, L-80 tubing has integrity to the Baker FHL packer at 9737' MD (5238' TVD) based on the passing MITIA to 3850 psi on August 10, 2018 and TIO trends. Production casing: The 7-5/8", 29.7 lb/ft, L-80 production casing has integrity to the Baker FHL packer at 9737' MD (5238' TVD) based on the aforementioned passing MITIA and TIO trends. Surface casing: The well is completed with 10-3/4", 45.5 lb/ft, L-80 surface casing with an internal yield pressure rating of 5210 psi. The surface casing has integrity based on the passing SCLD performed August 12, 2018 and TIO trends. Primary barrier: The primary barrier during water injection to prevent a release from the well and provide zonal isolation is the tubing and packer. The primary barrier during gas injection to prevent a release from the well and provide zonal isolation is the production casing. The tubing and packer also act as a limited barrier, so that the pressure build-up is manageable with no more than two non -thermal bleeds per month during gas injection. Secondary barrier: The production casing is the secondary barrier during water injection, should the tubing fail. The surface casing is the secondary barrier during gas injection, should the production casing fail. Tertiary barrier: The surface casing will act as a tertiary barrier during water injection, in the unlikely case that the first two normal barriers have failures. Monitoring: This well will be monitored real time for wellhead pressure changes. The IA will be bled on an occasional basis (no more than two non -thermal bleeds per month during gas injection) in order to maintain pressure within operating limits. Any pressure trends that indicate further annular communication require investigation, Commission notification, and corrective action, up to and including a shut-in of the well. TIO trends are compiled, reviewed, and submitted to the AOGCC for review on a monthly basis. Proposed Operating and Monitoring Plan 1. Well will be used for water alternating gas injection; 2. Perform a passing MITIA every 2 -years to maximum anticipated injection pressure; 3. Allow operating IA pressure up to 2,400 psi during gas injection service and 2,000 psi during water injection service; operating OA pressure up to 1,000 psi; 4. Bleed pressure from the IA as necessary to maintain pressure within operating limits, not to exceed two non -thermal bleeds per month during gas injection; 5. Submit monthly reports of daily tubing, IA, and OA pressures, injection volumes and pressure bleeds for all annuli; 6. Shut-in the well should diagnostic testing or injection rates and pressures indicate further problems with appropriate notification to the AOGCC; Well Integrity Supervisor 4/9/2019 2 ConocoPhillips Alaska P.O. BOX 100360 ANCHORAGE, ALASKA 99510-0360 MIT Anniversary date to be set the month of August 2020 to align the 2 -year AOGCC witnessed testing with the UIC MIT permanent 4 -year scheduled pad testing; Well Integrity supervisor 4/9/2019 vat N«R.: zlaw Stan Daec !-Jan-2819 Dals: 90 EnAOaI.: bA,02019 ROInKh Annular Communkation Surveillance 3000 170 300 sso zwa lw tsao 13a a 1000 90 w0 70 0 w g g g g g 9 9 —WW —1M —OAC —W1R Annular Communication Surveillance 1 0.9 M 0.7 66 0.3 0.a 0.3 0.7 0.1 0 y qq * —Dci —mi —RA• SWI —HIM 2L-310 Vi2119 315 1 314 94NER PWI STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION Mechanical Integrity Test Submit to: iim.rega(&alaska.goV; AOGCC Inspeclors(dalaskituoV: phoebe brooks(dWaska.gov OPERATOR: ConocoPhillips Alaska Inc FIELD/UNIT/PAD: Kuperuk/KRU/2L Pad DATE: 08/10/16 OPERATOR REP: Arend AOGCC REP: N/A chns.wallace(a).alaska.gov Well 21--310 Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. P=Pressure Test 1=Initial Test PTD 2100280 Type Inj W Tubing 1800 1800 1800 1800 V= Required by Variance 1=Inconclusive Type Test P Packer ND 5239 BBL Pump 4.6 IA 930 3850 3800 3800 MIT KRU 2L-310 diagnostic MITIA 8-10-18.x1ax Interval O Test psi 3500 BBL Return OA 320 357 357 357 Result P Notes: Diagnostic MITIA to MAIP in anticipation of AA well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer ND BBL Pump IA Interval Test psi BBL Return OA Result Notes: Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer ND BBL Pump IA Interval BBL Return OA Result Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. kP..kerTVD Type Inj Tubing Type Test BBL Pump IA Interval BBL Return OA Result Notes: Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer ND BBL Pump IA Interval Test psi BBL Return OA Result Notes: INTERVAL Codes Result Codes TYPE [NJ Codes TYPE TEST Cotler W=Water P=Pressure Test 1=Initial Test P=Pass G = Gas O = Other (describe In Notes) 4 = Four Year Cycle F= Fail B=&luny V= Required by Variance 1=Inconclusive I = IndusNal Wastewater O = Other (describe in notes) N = Not Injecting Form 10-426 (Revised 01/2017) MIT KRU 2L-310 diagnostic MITIA 8-10-18.x1ax v% KUP INJ 2L-310 eonoeo fillips Well Attributes Max Angle&MO TO �dSKd If1C *;�) VVel168re PPIlU1M FIND III Well bore 5lalus 501032061600 TARN PARTICIPATING AREA INJ n[I I°I MM., Ac[a-1ANB) 6].51 2.78072 10,2520 Comment H25 ap rn Dar SSSV'.NIPPLE Anno=n EnE Oatt Last WO: KOGM in, PoB Rnitlaa Dah 3310 5/1312010 NOR6ONTAL- ztam, 111 .1. 1 o5: 15 pM AnnofaYon OepA 1nN61 Enb Dale gnnoldllon LaSIMOE By FnC DNe LasITa95LM 1=042.0 11/15/2015 Rev Reason PULLED PLUG and PATCH ppNT 1li812016 BA..FR: z39asmg nngs $e caamg Dee[npgon o0 In1 1011n1 Top InM61 Set (nN6 Fel Dept (Tv0)... wUlen p... Glade Tep mreaE CONDUCTOR i6 15.062 260 112.0 1120 6250 H40 WELDED Calla, Dezcnptlon OD (Inl ID llnl Top SNU' Set Deplh IRHB1 Dept 1TVG).. WEI II..G Top n—A $e SURFACE 16314 9950 276 3,521.0 24167 4550 LBBB BTC Wb asing Dezcnptlon o0(Inj I011n) Top(P"I Se10epN"1 Sat Depa ITVD).. Len B.,. G,Me Top Tnuaa PRODUCTION ]5/6 6875 256 10,24]A 5.6152 29]0 L-80 pip Tubing Strings TubingA Oescrlpllon Slring Ma... 1011nf Top (nkDI Sel Oepon IR. aeI Go'n ITV011... W1(IbIR) Gndo Top C—Rellon IS TUBING 31/2 2.992 23.3 98000 5,2832 930 L-80 EUEBrtlABM00 Completion Details xominal lD Top (SEE) Top (TVC)nes) Top Incl l°) I.. Co. tin) 23.3 233 0.00 HANGER FMC GEN V TUBING HANGER 2992 516.4 5159 454 NIPPLE CAMCOOSNIPPLEw/28]5"PROFILE 2075 9,671.2 5,1940 48.89 SLEEVE -C BAKER CMU SLIDING SLEEVE aSneN2.9 PR0FILE 2.812 caxoucrore. z9D-um 9,7238 5,229.d 46.52 PER BAKER 8640 PER 2.990 9,7372 6238.6 4602 PACKER BAKERFHLPACKER 2,990 $]90.3 FIVE 4403 NIPPLE CAMCO'D' NIPPLE w/2]5"NO GO 2750 NIPPLE .as4 97995 5,2828 4369 WLEG WREUNE ENTRY GUIDE 2.920 Other In Hole (Wireline retrievable plugs, valves, pumps, fish, etc.) Top (TAD) Topmdl TOP(WI) (nKB) r) No Cam wnoar to (in) 6,930.0 3,829] 62.90 PATCH 2.72- SOS UPPER PARAGON II PACKER(seBi cap 1/15/2016 1.625 35040) W/ 15,49' SPACER PIPE S IATCH ASSEMBLY (ser# coal 35018) 6.9530 3936.fi 6292 PATCH 272" SOS LOWER PARAGON II PACKER(s9M 1/15@016 1.625 cpp35043) SURFACE', 276.3.5214 Perforations & Slots .Par —S Top(NO) 51m jNO) (dhand" CAS LIFT; 3.S9Tt Top lnkBl Btm 11IXB) (RK01 (rIHBI IDne Dale I Type tom 10.005.0 10.019.0 5,430.5 5p449 BPNNUGa 2L B/82D1a ou IPERF 2.5"Pm9pecfor RD%DP 310 chary¢., 60 deg phase Stimulations & Treatments PATCF:,1d5 .I. Top Ma, P. DepN .."In Top(N01 I B[m (ND) PATCN;95]A (MB) (flKBI MU.) IRS.) TIP. Dale Com 10,0058 1%019.0 S,d34.5 5,444.9 FRAC 81102010 PUnfla 262E" Das of Calbolite, placing 240,7311b5 behlnd pipe (pumped 2,602 bbl. of fluid). Collpleled ERA, w19 ppa on fartretlon. Mandrel Inserts GAS LIFT: 9.)169 SL .1 N Top Too) Top poren (MB) Make Model ODgn) a., Wlae Larn PoRSIae TROPo,n Type Typa 0.) 101) Run Palo Co. 1 3,697.2 2,4986 Garuda KSG-2- 1 GAS LIFT UMY IN 0.000 0.0 51191010 930 9 2 8,7168 4.720.8 Ca11wo KBG-2- 1 GASLIFT DMY INT 0000 OA 51192010 500 9 cnsuFT: es1T2 3 96172 5,1593 CamW HSG2 1 GAS LIFT DMT INT 0000 00 5/12/2013 1:00 9 Notes: General & Safety End Data Annonar. 5/18/2010 NOTE: VIEWSCHEMATIC w/Alaska SCM1emelica0 5/1612013 NOTE'. CONVERTED TO INJECTION (PRE -PRODUCED 3 YEARS) SLEEVEC:9Ani 5/15/2016 NOTE'. TXIAONMI. WATERINJECTIONONLY. PAC IUS; 9.7372 NRPLE;RTAPS WLEG.R79g5 IPEIRPROOSIF BM90 RAC 10.aa3A PRODUCTION;25.LE102470 17 ConocoPhillips Alaska P.O. BOX 100360 ANCHORAGE, ALASKA 99510-0360 March 17, 2019 Commissioner Hollis French Alaska Oil & Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, AK 99501 Dear Commissioner French: MAR '10 2n,o AaOGC ConocoPhillips Alaska, Inc. presents the attached proposal per AIO 16, Rule 10, to apply for Administrative Approval allowing KRU Tarn well 2N -337C (PTD 214-121-0) to be online in water only injection service. Currently, the well displays TxIA communication only when injecting gas. If you need additional information, please contact myself or Jan Byrne at 659-7224. Sincerely, Kelly Lyons Well Integrity Supervisor ConocoPhillips Alaska Inc. Cc: Working Well File, Legal Well File ConocoPhillips Alaska, Inc. Kuparuk River Unit Tarn Well 2N -337C (PTD# 214-121-0) Technical Justification for Administrative Relief Request Purpose ConocoPhillips Alaska, Inc. proposes that the AOGCC approve this Administrative Relief request as per Area Injection Order 16, Rule 10, to continue water only injection for Kuparuk River Unit Tarn injection well 2N -337C. The well displays annular communication only when the well is on gas injection. Well History and Status Kuparuk River Unit Tarn well 2N -337C (PTD 214-121-0) was drilled and completed in December 2014 as a WAG service injection well. 2N -337C was initially reported to the Commission on January 31, 2019, as demonstrating anomalous inner annulus pressure trends while on gas injection. During the approved gas injection monitor period, the well continued to display evidence of tubing by inner annulus communication. The well was then WAG'ed to water injection on February 16, 2019, to confirm the theory that the IA pressurization was due to a gas -only leak. Apart from the thermally - induced, minor fluctuations of the IA, the well does not shows signs of communication when on water injection (see attached TIO plot). A passing non -witnessed diagnostic MITIA to 3550psi was performed on February 4, 2019. ConocoPhillips intends to pursue repairs if the leak worsens enough to be detectable and located while on water injection. However, until the leak is detectable both on gas and water injection, ConocoPhillips requests an AA which will allow the well to remain online in water only injection service. The IA pressure will be maintained below 2000 psi. Barrier and Hazard Evaluation With only water injection, this well has all the barriers of a normal injection well Tubing: The 3-1/2" 9.2# L-80 tubing has integrity to the Baker Bullet Tie back seal assembly @ 6821' MD (4894' TVD), based on passing normal operating differential pressures while on water injection and the passing diagnostic MITIA to 3550psi performed on February 4, 2019. Production casing: The 5.5" 15.54 L-80 production casing has integrity to the Baker Bullet Tie back seal assembly @ 6821' MD (4894' TVD) based on the passing MITIA described above. The 5.5" has an internal yield pressure rating of 7000 psi. Surface casing: The well is completed with 7-5/8" 29.7# L-80 surface casing with an internal yield pressure rating of 6890 psi. The surface casing is set at 2858' MD (2311' TVD) and the shoe was left open after being drilled out. Primary barrier: The primary barrier to prevent a release from the well and provide zonal isolation is the tubing and packer. Secondary barrier: The production casing is the secondary barrier should the tubing fail. Monitoring. Each well is monitored daily for wellhead pressure changes. Should leaks develop in the tubing or production casing above the surface casing shoe it will be noted during the daily monitoring process. Any pressure trends that indicate annular communication require investigation, Commission notification, and corrective action, up to and including a shut-in of the well. T/IO plots are compiled, reviewed, and submitted to the AOGCC for review on a monthly basis. Proposed Operating and Monitoring Plan 1. Well will be used for water only injection (no MI or gas injection allowed); 2. Perform a passing MITIA every 2 years to the maximum anticipated injection pressure; 3. Anniversary date to be set the month of August 2020 (Last Witnessed MIT: August 14, 2018) to align the 2 -year AOGCC witnessed testing with the UIC MIT permanent 4 -year scheduled pad testing; 4. Allow operating IA pressure up to 2000 psi, operating OA pressure up to 1000 psi; 5. Submit monthly reports of daily tubing, IA & OA pressures, injection volumes and pressure bleeds for all annuli; 6. Shut-in the well should MIT's or injection rates and pressures indicate further problems with appropriate notification to the AOGCC. KUP ]NJ 2N -337C ConoCONhiilips Well Attributes Max Angle &MD I TD A H61(B,InF Weli"I'PPI" FeIE Name Wellbore 61aru5 nd,, MD I,II., ACI Dim PKI) 5 0103 20 26 2 03 TARN PARTICIPATING AREA ]NJ 69.65 2,901.28 7,0298 Comment H2S Ippm1 Oale SSSV: NIPPLE 30 ]I12008 MnINaibn EnG 0a4 K84m at flip Relpse Date LBMWr0: 29.253I 2N33TC.3a5dNI74'EG33PM Por o scoman ae aouu Apn0laiionff p,0h XKB) Ead DMe Anndtibn Last MI By End Date Last Ta9:SLM 7,532.0 11712017 Rev Reason: PULL BOMB HANGER WICUAL pprown &151201] GAUGES S R Lasing Dascrlpiion 00(in) IDIIn) Top 111K"a bei DepiF(XNI31 Se10epth IND)... WVLen T. Grade Topni-bi CONDUCTOR 16 15062 29.2 '-R 1080 62.58 H-40 WELDED Gasn,.'rep- GD9n) ID lint Top (XKD) Set Depin (ryN0) SeI OepP ITVDI_. WVLen (I... Gntle Top ThleaO SURFACE ]SIB 3.875 29.3 2,8504 2,311.3 29.]0 L-80 BTC -MOD Cazlnp Descnpiion O011n) ID 6n) Top (XKO) Sel Dopiry (I1K0) Set Depth(TTs- Wit lt.. Gmtle Top TMmtl PRODUCTION 5112" 5112 4950 28.0 ].029.8 5,054.2 15.501.80 Hy0563 Casing Descrlpxon Q. (in) 10(In) Top(XKB) Eel DepinnlKD) bel Depthlvu,._WVLe1(I... Gra. Top Thread LINER 3112"- 3112 2.992 6,819E 7,653.0 5,5366 920 NO 511 CEMENTED Uner Details ino Top IXKR) Top Wo (I Top Inol (°) Item Des com lin) HMIGER:25.B- 6,619, 4892.6 4000 SLEEVE SETTING SLEEVE 4.130 6,840.0 4.9116.9 40.06 PACKER IF PACKER 3.000 6,0408 4.9153 4005 HANGER FLEX LOCK LINER HANGER 2.960 sed Tubing Strings inhm90ezcilpilDp e:nneMa.-mOnl To,(XKEI 6e Orem Vt. set Depth l-014-wtlmm) Ga. TOPConnecnoo T1ldMG'o'C 6914 3112 2992 256 6,639.9 4,908.5 920 L-80 E11E 01tl Completion De tags - - N>mmauo Top ars) Tnp TVD11nKB1 Top Ina (°) nem Des Co. (In) 25.8 25.8 0.00 HANGER FMC HANGER- PORTED DRIFTED TO 2.91" 2.992 OexOU$Og; 3R�gvg 483.0 483.4 8.06 NIPPLE CAME0 05 NIPPLE 2.875 6.601.3 4,]8].1 Sees SLEEVE BAKER CMU DS SLIDING SLEEVEDS PROFILE- 2.810 CLOSED NIPPLE: 493.9 5,]6].1 4,852.8 40.10 NIPPLE CAMCODNIPPLE 2.750 81820.8 4,8937 40.08 SEAL ASY SAKERSULLET TIE BACK SEAL ASSEMBLY Wl 7' 2.900 SPACE OUT Perforations & Slots Gboi Dens Top (NO) Ban Tm b1aw Top (I 91m tXKKEI (rise) (XKO) Zone Det, ry Type Cnm L 7,285.0 7,30.5.0 5,251.5 5,290.4 4132015 6.0 IPERF 2.5"HOLLO STEEL 6URFACe SGGUESEa- CARRIER SCALLOPED GUNS. 11.1 GRAM MILLENNIUM GABUFT:3.355.0 CHARGES 7,346.0 7,390.0 5,298.4 5.333.3 411 212015 6.0 (PERE 25"HDLL0WSTEEL CARRIERSCALLOPED GAS OF II GUNS, 11.1 GRAM MILLENNIUM CHARGES. 60 DEG PHASING GASGFT6.1652 7,435.0 7,455.0 5,308.1 5,383.5 411MOIS 6.01PERF 25"HOLLOWSTEEL CARRIER SCALLOPED GUNS, 11.1 GRAM MILLEINNUM CHARGE$ 60 DEG Ons uFi; S.ex.a PHASING 7.455.0 7,475.0 5,383.5 5,398.8 411112015 BE ,PERF 2.FH0LL0WSTEEL CARRIER, 11.1 GRAM SLEEMFB6813 MILLEINNUM DP CHARGES, 60 DEG PHASING 7,475.6 7,490.0 5398 8 5,410.3 312412015 60 IPERF 25" 11.1 GRAM NNPLE; B.RT.1 MJLLENIDM DP HARGES Stimulati0n6 & Treatments Proppant DeinnM lib) Prop pan i l n Formmion(le) Date 50I2007 Mandrel Inserts 6FPLn6Y:8.6ID.6 SI eN Na Top (N°1 To (StanWas Make Model ODBn) Sem u,ibe LaW PonSim THORun Type pe 9n) IpaB Run Ogle Cqm t1 3,355.0 2,690.6 CAMCO KBG-2- 9 1 GAS LIFT DMY INT 0.000 0.0 12252014 2 5,129.6 3,806.9 CAMCO KBG-2- 1 GASLIFT DMY INT 0.000 0.0 12252014 9 3 6168.2 4,385.6 CAMCO KBG2- 1 GAS LIFT DMY INT O.ODO 0.0 12252014 9 P500ucnON slR :m4 1 "mal InbrmeG'4e Gsira Cement:-'� 7 4 6,6239 4,743.1 CAMCO KBG-2- 9 1 GAS LIFT DMY INT 0,000 0.0 315,2015 s.zgD.°nKa IPERR72BS.47.W0-, IPERF.73450-7 aM.0� Notes: General & Safety Entl Dme Anmrarion NOTE'. IPERR7tl501.,S 0- IPERF.7,455A7,4TS0- IPERF],MC4,60.0 LINER 312- CEMENTED: 6,61E47,fiE3O� 11RPn0sfpnrrer;6,92E0_ y .a tart Dale: 17-Dae-2011 a1s: 90 nd Date: T7-Mar-M9 a¢ mn316M �1 r t ai 2718D9 2027 6pp_ WNEH PM Annular Commurowtion Surveillance __.2N-337 _ 2N-337 1385_ — 800 _ _1927 _ _.-.. 585. _ .. _ IfJftlER _ .MI5 as9a 2N-337 v3o7B _ _— ztoo - ._. 560 - -iwa------- InraEn.._.- _.rvus ssa _ saP tP _.__------- _._...__..__.._. _...__ ^ 9 n a a Armular Communication Surveillame ____�_____—____�_____ _._ ______�_-_____.._- Im Bao aua am zm a —DGI —IAGI —PWI SWI —81.PO STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION Mechanical Integrity Test Submit to: iim.reaoCrDalaskaoov AOGCC.Inspectors(cD.alaska.00v: ohoebe.bmoksBalaska.aov, OPERATOR: ConocoPhillips Alaska Inc FIELD/UNIT/PAD: Tarn /KRU/2N Pad DATE: 02/04/19 OPERATOR REP: Miller AOGCC REP: notwitnessed chds wallaceCdalaska cov Well 2N -337C Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD 2141210 Type Inj N Tubing 2960 2940 2940 2940 Type Test P Packer TVD 4894 BBL Pump 2.5 IA 1385 3550 3500 3490 Interval O Test psi 1500 1 BBL Return OA 100 250 225 225 Result P Notes: Diagnostic MITIA Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBI -Pump IA Interval Test psi BBL Return OA Result Notes: Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Notes: Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Noe Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTO Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Notes: TYPE INJ Codes W = Water G = Gas S=Slurry 1=industrial Wastewater N= Not Injecting TYPE TEST Codes INTERVAL Codes Result Codes P=Pressure Test I=Initial Test P=Pass O= Other (describe, in Notes) 4=Four Year O/de F=Fall V = Required by Variance I=Inconclusive 0= Other (describe In notes) Form 1GA26 (Revised 01/2017) MIT KRU 2W337C diagnostic MITIA 02.04d9.xlax 16 ConocoPh i I I i ps Alaska P.O. BOX 100360 ANCHORAGE, ALASKA 99510-0360 February 23, 2017 Chris Wallace Alaska Oil and Gas Commission 333 West 7ch Avenue, Suite 100 Anchorage, AK 99501 Dear Mr. Wallace, RECEIVED FEB 2 7 2017 U S IF Last year on March 26, 2016, CPAI submitted a proposal to the AOGCC for your consideration. After nearly a year of implementation of accelerated MIT testing, efficiencies in time and resources for both CPAI and AOGCC inspectors have been demonstrated. Therefore, CPAI would like to reiterate our request to have a blanket amendment be approved to change the MIT anniversary dates of all of the wells which operate under an Administrative Approval to align with the UIC test month schedule. Attached is an updated list with all of the AA'd wells, which include their existing and proposed new anniversary dates, the dates of their last witnessed tests and notes which detail how CPAI intends to test each well to keep the wells within compliance and achieve their new anniversary testing months. In addition to the changes in anniversary dates, we would also like to reiterate our request to align the MITIA test pressure criteria with current requirements. There are 6 older AA's that require "1.2 times the maximum anticipated injection pressure" for the MITIA criteria. The wells in question are 113-11, 2K-03, 2K-10, 3K-11, 3Q-05, CD4- 209. CPAI requests that the AA MITIA test criteria for these wells be changed to "maximum anticipated injection pressure". CPAI still would like the other topics which were included in the March 2016 letter to be considered by the AOGCC. But it is understood that they will be addressed at a future date. If you need additional information or have any questions, please contact myself or Brent Rogers at 659-7224. Sincerel , Kelly Lyo Well Integrity Supervisor ConocoPhillips Alaska, Inc. Anniversary Date Amendement Proposal Well name AIO # Existing Anniversary Date Date Last Witnessed Test Proposed New Notes Anniversary Test Month 1A-04A AIO 2B.011 5/30/2006 5/12/2016 July 2017 1A pad next due July of 2019. Well to be tested on or before 7/31/17 to get on schedule. 1A-06 AIO 2C.031 July 2017 2/4/2016 July 2017 No changes 1A-12 ATO 2B.049 3/16/2010 2/20/2016 July 2017 Well to be tested on or before 7/31/17 to get on schedule. 1A-16RD AIO 213.075 3/22/2015 3/22/2015 July 2017 CPAI requests a delay of 4 months to allow the test on or before 07/31/17 to get on schedule. 113-08A AIO 2C.027 8/7/2015 7/12/2013 June 2017 1B pad next due June of 2017. Well to be tested on or before 6/30/17 to get on schedule. 16-11 AIO 213.060 7/6/2011 7/7/2015 June 2017 Well to be tested on or before 6/30/17 to get on schedule. 1D-38 AIO 2C.010 8/26/2014 8/7/2016 July 2018 1D pad next due July of 2018. Well to be tested on or before 7/31/18 to get on schedule. 1E-08A AIO 28.065 8/30/2011 8/27/2015 June 2018 1E pad next due June of 2018. Well to be tested on or before 8/30/17 and then tested on or before 06/30/18 to get on schedule. 1E-15A AIO 2B.081 12/8/2013 1/8/2017 June 2018 Well to be tested on or before 6/30/18 to get on schedule. 1E-22 AIO 213.078 6/16/2013 1/8/2017 June 2018 Well to be tested on or before 6/30/18 to get on schedule. 1F-04 AIO 2C.006 9/16/2014 6/15/2016 June 2018 1F pad next due June 2020. Well to be tested on or before 6/30/18 to get on schedule. 1F-05 A1O.213.080 7/12/2012 6/15/2016 June 2018 Well to be tested on or before 6/30/18 to get on schedule. 1F-16A AIO 2C.018 3/24/2015 6/15/2016 June 2018 Well to be tested on or before 6/30/18 to get on schedule. 1G-01 AIO 213.035 6/28/2008 6/21/2016 July 2017 1G pad next due July of 2019. Well to be tested on or before 7/31/17 to get on schedule. 1L-05 AIO 213.054 8/11/2010 6/1/2016 June 2018 1L pad next due June of 2020. Well to be tested on or before 6/30/18 to get on schedule. 1L-07 AIO 2C.008 10/28/2014 6/1/2016 June 2018 Well to be tested on or before 6/30/18 to get on schedule. 1L-10 AIO 26.083 2/22/2014 6/1/2016 June 2018 Well to be tested on or before 6/30/18 to get on schedule. 1L-22 AIO 2C.042 June 2018 6/3/2016 June 2018 No changes 1Q-09 AIO 2B.093 5/30/2014 5/26/2016 July 2017 1Q pad next due July of 2017. Well to be tested on or before 7/31/17 to get on schedule. 1Q-13 AIO 26.090 6/29/2014 6/21/2016 July 2017 Well to be tested on or before 7/31/17 to get on schedule. 1Q-14 AIO 2C.034 July 2017 7/9/2013 July 2017 No changes 1Q-24 AIO 2C.017 3/11/2015 2/20/2017 July 2017 Well to be tested on or before 7/31/17 to get on schedule. 1R-15 AIO 2B.088 1/12/2014 1/2/2016 May 2017 1R pad next due May of 2019. Well to be tested on or before 5/31/17 to get on schedule. 1Y-08 AIO 213.056 6/15/2010 6/5/2016 July 2017 3Y pad next due July 2017. Well to be tested on or before 7/31/17 to get on schedule. 1Y-09 AIO 213.051 5/20/2010 5/7/2016 July 2017 Well to be tested on or before 7/31/17 to get on schedule. 1Y-10 AIO 2C.014 8/29/2014 8/18/2016 July 2017 Well to be tested on or before 7/31/17 to get on schedule. 213-06 AIO 2C.012 12/26/2014 5/1/2016 May 2018 2B pad next due May of 2020. Well to be tested on or before 5/31/18 to get on schedule. 213-07 AIO 2C.024 12/18/2014 5/1/2016 May 2018 Well to be tested on or before 5/31/18 to get on schedule. 213-10 AIO 213.073 2/14/2013 7/31/2016 May 2018 Well to be tested on or before 5/31/18 to get on schedule. 2C-03 AIO 26.085 2/5/2013 2/20/2016 August 2017 2C pad next due August 2017. Well to be tested on or before 8/31/17 to get on schedule. 2C-04 AIO 213.091 6/21/2014 6/21/2014 August 2015 This well has been offline since 3/31/16. If the well is BOI it will be tested post stabilization and then again on the earliest date to align with the schedule. 2C-07 A10 213.007 2/5/2006 2/5/2012 August 2015 This well has been offline since 9/12/12. If the well is BO1 it will be tested post stabilization and then again on the earliest date to align with the schedule. 2C-08 AIO213.086 3/4/2014 2/20/2016 August 2017 Well to be tested on or before 8/31/17 to get on schedule. 2D-02 AIO 2B.052 3/22/2011 3/22/2015 August 2017 2D pad next due August of 2017. CPAI requests a delay of up to 5 months to test on or before 8/31/17 to get on schedule. 2D-04 AIO 2B.037 6/21/2008 6/21/2016 August 2017 Well to be tested on or before 8/31/17 to get on schedule. 2D-10 AIO 26.070 2/6/2012 1/19/2016 August 2017 Well to be tested on or before 8/31/17 to get on schedule. 2F-02 A10 2C.035 July 2016 7/9/2016 July 2016 2F pad next due July of 2020. No changes. 2F-03 AIO 2C.039 July 2018 7/9/2016 July 2018 No changes 2F-04 AIO 213.074 6/7/2012 7/9/2016 July 2018 Well to be tested on or before 7/31/18 to get on schedule. 2F-13 AIO 213.039 7/5/2008 7/9/2016 July 2018 Well to be tested on or before 7/31/18 to get on schedule. 2G-01 AIO 2C.019 1/11/2015 5/10/2016 May 2018 2G pad next due May of 2020. Well to be tested on or before 5/31/18 to get on schedule. 2G-05 AIO 2C.029 8/27/2015 5/1/2012 May 2016 Well has been shut in since 2/22/16. If the well is BOI, it will be tested post stabilization and then again on or before 5/31/18 to get on schedule. 2G-07 AIO 2C.038 May 2018 5/10/2016 May 2018 No changes 2G-10 AIO 213.030 2/24/2008 6/21/2016 May 2018 Well to be tested early, on or before 5/31/18 to get on schedule. 21-1-01 AIO 2C.037 May 2018 7/31/2016 May 2018 2H pad next due May 2020. No changes. 21-1-03 AIO 2C.009 12/9/2014 5/26/2016 May 2018 Well to be tested on or before 5/31/18 to get on schedule. 2H-13 AIO 26.076 3/23/2013 5/10/2016 May 2018 Well to be tested on or before 5/31/18 to get on schedule. 21-1-15 AIO 2C.015 12/25/2014 5/10/2016 May 2018 Well to be tested early, on or before 5/31/18 to get on schedule. 2K-03 AIO 213.016 6/1/2007 5/30/2015 June 2017 2K pad next due June of 2019. CPAI requests a delay of up to 1 month to test on or before 6/30/17 to get on schedule. 2K-10 AIO 26.017 6/1/2007 5/29/2015 June 2017 CPAI requests a delay of up to 1 month to test on or before 6/30/17 to get on schedule. 2K-12 AIO 213.048 8/8/2009 8/4/2015 June 2017 Well to be tested on or before 6/30/17 to get on schedule. 2K-20 AIO 2C.041 June 2017 11/13/2015 June 2017 No changes 2L-305 A10 16.002 1/21/2012 2/14/2017 August 2018 2L pad next due August of 2018. Well to be tested on or before 8/31/18 to get on schedule. 2L-310 AIO 16.004 2/5/2014 2/14/2017 August 2018 Well to be tested on or before 8/31/18 to get on schedule. 2L-319 AIO 16.003 10/4/2012 9/30/2016 August 2018 lWell to be tested on or before 8/31/18 to get on schedule. 2L-323 AIO 16.005 2/1/2015 1/17/2017 August 2018 Well to be tested on or before 8/31/18 to get on schedule. 2M-09A AIO 26.004 2/6/2008 9/25/2015 June 2016 2M pad next due June 2020. Well has been shut in since 10/6/15. If it is 13O1, the well will be tested post stabilization and then again on the earliest date to align with the schedule. 2M-19 AIO 2C.020 5/4/2015 6/3/2016 June 2018 Well to be tested on or before 6/30/18 to get on schedule. 2M-27 AIO 2C.021 5/5/2015 10/15/2016 June 2018 Well to be tested on or before 6/30/18 to get on schedule. 2N-306 AIO 16.006 August 2016 8/20/2016 August 2016 2N pad next due August of 2018. No changes 2N-325 AIO 16.001 12/30/2009 2/14/2017 August 2018 Well to be tested on or before 8/31/18 to get on schedule. 213-447 AIO 216.001 8/20/2016 2P pad next due August of 2018. This well is on schedule. No anniversary date on AA. Follows the pad schedule which occurs every 2 years. No changes. 2T-02 AIO 2C.001 11/9/2014 10/25/2016 June 2017 2T pad next due June of 2017. Well to be tested on or before 6/30/17 to get on schedule. 2T-10 AIO 26.092 10/2/2014 9/30/2016 June 2017 Well to be tested on or before 6/30/17 to get on schedule. 2T-18 AIO 2C.023 4/16/2015 6/1/2013 June 2017 Well to be tested on or before 4/16/17 and then again on or before 6/30/17 to get on schedule. 2T-28 A10 213.066 10/2/2011 9/25/2015 June 2017 Well to be tested on or before 6/30/17 to get on schedule. 2T-32A AIO 2C.007 11/9/2014 10/25/2016 June 2017 Well to be tested on or before 6/30/17 to get on schedule. 2U-05 AIO 213.084 1/12/2014 2/14/2017 August 2018 21J pad next due August of 2018. Well to be tested on or before 8/31/18 to get on schedule. 2V-02 AIO 26.071 5/29/2012 9/30/2016 June 2017 2V pad next due June of 2020. Well to be tested on or before 6/30/17 to get on schedule. AA requires a yearly test. 2V-05 AIO 213.055 6/26/2010 6/3/2016 June 2018 Well to be tested on or before 6/30/18 to get on schedule. 2X-05 AIO 2B.064 6/26/2011 6/10/2015 June 2017 2X pad next due June of 2019. Well to be tested on or before 6/30/17 to get on schedule. 2Z-16 AIO 213.002 9/25/2007 August 2015 2Z pad next due August of 2019. This well has been offline since 3/6/06. If the well is BO1 it will be tested post stabilization and then again on the earliest date to align with the schedule. AA did not stipulate anniversary date. 36-01 AIO 2C.033 June 2017 6/18/2015 June 2017 3B pad next due June of 2019. No changes 313-05 AIO 2C.005 10/13/2014 12/27/2016 June 2017 Well to be tested on or before 6/30/17 to get on schedule. 313-07 AIO 2C.028 6/18/2015 6/18/2015 June 2017 Well to be tested on or before 6/30/17 to get on schedule. 36-10 AIO 26.067 6/19/2011 6/18/2015 June 2017 Well to be tested on or before 6/30/17 to get on schedule. 36-12 AIO 2C.025 6/27/2015 6/18/2015 June 2017 Well to be tested on or before 6/30/17 to get on schedule. 3F-04 AIO 213.063 6/5/2011 6/5/2015 June 2017 3F pad next due June of 2019. Well to be tested on or before 6/30/17 to get on schedule. 3F-08 AIO 26.087 2/13/2014 2/4/2016 June 2017 Well to be tested on or before 6/30/17 to get on schedule. 3F-11 AIO 26.089 1/27/2014 1/17/2016 June 2017 Well to be tested on or before 6/30/17 to get on schedule. 3G-15 AIO 2C.011 6/11/2014 6/1/2016 August 2017 3G pad next due August of 2019. Well to be tested on or before 8/31/17 to get on schedule. 3G-23 AIO 2C.004 10/10/2014 9/26/2016 August 2017 Well to be tested on or before 8/31/17 to get on schedule. 3G-24 AIO 2C.040 August 2017 8/15/2015 August 2017 No changes 31-1-06 AIO 2C.003 7/12/2014 7/10/2016 June 2017 3H pad next due June 2017. Well to be tested on or before 6/30/17 to get on schedule. 31-1-07 AIO 2C.016 9/18/2014 9/26/2016 June 2017 Well to be tested on or before 6/30/17 to get on schedule. 3J-08 AIO 2C.013 11/27/2014 7/5/2016 July 2018 3J pad next due July of 2020. Well to be tested on or before 7/31/18 to get on schedule. 3K-11 AIO 2B.061 7/29/2011 4/30/2016 May 2017 3K pad next due May of 2017. Well to be tested on or before 5/31/17 to get on schedule. 3K-22A AIO 26.013 4/5/2005 4/14/2015 May 2017 CPAI requests a delay of up to 1 month to allow the MIT to be performed on or before 5/31/17 to get on schedule. 3N-11A AIO 2B.072 12/7/2012 8/1/2016 August 2018 3N pad next due August of 2020. Well to be tested on or before 8/31/18 to get on schedule. 3N-16A AIO 213.057 8/7/2016 August 2018 Well to be tested on or before 8/31/18 to get on schedule. AA did not stipulate anniversary date. 30-07 A10 2C.032 June 2017 3/14/2016 June 2017 30 pad next due June of 2017. No changes 30-10 AIO 2B.033 6/10/2008 6/1/2016 June 2017 Well to be tested on or before 6/30/17 to get on schedule. 30-17 AIO 2C.026 8/5/2015 8/5/2015 June 2017 Well to be tested on or before 6/30/17 to get on schedule. 3Q-01 AIO 26.068 11/24/2011 8/2/2016 August 2018 3Q pad next due August of 2020. Well to be tested on or before 8/31/18 to get on schedule. 3Q-05 AIO 2B.019 10/1/2007 8/2/2016 August 2018 Well to be tested on or before 8/31/18 to get on schedule. 3Q-12 AIO 2C.002 8/14/2014 9/15/2016 August 2018 Well to be tested on or before 8/31/18 to get on schedule. 3Q-15 AIO 2B.042 9/25/2008 8/2/2016 August 2018 Well to be tested on or before 8/31/18 to get on schedule. 3Q-16 AIO 26.082 1/12/2014 8/2/2016 August 2018 Well to be tested on or before 8/31/18 to get on schedule. 3Q-21 AIO 26.005 4/25/2006 8/2/2016 August 2018 Well to be tested on or before 08/31/18 to get on schedule. 3R-25 AIO 26.012 4/27/2005 8/2/2016 August 2018 3111 pad next due August of 2020. Well to be tested on or before 8/31/18 to get on schedule. 3S-18 AIO 26.069 6/6/2012 6/6/2012 Alternating service and development well. Required to have witnessed MIT upon start of each injection cycle. Well currently on production. No changes 35-26 AIO 2C.036 August 2016 8/18/2016 August 2016 3S pad next due August of 2018. No changes CD1-07 AIO 1813.006 6/8/2008 6/11/2015 June 2017 CD1 pad next due June of 2017. Well to be tested on or before 6/30/17 to get on schedule. CD1-14 AIO 18C.006 9/1/2015 6/12/2013 June 2017 Well to be tested on or before 6/30/17 to get on schedule. CD1-21 A1O.18B.007 6/12/2013 6/11/2015 June 2017 Well to be tested on or before 6/30/17 to get on schedule. CD1-46 AIO 18C.004 2/20/2015 6/12/2013 June 2017 Well was recently BO1 on 2/21/17. The well will be tested when stable and then again on or before 6/30/17 to get on schedule. CD2-51 AIO 18C.010 June 2016 6/22/2016 June 2016 CD2 pad next due June of 2018. No changes CD3-112 AIO 30.007 February 2018 2/23/2014 February 2018 CD3 pad next due February of 2018. No changes CD3-123 AIO 30.005 2/23/2014 2/18/2016 February 2018 Well to be tested on or before 2/28/18 to get on schedule. CD3-128 AIO 18C.009 February 2018 2/23/2014 February 2018 No changes CD3-198 AIO 30.006 7/30/2015 1/28/2017 February 2018 Well to be tested on or before 2/28/18 to get on schedule. CD4-17 AIO 18C.003 5/6/2015 6/30/2011 June 2017 CD4 pad next due June of 2019. Well has been shut in since 5-3-15. If the well is BOI it will be tested on or before 5/6/17 and then again on or before 6/30/17 to get on schedule. CD4-27 AIO 18C.008 June 2017 6/12/2015 June 2017 No changes CD4-209 AIO 28.003 11/28/2009 11/11/2015 June 2017 Well to be tested on or before 6/30/17 to get on schedule. CD4-321 AIO 18C.002 5/10/2013 11/11/2015 June 2017 Well to be tested on or before 6/30/17 to get on schedule. CD4-322 AIO 18C.005 6/12/2015 6/12/2015 June 2017 lWell to be tested on or before 6/30/17 to get on schedule. ConocoPhillips Alaska P.O. BOX 100360 ANCHORAGE, ALASKA 99510-0360 March 26, 2016 Chris Wallace Alaska Oil and Gas Commission 333 West 7t' Avenue, Suite 100 Anchorage, AK 99501 Dear Mr. Wallace, CPAI requested a meeting with the AOGCC in December 2015 to discuss several topics. The intent of the meeting was to discuss ideas to improve efficiency and cost savings for both CPAI and the AOGCC, while maintaining regulatory compliance which ensures the safety of personnel and the environment. The purpose of the following proposal is to maintain a good working relationship with the AOGCC while streamlining reporting requirements, align Administrative Approval (AA) anniversary dates, and outline an acceptable diagnostic and operating path forward pertaining to injectors that have an IA pressure anomaly while on gas injection. The first topic for consideration is to align the anniversary dates on AA's with the current approved UIC testing schedule. This will optimize CPAI's time and resources as well as North Slope AOGCC Inspector time by aligning the testing with the rest of the pad instead of making multiple trips to Kuparuk for 1 or 2 wells at a time. This covers both future approvals and amending the dates on existing approvals. With the current testing requirements and the acceptance of this proposal, the wells will still be tested every 2 years. However, every other test will fall in line with the 4 year UIC pad testing. For future approvals, the AA applications will include a requested anniversary test month which will align the testing cycle of the specific well with the required UIC test month schedule. Initially this may require a test early in the cycle for alignment. However, it will be more efficient over the long term. For existing approvals already in place, a blanket amendment is requested to change the dates to align with the approved UIC test month schedule. An outline of each well, the existing anniversary date, the date of the last witnessed test, and the new proposed anniversary date is included for easy reference. The attached spreadsheet includes all of the above data and an explanation of how the new date will be achieved. However a number of these wells have not had a recent witnessed MITIA due to having been shut in long term. These wells will be evaluated for cancellation of their AA's. Some of the wells will require early testing and some of the wells include a request to delay the testing for a short period, no longer than 5 months, in order to get each well in cycle. Along with the information listed above, each well has a note included of how CPAI intends to test each well to keep the wells within compliance and to achieve the new anniversary testing month. In addition to aligning the MITIA anniversary test dates, the MITIA test pressure criteria should be brought into alignment with current requirements. There are 6 older AA's that require "1.2 times the maximum anticipated injection pressure" for the MITIA criteria. The wells in question are 1B-11, 2K-03, 2K-10, 3K-11, 3Q-05, CD4-209. CPAI requests that the AA MITIA test criteria for these wells be changed to "maximum anticipated injection pressure". The second topic for consideration is to clarify and improve the reporting process for injectors. CPAI proposes that a report to the AOGCC will not be initiated until annular communication and/or casing integrity failures have been confirmed. This will be accomplished via diagnostic testing and/or extended observation of a well. After observing an anomaly, a standard suite of diagnostics would begin. These typically include an MIT of the annulus in question, packoff testing either of the tubing and/or inner casing, and a drawdown test to establish a buildup rate if the MIT passes. Depending on the results of the drawdown test, a period of extended bleeds or an annular fluid replacement may be performed. If the extended bleeds or fluid replacement indicate that there are no signs of communication, a self -regulated monitor period while remaining on injection may be started to confirm the repeatability of the anomaly. Normally a monitor period of 30 days will be used. However, if the suspected communication is of a very slow or intermittent nature, longer observation may be necessary. The WellTracker system recently put into place at CPAI will help in tracking these wells. If the monitor period does not show any further anomalies, the well will not be reported at that time. If a well fails an MIT or if the anomaly repeats itself and there is confirmed communication, the well will be reported at that time. The initial report at that time will include all diagnostics that have been performed to date, including the dates and results of the testing, a TIO plot with a minimum of 90 days to cover the entire duration of the diagnostics (including the initial tests and any diagnostic periods that may have occurred), a rate plot of injection, and the plan forward for further diagnostics or intentions to waiver will be included. With this approach, ConocoPhillips will be reporting wells that have confirmed communication with the details of how it was confirmed and minimize the reporting of wells that do not have confirmed communication. The results of the diagnostics will dictate each new path forward. A failing MIT will result in the well being shut in as soon as reasonably possible and may include securing with a downhole plug as necessary. If communication is observed on gas injection, if possible, the well will remain on gas injection and attempts will be made to establish the bleed frequency and the approximate psi per day pressure build up rate. This will be done to determine whether the well can be operated maintaining the inner annulus below the "Do not exceed" (DNE) pressure with a maintenance bleed program. After the communication on gas injection has been confirmed and a buildup rate determined, the well will be WAG'ed to water injection and an additional 30 day monitoring period will be conducted to ensure that the communication is only present when on gas injection. The third topic for consideration concerns the wells which demonstrate TxIA communication only while on gas injection and for which there are no plans to continue gas injection. CPAI proposes that these wells should not need to have an AA to continue water -only injection. Instead, CPAI will submit a sundry request to convert these injectors from WAG to WINJ status. When on water injection, these injectors display all of the characteristics of a well with full integrity and behave no differently than the normal wells. After being placed in WINJ status, these wells would then be governed by their respective field's Area Injection Order. To ensure that these wells are not inadvertently returned to gas injection, the gas lines will be physically disconnected from the wellheads. The fourth topic for consideration concerns the injectors which demonstrate TxIA communication only when on gas injection and where CPAI would operate these wells under a "Maintenance Bleed" AA. For those wells, CPAI would like to remain consistent with our current Well Operating Guidelines (WOG) allowance of OA bleeds on a gas lifted producer. This would mean that the acceptable and manageable rate would be a buildup of pressure requiring no more than two bleeds per week to keep the IA under the standard DNE of 2400 psi for gas injectors in Kuparuk and Alpine. The bleed frequency would be established as part of the diagnostics and if an acceptable frequency was achieved, an AA request would be submitted to continue WAG injection allowing maintenance bleeds on the IA while on gas injection only. In addition to a normally required 2 year MITIA, a caliper survey of the tubing from the packer to the surface would be logged. With this criteria in place, the testing requirements would evaluate or test the integrity of the tubing every year. The caliper will evaluate the internal condition of the pipe and the MITIA would test the integrity of the tubing externally as well as the integrity of the production casing and packer. The proposed AA would request a 2 year witnessed MITIA to the standard AOGCC test pressure (.25 x Packer TVD or 1500 psi whichever is greater), alternating with a 2 year non -witnessed caliper survey. The caliper survey would be submitted to the AOGCC but would not require an inspector on site to witness the logging. The request for the lowered test pressure criteria, in lieu of the higher test pressure to maximum anticipated pressure, is based on the annual monitoring of the tubing condition and the well operating under normal gas injection well criteria, other than the maintenance bleeds, with the IA remaining under the 2400 psi DNE limits. The well would be shut in if the bleed frequency increased above two bleeds per week which could indicate a change in mechanical condition of the well. Any `slow' gas -only tubing leaks which are identified in the future will follow the protocol as outlined above. However, any of the existing AA's for wells with this type of communication will need to be addressed separately. For some of these wells, investigation will be needed to quantify their gas leak rates. Therefore, a diagnostic plan will be developed and a request submitted at a future date asking for permission from the AOGCC to allow these wells to have gas injection temporarily restored to perform the diagnostics. A judgment from that point can be made as to whether the leaks can be managed by bleed (criteria from above) or whether they will need to remain on water injection. For those wells which will need to remain on water injection, a request will be submitted to change their status from WAG to WINJ and have their AA's cancelled, as outlined under the third topic in this proposal. ConocoPhillips is continuously striving for improvement. This proposal includes some of the topics for consideration that have been identified as areas for improvement. The intent of this proposal is to better utilize resources for both CPAI and the AOGCC. We believe with the implementation of the topics above, it will enable more efficient use and time of CPAI resources while providing less burden on the AOGCC, both town personnel and the North Slope inspectors. It will also reduce the amount of redundant work and streamline communication to include more factual information and not just suspicions. Additionally these ideas will help maximize production by allowing continued gas injection while ensuring the well is still safe to operate and does not compromise the safety of the environment or personnel. This proposal will still maintain the wells within regulatory compliance while achieving a higher level of efficiency. Due to the nature of the upcoming summer MIT schedule, a prompt response would be appreciated. If necessary, we are available to set up a face to face meeting to finalize the details. Don't hesitate to call if you have any questions. For your consideration from ConocoPhillips Alaska's Problem Wells Supervisors: Brent Rogers Kelly Lyons Dusty Freeborn Jan Byrne Anniversary Date Amendement Proposal Well name AIO # Existing Anniversary Date Date Last Witnessed Test Proposed New Notes Anniversary Date 1A-04A AIO 2B.011 5/30/2006 6/29/2014 7/31/2017 1A pad due next July of 2019. This well will be tested by 06/29/16 and then the following year by 07/31/17 to get on schedule. 1A-06 AIO 2C.031 July 2017 7/26/2011 7/31/2017 New approved AA calls for anniversary date to be before or during month of July 2017. CPAI requests to change this to last day of July for precise database maintenance. 1A-12 A1O 2B.049 3/16/2010 2/20/2016 7/31/2017 This well will be tested on or before 07/31/17 to get on schedule. 1A-16RD AIO 2B.075 3/22/2015 3/22/2015 7/31/2017 CPAI requests a delay of 4 months on the test to allow the test on or before 07/31/17 to get on schedule. 16-08A A1O 2C.027 8/7/2015 7/12/2013 6/30/2017 1B pad due next June of 2017. Well to be tested early, on or before 6/30/17 to get on schedule. 16-11 AIO 26.060 7/6/2011 7/7/2015 6/30/2017 Well to be tested early, on or before 7/31/16 to get on schedule. 1D-38 AIO 2C.010 8/26/2014 8/26/2014 7/31/2016 1D pad due next July of 2018. Well to be tested early, on or before 7/31/16 to get on schedule. 1E-08A A1O 213.065 8/30/2011 8/27/2015 6/30/2016 3E pad due next June of 2018. Well to be tested early, on or before 6/30/16 to get on schedule. 1E-15A AIO 26.081 12/8/2013 11/20/2015 6/30/2016 Well to be tested early, on or before 6/30/16 to get on schedule. 1E-22 AIO 213.078 6/16/2013 11/20/2015 6/30/2016 Well to be tested early, on or before 6/30/16 to get on schedule. 1F-04 A1O 2C.006 9/16/2014 2/14/2013 6/30/2016 1f pad due next June 2016. Well to be tested early, on or before 6/30/16 to get on schedule. 1F-05 A1O.26.080 7/12/2012 7/4/2014 6/30/2016 Well to be tested early, on or before 6/30/16 to get on schedule. 1F-16A AIO 2C.018 3/24/2015 12/2/2013 6/30/2016 Well to be tested early, on or before 6/30/16 to get on schedule. 1G-01 AIO 26.035 6/28/2008 6/15/2014 7/31/2017 1G pad due next July of 2019. This well will be tested by 6/28/16 and then on or before 7/31/17 to get on schedule. 1L-05 A10 2B.054 8/11/2010 7/27/2014 6/30/2016 1L pad due next June of 2016. Well to be tested early, on or before 6/30/16 to get on schedule. 1L-07 A10 2C.008 10/28/2014 5/25/2012 6/30/2016 Well to be tested early, on or before 6/30/16 to get on schedule. 1L-10 AIO 213.083 2/22/2014 2/20/2016 6/30/2016 Well to be tested early, on or before 6/30/16 to get on schedule. 1Q-09 AIO 26.093 5/30/2014 7/9/2013 7/31/2017 1Q pad due next July of 2017. This well will be tested by 5/30/16 and then on or before 7/31/17 to get on schedule. 1Q-13 AIO 26.090 6/29/2014 6/29/2014 7/31/2017 This well will be tested by 6/29/16 and then on or before 7/31/17 to get on schedule. 1Q-24 A10 2C.017 3/11/2015 7/9/2013 7/31/2017 CPAI requests a delay of 5 months to allow the test to be performed on or before 7/31/17 to get on schedule. 1R-15 A1O 213.088 1/12/2014 1/2/2016 5/31/2017 1R pad due next May of 2019. Well to be tested early, on or before 5/31/17 to get on schedule. 1Y-05 AIO 26.015 7/23/2006 7/8/2013 7/31/2017 1Y pad due next July of 2017. This well has been offline since 2/6/12. If the well is BO1 it will be tested post stabilization and then again on the earliest date to align with the schedule. 1Y-08 AIO 213.056 6/15/2010 2/15/2015 7/31/2017 This well will be tested by 6/15/16 and then on or before 7/31/17 to get on schedule. 1Y-09 AIO 26.051 5/20/2010 2/15/2015 7/31/2017 This well will be tested by 5/20/16 and then on or before 7/31/17 to get on schedule. 1Y-10 AIO 2C.014 8/29/2014 9/12/2015 7/31/2017 This well will be tested by 8/29/16 and then on or before 7/31/17 to get on schedule. 26-06 AIO 2C.012 12/26/2014 12/26/2014 5/31/2016 2B pad due next May of 2016. Well to be tested early, on or before 5/31/16 to get on schedule. 26-07 NO 2C.024 12/18/2014 5/10/2012 5/31/2016 Well to be tested early, on or before 5/31/16 to get on schedule. 213-10 AIO 26.073 2/14/2013 2/8/2015 5/31/2016 Well to be tested early, on or before 5/31/16 to get on schedule. 2C-03 AIO 26.085 2/5/2013 2/20/2016 8/31/2017 2C pad due next August 2017. Well to be tested early, on or before 8/31/17 to get on schedule. 2C-04 AIO 213.091 6/21/2014 6/21/2014 8/31/2017 This well will be tested by 6/21/16 and then on or before 8/31/17 to get on schedule. 2C-07 AIO 26.007 2/5/2006 2/5/2012 8/31/2017 This well has been offline since 9/12/12. If the well is 13O1 it will be tested post stabilization and then again on the earliest date to align with the schedule. 2C-08 A1O26.086 3/4/2014 2/20/2016 8/31/2017 Well to be tested early, on or before 8/31/17 to get on schedule. 2D-02 AIO 26.052 3/22/2011 3/22/2015 8/31/2017 2D pad due next August of 2017. CPAI requests a delay of 5 months to allow the MIT to be performed on or before 8/31/17 to get on schedule. 2D-04 AIO 26.037 6/21/2008 6/21/2014 8/31/2017 This well will be tested by 6/21/16 and then on or before 8/31/17 to get on schedule. 2D-10 NO 26.070 2/6/2012 1/19/2016 8/31/2017 Well to be tested early, on or before 8/31/17 to get on schedule. 2F-04 AIO 213.074 6/7/2012 6/7/2014 7/31/2016 2F pad due next July of 2016. CPAI requests a delay of 2 months to allow the MIT to be performed on or before 7/31/16 to get on schedule. 2F-13 AIO 26.039 7/5/2008 6/7/2014 7/31/2016 CPAI requests a delay of 1 month to allow the MIT to be performed on 7/31/16. 2G-01 AIO 2C.019 1/11/2015 5/1/2012 5/31/2016 2G pad due next May of 2016. Well to be tested early, on or before 5/31/16 to get on schedule. 2G-03 AIO 213.014 5/14/2006 5/28/2010 5/31/2016 This well has been offline since 9/28/11. If the well is BOI it will be tested post stabilization and then again on the earliest date to align with the schedule. 2G-05 AIO 2C.029 8/27/2015 5/1/2012 5/31/2016 Well to be tested early, on or before 5/31/16 to get on schedule. 2G-10 AIO 213.030 2/24/2008 5/1/2012 5/31/2016 This well has been offline since 9/28/12. If the well is BO1 it will be tested post stabilization and then again on the earliest date to align with the schedule. 2H-03 AIO 2C.009 12/9/2014 5/6/2012 5/31/2016 2H pad due next May of 2016. Well to be tested early, on or before 5/31/16 to get on schedule. 2H-13 NO 26.076 3/23/2013 8/15/2015 5/31/2016 Well to be tested early, on or before 5/31/16 to get on schedule. 2H-15 NO 2C.015 12/25/2014 5/6/2012 5/31/2016 Well to be tested early, on or before 5/31/16 to get on schedule. 2K-03 NO 26.016 6/1/2007 5/30/2015 6/30/2017 2K pad due next June of 2019. CPAI requests a delay of 1 month to test on or before 6/30/17 to get on schedule. 2K-10 AIO 213.017 6/1/2007 5/29/2015 6/30/2017 CPAI requests a delay of 1 month to test on or before 6/30/17 to get on schedule. 2K-12 AIO 26.048 8/8/2009 8/4/2015 6/30/2017 Well to be tested early, on or before 6/30/16 to get on schedule. 2L-305 AIO 16.002 1/21/2012 1/19/2016 8/31/2016 2L pad due next August of 2018. Well to be tested early, on or before 8/31/16 to get on schedule. 2L-310 AIO 16.004 2/5/2014 2/4/2016 8/31/2016 Well to be tested early, on or before 8/31/16 to get on schedule. 2L-319 AIO 16.003 10/4/2012 9/8/2014 8/31/2016 Well to be tested early, on or before 8/31/16 to get on schedule. 2L-323 NO 16.005 2/1/2015 9/8/2014 8/31/2016 Well to be tested early, on or before 8/31/16 to get on schedule. 2M-09A NO 213.004 2/6/2008 9/25/2015 6/30/2016 2M pad due next June 2016. Well to be tested early, on or before 6/30/16 to get on schedule. 2M-19 NO 2C.020 5/4/2015 9/2/2012 6/30/2016 Well to be tested early, on or before 6/30/16 to get on schedule. 2M-27 NO 2C.021 5/5/2015 9/2/2012 6/30/2016 Well to be tested early, on or before 6/30/16 to get on schedule. 2N-325 NO 16.001 12/30/2009 12/27/2015 6/30/2016 2N pad due next August of 2018. Well to be tested early, on or before 6/30/16 to get on schedule. 2P-447 NO 216.001 8/31/2014 12/26/2014 8/31/2016 2P pad due next August of 2016. This well is on schedule. 2T-02 NO 2C.001 11/9/2014 11/9/2014 6/30/2017 2T pad due next June of 2017. This well will be tested by 11/9/16 and then on or before 6/30/17 to get on schedule. 2T-10 AIO 26.092 10/2/2014 10/2/2014 6/30/2017 This well will be tested by 10/2/16 and then on or before 6/30/17 to get on schedule. 2T-18 AIO 2C.023 4/16/2015 6/1/2013 6/30/2017 CPAI requests a 3 month delay to allow the MIT to be performed on or before 6/30/17 to get on schedule. 2T-28 NO 213.066 10/2/2011 9/25/2015 6/30/2017 Well to be tested early, on or before 6/30/17 to get on schedule. 2T-32A AIO 2C.007 11/9/2014 11/9/2014 6/30/2017 This well will be tested by 11/9/16 and then on or before 6/30/17 to get on schedule. 2U-05 NO 213.084 1/12/2014 12/27/2015 8/31/2016 2U pad due next August of 2018. Well to be tested early, on or before 8/31/16 to get on schedule. 2V-02 NO 2B.071 5/29/2012 11/6/2015 6/30/2016 2V pad due next June of 2016. CPAI requests a delay of 1 month to allow the test to be performed on or before 6/30/16 to get on schedule. 2V-05 NO 26.055 6/26/2010 7/27/2014 6/30/2016 CPAI requests a delay of 1 month to allow the test to be performed on or before 6/30/16 to get on schedule. 2X-05 NO 26.064 6/26/2011 6/10/2015 6/30/2017 2X pad due next June of 2019. CPAI requests a delay of 1 week to allow the MIT to be performed on or before 6/30/17 to get on schedule. 2Z-16 NO 213.002 9/25/2007 8/31/2017 2Z pad due next August of 2019. This well has been offline since 3/6/06. If the well is BOI it will be tested post stabilization and then again on the earliest date to align with the schedule. AA did not stipulate anniversary date. 3B pad due next June of 2019. This well will be tested by 10/13/16, and then the 36-05 AIO 2C.005 10/13/2014 6/19/2011 6/30/2017 following year by 6/30/17 to get on schedule. CPAI requests a delay of 2 weeks to allow the MIT to be performed on or before 6/30/17 36-07 AIO 2C.028 6/18/2015 6/18/2015 6/30/2017 to get on schedule. CPAI requests a delay of 2 weeks to allow the MIT to be performed on or before 6/30/17 313-10 AIO 26.067 6/19/2011 6/18/2015 6/30/2017 to get on schedule. CPAI requests a delay of 1 week to allow the MIT to be performed on or before 6/30/17 36-12 AIO 2C.025 6/27/2015 6/18/2015 6/30/2017 to get on schedule. 3F pad due next June of 2019. CPAI requests a delay of 1 month to allow the MIT to be 3F-04 AIO 213.063 6/5/2011 6/5/2015 6/30/2017 performed on or before 6/30/17 to get on schedule. 3F-08 AIO 213.087 2/13/2014 2/4/2016 6/30/2017 Well to be tested early, on or before 6/30/17 to get on schedule. 3F-11 AIO 26.089 1/27/2014 1/17/2016 6/30/2017 Well to be tested early, on or before 6/30/17 to get on schedule. 3G pad due next August of 2019. This well will be tested by 6/11/16 and then the 3G-15 AIO 2C.011 6/11/2014 8/30/2011 8/31/2017 following year by 8/31/17 to get on schedule. This well will be tested by 10/10/16 and then the following year by 8/31/17 to get on 3G-23 AIO 2C.004 10/10/2014 9/6/2014 8/31/2017 schedule. 3H pad due next June 2017. This well will be tested by 7/12/16 and then the following 31-1-06 AIO 2C.003 7/12/2014 11/19/2013 6/30/2017 year by 6/30/17 to get on schedule. This well will be tested by 9/18/16 and then the following year by 6/30/17 to get on 31-1-07 AIO 2C.016 9/18/2014 9/18/2014 6/30/2017 schedule. 3J-08 AIO 2C.013 11/27/2014 7/5/2012 7/31/2016 3.11 pad due next July of 2016. This well will be tested by 7/31/16 to get on schedule. 3K pad due next May of 2017. This well has been off line since 5/25/15. If the well is BO1 it will be tested post stabilization and then again on the earliest date to align with 3K-11 AIO 213.061 7/29/2011 7/8/2013 5/31/2017 the schedule. CPAI requests a delay of 2 months to allow the MIT to be performed on or before 3K-22A AIO 26.013 4/5/2005 4/14/2015 5/31/2017 5/31/17 to get on schedule. 3N pad due next August of 2016. Well to be tested early, on or before 8/31/16 to get 3N-11A AIO 213.072 12/7/2012 12/13/2014 8/31/2016 on schedule. Well to be tested early, on or before 8/31/16 to get on schedule. AA did not stipulate 3N-16A AIO 213.057 12/13/2014 8/31/2016 anniversary date. 30 pad due next June of 2017. CPAI requests a delay of 3 months to allow the MIT to be 30-06 AIO 2C.022 3/27/2015 3/27/2015 6/30/2017 performed on or before 6/30/17 to get on schedule. New approved AA calls for anniversary date to be before or during month of June 2017. 30-07 AIO 2C.032 June 2017 3/14/2016 6/30/2017 CPAI requests to change this to last day of June for precise database maintenance. 30-10 AIO 213.033 6/10/2008 6/15/2014 6/30/2017 This well will be tested by 6/10/16 and then on or before 6/30/17 to get on schedule. 30-17 AIO 2C.026 8/5/2015 8/5/2015 6/30/2017 Well to be tested early, on or before 6/30/17 to get on schedule. 3Q pad due next August of 2016. This well will be tested on or before 8/31/16 to get on 3Q-01 AIO 213.068 11/24/2011 11/13/2015 8/31/2016 schedule. 3Q-05 AIO 213.019 10/1/2007 9/25/2015 8/31/2016 Well to be tested early, on or before 8/31/16 to get on schedule. 3Q-12 AIO 2C.002 8/14/2014 8/8/2012 8/31/2016 CPAI requests a delay of 3 weeks to allow the MIT to be performed on or before 8/31/16. 3Q-15 AIO 213.042 9/25/2008 6/27/2015 8/31/2016 Well to be tested early, on or before 8/31/16 to get on schedule. 3Q-16 AIO 26.082 1/12/2014 1/2/2016 8/31/2016 Well to be tested early, on or before 8/31/16 to get on schedule. 3Q-21 AIO 213.005 4/25/2006 4/15/2014 8/31/2016 CPAI requests a delay of 4 months to allow the test to be performed on or before 08/31/16 to get on schedule. 313-25 AIO 26.012 4/27/2005 4/24/2015 8/31/2016 3R pad due next August of 2016. Well to be tested early, on or before 8/31/16 to get on schedule. 35-18 AIO 26.069 6/6/2012 6/6/2012 Alternating service and development well. Required to have witnessed MIT upon start of each injection cycle. Well currently on production. CD1-07 AIO 1813.006 6/8/2008 6/11/2015 6/30/2017 CD1 pad due next June of 2027. CPAI requests a delay of 3 weeks to allow the test to be performed on or before 6/30/17. CD1-14 AIO 18C.006 9/1/2015 6/12/2013 6/30/2017 Well to be tested early, on or before 6/30/17 to get on schedule. CD1-21 A1O.186.007 6/12/2013 6/11/2015 6/30/2017 CPAI requests a delay of 3 weeks to allow the test to be performed on or before 6/30/17 to get on schedule. CD1-46 AIO 18C.004 2/20/2015 6/12/2013 6/30/2017 CPAI requests a delay of 4 months to allow the test to be performed on or before 6/30/17 to get on schedule. CD3-123 AIO 30.005 2/23/2014 2/18/2016 2/28/2018 CD3 pad due next February 2018. CPAI requests a delay of 1 week to allow the test to be perfomed on or before 2/28/18 to get on schedule. CD3-198 AIO 30.006 7/30/2015 4/12/2015 2/28/2018 Well to be tested early, on or before 2/28/17 and then on or before 2/28/18 to get on schedule. CD4-17 AIO 18C.003 5/6/2015 6/30/2011 6/30/2017 CD4 pad due next June 2019. CPAI requests a delay of 2 months to allow the test to be performed on 6/30/17 to get on schedule. CD4-27 AIO 18C.008 June 2017 6/12/2015 6/30/2017 New approved AA calls for anniversary date to be before or during month of June 2017. CPAI requests to change this to last day of June for precise database maintenance. CD4-209 AIO 28.003 11/28/2009 11/11/2015 6/30/2017 Well to be tested early, on or before 6/30/17 to get on schedule. CD4-213B AIO 18C.007 June 2017 6/12/2015 6/30/2017 New approved AA calls for anniversary date to be before or during month of June 2017. CPAI requests to change this to last day of June for precise database maintenance. CD4-321 AIO 18C.002 5/10/2013 11/11/2015 6/30/2017 CPAI requests a delay of 2 months to allow the MIT to be performed on or before 6/30/17 to get on schedule. CD4-322 AIO 18C.005 6/12/2015 6/12/2015 6/30/2017 CPAI requests a delay of 3 weeks to allow the test to be performed on or before 6/30/17 to get on schedule. 15 RECEIVE® ConocoPhillips Alaska P.O. BOX 100360 ANCHORAGE, ALASKA 99510-0360 June 19, 2016 Commissioner Cathy Foerster Alaska Oil & Gas Conservation Commission 333 West 7t' Avenue, Suite 100 Anchorage, AK 99501 Dear Commissioner Foerster: JUN 21 2016 AOGCC ConocoPhillips Alaska, Inc. presents the attached proposal per AIO 16, Rule 10, to apply for Administrative Approval allowing KRU Tarn well 2N-306 (PTD 204-062) to be online in water only injection service. Currently, the well displays TxIA communication only when injecting gas. ConocoPhillips intends to pursue repairs should MI or lean gas injection be desired in the future. If a successful repair is achieved, we will request the well be returned to normal status and resume ability to inject gas. If you need additional information, please contact myself or Brent Rogers at 659-7224, or Jan Byrne / Dusty Freeborn at 659-7126. Sincerely, Kelly Lyons Problem Wells Supervisor ConocoPhillips Alaska Inc. Cc: Working Well File, Legal Well File ConocoPhillips Alaska, Inc. Kuparuk River Unit Tarn Well 2N-306 (PTD# 204-062) Technical Justification for Administrative Relief Request Purpose ConocoPhillips Alaska, Inc. proposes that the AOGCC approve this Administrative Relief request as per Area Injection Order 16, Rule 10, to continue water only injection for Kuparuk River Unit Tarn injection well 2N-306. The well displays annular communication only when the well is on gas injection. Well History and Status Kuparuk River Unit Tarn well 2N-306 (PTD 204-062) was drilled and completed in June 2004 as a WAG service injection well. 2N-306 was initially reported to the Commission on April 18, 2016, as demonstrating anomalous inner annulus pressure trends while on gas injection. During the approved gas injection monitor period, the well continued to display evidence of tubing by inner annulus communication. The well was then WAG' ed to water injection on May 20, 2016, to confirm the theory that the IA pressurization was due to a gas -only leak. Apart from the thermally -induced, minor fluctuations of the IA, the well does not shows signs of communication when on water injection (see attached TIO plot). A passing non -witnessed diagnostic MITIA to 3000psi was performed on May 22, 2016. ConocoPhillips intends to pursue repairs if the leak worsens enough to be detectable and located while on water injection. However, until the leak is detectable both on gas and water injection, ConocoPhillips requests an AA which will allow the well to remain online in water only injection service. The IA pressure will be maintained below 2000 psi. Barrier and Hazard Evaluation With only water injection, this well has all the barriers of a normal injection well Tubing: The 3-1/2" 9.3# L-80 tubing has integrity to the Baker GBH seal assembly @ 6944' MD (5174' TVD), based on passing normal operating differential pressures while on water injection and the passing diagnostic MITIA to 3000psi performed on May 22, 2016. Production casing: The 5.5" 15.5# L-80 production casing has integrity to the Baker GBH seal assembly @ 6944' MD (5174' TVD) based on the passing MITIA described above. The 5.5" has an internal yield pressure rating of 7000 psi. Surface casing: The well is completed with 7-5/8" 29.7# L-80 surface casing with an internal yield pressure rating of 6890 psi. The surface casing is set at 2794' MD (2439' TVD) and the cement shoe was left open after being drilled out. Primary barrier: The primary barrier to prevent a release from the well and provide zonal isolation is the tubing and packer. Secondary barrier: The production casing is the secondary barrier should the tubing fail. Problem Wells Supervisor 6/19/2016 Monitoring: Each well is monitored daily for wellhead pressure changes. Should leaks develop in the tubing or production casing above the surface casing shoe it will be noted during the daily monitoring process. Any pressure trends that indicate annular communication require investigation, Commission notification, and corrective action, up to and including a shut-in of the well. T/IO plots are compiled, reviewed, and submitted to the AOGCC for review on a monthly basis. Proposed Operating and Monitoring Plan 1. Well will be used for water only injection (no MI or gas injection allowed); 2. Perform a passing MITIA every 2 years to the maximum anticipated injection pressure; 3. Anniversary date to be set on August 31, 2016 (Last MIT: May 22, 2016) to align the 2-year AOGCC witnessed testing with the UIC MIT permanent 4 year scheduled pad testing; 4. Allow operating IA pressure up to 2000 psi, operating OA pressure up to 1000 psi; 5. Submit monthly reports of daily tubing, IA & OA pressures, injection volumes and pressure bleeds for all annuli; 6. Shut-in the well should MIT's or injection rates and pressures indicate further problems with appropriate notification to the AOGCC. Problem Wells Supervisor 6/19/2016 2 Well Name Start Date Days End Date 2N-306 3/21/2016 90 6/19/2016 Notes: Bleed Histnr; 4DDD 35DO 3DDD 2500 w 2DDD Q 1500 1D D ACC 0 Mar-16 Annular Communication Surveillance — WHIP _ IAP tArELL ID 2N-306 160 2N-306 2N-306 2N-306 140 2N-306 2N-306 1 G 1GG u_ 8D y v 6D 40 20 0 TIME STR-PRES END-PRES DIF-PRES CASWG SERVICE 5/22/2016 1230 776 454 INNER PWI 5/18/2016 1407 900 507 INNER GIN 5/2/2016 2270 1400 870 INNER GIN SWO16 968 290 678 OUTER GIN OAP 4/17/2016 2461 1 1250 1211 INNER GIN _ WHT 4/4/2016 2300 1450 850 INNER GIN FAar-'6 Mar-16 Apr-16 Apr46 Apr-16 May-16 May-16 May-16 Jun-16 Jun-16 Jun-16 ism n rl i]]7 m d =>? u 507 wo � -auo in t,13r-1C Mar-16 Mar-16 Apr46 Apr-16 Apr-16 May-16 May-16 May-16 Jun-16 Jun-16 Jug-1e Date KUP INJ 2N-306 CIDnoCophillip Well Attributes Max Angle & MD TO Alaska Inc Wellbore API/UW Field Name Wellbore Status 501032049000 TARN PARTICIPATING AREA INJ nc1 (°) MD (ftKB) 52.43 3,116.17 Act Btm (ftKB) 7,605.0 Comment 7(ppm) I Date S.-NIPPLE Annotation I End Date Last WO: KB-Grd (tt) Rig Release Date 36.51 6/2/2004 2N-306, 3/25/201510.05:53 AM ertica sc erratic actua Annotation Depth (ftKB) End Date Last Tag: SLM 7,538.0 3/21 /2015 Annotation Last Mod By End Date Rev Reason: TAG lehallf 3/24/2015 ............................................................. ................... HANGER; 25.4Casing Strings Casing Description OD (in) ID (in) Top (ftKB) Set Depth (ftKB) Set Depth (ND)... WtlLen (I... Grade Top Thread CONDUCTOR 16 15.062 29.8 139.0 139.0 62.50 H-40 WELDED Casing Description OD (in) ID (in) Top (ftKB) Set Depth (ftKB) Set Depth (ND)... WVLen (I... Grade Top Thread SURFACE 75/8 6.875 29.8 2,794.0 2,438.8 29.70 L-80 BTCM Casing Description OD (in) ID (in) Top (ftKB) Set Depth (RKB) Set Depth (ND)... WVLen (I... Grade Top Thread PRODUCTION 5.5"x3.5" 51/2 4.950 28.3 7,594.7 5,602.4 15.50 L-80 BTCMOD @ 6964' Tubing Strings Tubing Description String Ma... ID (in) Top (ftKB) Set Depth (lft Set Depth (TV (... Wt (IbRt) Grade Top Connection TUBING 31/2 2.992 25.4 6,961.4 5,186.3 9.30 L-80 EUE8RDMOD Completion Details Nominal ID Top (ftKB) Top (TVD) (ftKB) Top Incl (°) Item Des Corn (in) 25.4 25.4 0.00 HANGER FMC TUBING HANGER 3.500 CONDUCTOR; 29.8-139.0 493.9 493.7 3.17 NIPPLE CAMCO DS LANDING NIPPLE 2.875 6,882.1 5,133.3 48.75 SLEEVE BAKER CMU SLIDING SLEEVE 2.813 NIPPLE; 193.9 6,898.2 5,144.0 48.62 NIPPLE CAMCO D NIPPLE 2.750 6,942.6 5,173.6 47.61 LOCATOR G-22 LOCATOR SUB 3.000 6,943,5 5,174.2 47.58 1 SEAL ASSY I BAKER GBH 80-40 SEAL ASSEMBLY 3.000 Other In Hole (Wireline retrievable plugs, valves, pumps, fish, etc.) Top Top Incl Top (ftKB) KB (ftKB) I°) Des Co. Run Date ID (in) 7,504.0 5,546.2 51.56 FISH Plug off Gauge LOST BULL PLUG OFF PANEX W2712007 0.000 SURFACE; 29.8-2,794.0- GAUGES IN RATHOLE - 6/27/2007 Perforations & Slots Shot Dens GAS LIFT; 6,833.7 Top (ftKB) Eft. (ftKB) Top (TVD) Btm (ftKB) (ND) (ftKB) Zone Date (shotsff t) Type Corn 7,258.0 7,266.0 5,387.7 5,393.1 S-3, S-5, 2N- 6/26/2004 6.0 IPERF 2.5" HSD PJ 2506, EHD 306 0.31" 7,270.0 7,286.0 5,395.7 5,406.4 S3, 2N-306 6/26/2004 6.0 IPERF 2.5" HSD PJ 2506, EHD 0.31" 7,292.0 7,310.0 5,410.3 5,422.2 S3, 2N-306 6/26/2004 6.0 IPERF 2.5" HSD PJ 2506, EHD 0.31" SLEEVE; 6.882.1 7,364.0 7,382.0 5,457.5 5,469.2 Top Purple, 4Y30Y2008 6.0 APERF 2N-306 7,394.0 7,440.0 5,476.9 5,506.1 Top/Base 4/29/2008 6.0 APERF NIPPLE; 6,8982 30u6 le, 2N- Mandrel Inserts St aB on N Top (ftKB) Top (ND) (fBCB) Make Model OD (in) gem Valve Type Latch Type PortSize (in) TRO Run (psi) Run Date Co. 6,833.7 5,101.5 CAMCO KBG-2- 1 GAS LIFT SOV BTM 0.000 0.0 5/23/2004 9 Notes: General & Safety End Date Annotation LOCATOR; 6,942.6 11/19/2010 NOTE: View Schematic w/ Alaska Schematic9.0 SEAL ASSY; 6,943.5 IPERF; 7,258.0-7,266.0 IPERF; 7,270D7,286.0 IPERF; 7,292.0-7,310.0 APERF; 7,364.D-7,382.0 APERF; 7,394.0-7,440.0 FISH; 7.504.0 PRODUCTION 5.5"x3.5' 6W; 2837,594.7 10 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION Mechanical Integrity Test Submit to: iim.regq@alaska.gov: AOGCC.Inspectors(a alaska.gov; phoebe. brooks(a)alaska.gov chris.wallacepalaska.gov OPERATOR: FIELD / UNIT / PAD DATE: OPERATOR REP: AOGCC REP: ConocoPhillips Alaska, Inc Kuparuk / KRU / 2N 05/22/16 Riley / Arend not witnessed Packer Depth Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. Well 2N-306 Type Inj. I W TVD 5,174' Tubing 1,675 1,675 1,675 1,675 Interval O P.T.D. 2040620 I Type test I P Test psi 1500 Casing 1,230 3,000 2,975 2,975 P/F P Notes: Diagnostic OA 550 755 730 720 Well Type Inj. TVD Tubing Interval P.T.D. Type test Test psi Casing P/F Notes: OA Well I Type Inj. I TVD I Tubing Interval P.T.D. I Type test I Test psi Casing P/F Notes: OA Well I Type Inj. I TVD I Tubing Interval P.T.D. I Type test I Test psi Casing P/F Notes: OA Well Type Inj. I TVD I Tubing Interval P.T.D. I Type test I Test psi I Casing P/F Notes: OA TYPE INJ Codes TYPE TEST Codes D = Drilling Waste M = Annulus Monitoring G = Gas P = Standard Pressure Test I = Industrial Wastewater R = Internal Radioactive Tracer Survey N = Not Injecting A = Temperature Anomaly Survey W = Water D = Differential Temperature Test INTERVAL Codes I = Initial Test 4 = Four Year Cycle V = Required by Variance O = Other (describe in notes) Form 10-426 (Revised 11/2012) MIT KRU 2N-306 non -witnessed 05-22-16.xls 14 ConocoPhillips Alaska P.O. BOX 100360 ANCHORAGE, ALASKA 99510-0360 October 30, 2015 Commissioner Cathy Foerster Alaska Oil & Gas Conservation Commission 333 West 7t' Avenue, Suite 100 Anchorage, AK 99501 Dear Commissioner Foerster: NOV 0 3 2015 ConocoPhillips Alaska, Inc. presents the attached proposal per AIO 16, Rule 10, to apply for Administrative Approval allowing KRU Tarn well 2L-323 (PTD 198-251) to be online in water only injection service. Currently, the well displays TxIA communication only when injecting gas. ConocoPhillips intends to pursue repairs should MI or lean gas injection be desired in the future. If a successful repair is achieved we will request the well be returned to normal status and resume ability to inject gas. If you need additional information, please contact myself or Brent Rogers at 659-7224, or Jan Byrne / Dusty Freeborn at 659-7126. Sincerely, Kelly Lyo Problem Wells Supervisor ConocoPhillips Alaska Inc. Cc: Working Well File, Legal Well File ConocoPhillips Alaska, Inc. Kuparuk River Unit Tarn Well 2L-323 (PTD# 198-251) Technical Justification for Administrative Relief Request Purpose ConocoPhillips Alaska, Inc. proposes that the AOGCC approve this Administrative Relief request as per Area Injection Order 16, Rule 10, to continue water only injection for Kuparuk River Unit Tarn injection well 2L-323. The well displays annular communication only when on gas injection. Well History and Status Kuparuk River Unit Tarn well 2L-323 (PTD 198-251) was drilled and completed in December 1998 as a WAG injection well. 2L-323 was initially reported to the Commission on January 31, 2015, for an unexplained IA pressure anomaly while the well was on gas injection. While the well was shut in, a passing diagnostic MITIA, IA drawdown and tubing packoff tests were performed on February 1, 2015. There was a delay in returning the well to gas injection due to a needed surface safety valve repair and for reservoir management during a close drilling approach in an offset well. After 2L- 323 was returned to gas injection, the well continued to display evidence of tubing by inner annulus communication. The well was then WAG'ed to water injection on October 2, 2015 for its AOGCC-approved 30 day monitor period. There was an initial slight increase in IA pressure due to the residual gas in the annulus coming out of solution because of the higher heat inputs as the water was pumped downhole. After an extended bleed was performed on October 10, 2015, the IA has not shown signs of repressurization. Tubing by inner annulus communication is not present when the well is on water injection. ConocoPhillips intends to pursue repairs if the leak worsens enough to be detectable and located while on water injection. However, until the leak is detectable both on gas and water injection, ConocoPhillips requests an AA which will allow the well to remain online in water only injection service. The IA pressure will be maintained below 2000 psi. Barrier and Hazard Evaluation With only water injection, this well has all the barriers of a normal injection well Tubing: The 3-1/2" 9.3# L-80 tubing has integrity to the Baker seal assembly at 9448' MD (5238' TVD), based on passing normal operating injection differential and the passing MITIA to 2600psi on 02/01/15. Production casing: The 5.5" 15.5# L-80 production casing has integrity to the Baker seal assembly at 9448' MD (5238' TVD) based on normal operating differential pressures and the passing MITIA to 2600psi on 02/01/15. Surface casing: The well is completed with 7-5/8" 29.7# L-80 surface casing with an internal yield pressure rating of 6890 psi. The surface casing is set at 2602' MD (2289' TVD) and the cement shoe was left open after being drilled out. Primary barrier: The primary barrier to prevent a release from the well and provide zonal isolation is the tubing and packer. Secondary barrier: The production casing is the secondary barrier should the tubing fail. Monitoring: Each well is monitored daily for wellhead pressure changes. Should leaks develop in the tubing or production casing above the surface casing shoe it will be noted during the daily monitoring process. Any pressure trends that indicate annular communication require investigation, Commission notification, and corrective action, up to and including a shut-in of the well. T/IO plots are compiled, reviewed, and submitted to the AOGCC for review on a monthly basis. Proposed Operating and Monitoring Plan 1. Well will be used for water only injection (no MI or gas injection allowed); 2. Perform a passing MITIA every 2 years to the maximum anticipated injection pressure; 3. Allow operating IA pressure up to 2000 psi, operating OA pressure up to 1000 psi; 4. Submit monthly reports of daily tubing, IA & OA pressures, injection volumes and pressure bleeds for all annuli; 5. Shut-in the well should MIT's or injection rates and pressures indicate further problems with appropriate notification to the AOGCC. 2 ti111ell Name Start Date Days End Date 2L-323 811/2015 90 1013012015 Notes: Bleed History A000 3500 3000 2500 2000co 1s0o- 1000 Sao- o- Jul-15 Annular Communication Surveillance ~~ -_ WHP [P OAP WELL-10 2L-323 160 2L-323 2L-323 140 120 100 U. s0 60 40 24 ° TIME STR-PRES ENE)-PRES dtF-PRES CASING SERME 1011012015 1250 950 300 INNER P O 10121201E 1950 1120 830 INNER PY0 91=015 1362 963 399 INNER PO W HT Aug-15 Aug-15 Aug-15 Sep-15 Sep-15 Sep-15 0ct-15 0ct-15 Oct-15 Nov-15 Nov-15 v� w 2- -IVA -Got tOM C Jul-15 Aug-15 Aug-15 Aug-15 Sep-15 SOP-15 Sep-15 0ct-15 0ct-15 0ct-15 Nov-15 Nov-15 Date STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION Mechanical Integrity Test Submitto: dim. regg(caalaska.gov: AOGCC.Inspectors(rDalaska.gov: phoebe.brooks(a)alaska.gov chris.wallace(a)alaska.gov OPERATOR: ConocoPhillips Alaska, Inc. FIELD / UNIT / PAD: Tarn / KRU / 2L DATE: 02/01/15 OPERATOR REP: Miller / Riley AOGCC REP: not witnessed Packer Depth Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. Well 2L-323 I Type Inj. N TVD 1 5,237' Tubingl 3,1801 3,180 3,1801 3,180 1 1 Interval O P.T.D. 1982510 I Type test I P Test psi 1500 Casingl 9501 2,6001 2,5801 2,575 P/F P Notes: Diagnostic MITIA 0AJ 2001 2001 2001 200 Well 2L-323 I Type Inj. N I TVD 1 5,237'1 Tubingl 3,1801 3,180 3,1801 3,180 1 1 Interval O P.T.D. 1982510 I Type testl P I Test psi 1 15001 Casingl 2,5751 1,0101 1,0501 1,058 P/F I P Notes: Diagnostic IA drawdown test I OAJ 2001 2001 2001 200 Weill I Type Inj. I TVD I I Tubingl I I I I I I Interval P.T.D.1 I Type test I I Test psi I I Casing P/F Notes: I OA WeIll I Type Inj. I TVD I I Tubingl I I I I Interval P.T.D.1 I Type test I I Test psi I I Casing P/F Notes: I OA Weill I Type Inj. I I TVD I I Tubingl I I I I I I Interval P.T.D.1 I Type test I I Test psi I I Casing P/F Notes: I OA TYPE INJ Codes TYPE TEST Codes D = Drilling Waste M = Annulus Monitoring G = Gas P = Standard Pressure Test I = Industrial Wastewater R = Internal Radioactive Tracer Survey N = Not Injecting A = Temperature Anomaly Survey W = Water D = Differential Temperature Test INTERVAL Codes I = Initial Test 4 = Four Year Cycle V = Required by Variance O = Other (describe in notes) Form 10-426 (Revised 11/2012) MIT KRU 2L-323 Diagnostic non witnessed 02-01-15.x1s KUP 2L-323 ConocoPhillipsa Cd1oCOPhAi,r�, Well Attributes Max An le & MD TD Wellbore APUUWI Field Name Well Status 501032028200 TARN PARTICIPATING AREA INJ Incl M 67.81 MO (RKB) 8,796.46 Act St. (ftKH) 10,400.0 comment SSSV: NIPPLE H2S (ppm) Date Annotation End Date KB-Grd (R) Last WO: 36.59 Rig Release Date 12/26/1998 Annotation Depth Last Tag: SLM (RKB) 9,687.0 End Date 8/13/2011 Annotation Rev Reason: WELL REVIEW Last Mod ... osborl End Date 7/18/2012 ,CasingStrings Casing Description CONDUCTOR ____ String 0. 16 String ID ... 15.062 Top (ftKB) 28.0 Set Depth if... 108.0 Set Depth (TVD) ... String 108.0 WL.. 62.58 String ... H-40 String Top Thrd WELDED Casing Description SURFACE String 0... 7 518 String ID ... 6.875 Top(ftKB) 28.5 Set Depth (f... 2,602.0 Set Depth (TVD) ... String 2,288.6 Wt... 29.70 String ... L-80 String Top Thiel BTC-MOD Casing Description PRODUCTION 5.5"x3.5" @ 9470' String 0... 51/2 String ID ... 4.950 Top (ftKB) 25.2 Set Depth (L.. 10,395.2 Set Depth (TVD) ... String 5.770.9 Wt... 15.50 String ... L-80 String Top Thrd EUE-8RD Tubin Strin s Tubing Description String 0... iStringSet Depth (1. Set Depth (ND) ... String Wt... String... String Top Thrd TUBING 73_1/02 2992 25.0 9,463.3 �_ 5,245.9 9.30 '-80 EUE-8rd _ - Completion Details Top (ftKB ) Top Depth (TVD) (ftKB) Topincl V) Item Description Comment - Nomi... ID (in) 25.0 25.0 0.56 HANGER FMC GEN V TUBING HANGER 3.500 518.0 518.0 0.21 NIPPLE CAMCO DS NIPPLE 2.875 9,338.6 5,174.4 56.52 SLEEVE BAKER CMU SLIDING SLEEVE (CLOSED 2126/1999) 2.813 9,439.4 5,231.8 54.06 NIPPLE CAMCO D NIPPLE 2.750 9,446.3 5,235.8 53.89 LOCATOR BAKER LOCATOR 80-40 2,985 9,447.8 5,236.1 53.85 SEALS BAKER SEAL ASSEMBLY w/15' STROKE 2.900 - Perforations & Slots Top (R(B) BM (ftKB) Top (TVD) (flK8) Bim (TVD) (ftKB) Zone Date Shot Dens (sh•^ Type Comment 9,670.0 9,706.0 5,367.8 5,388.8 S-5, 2L-323 225/1999 6.0 IPERF 60 penetrating;2.5"HC deg phase deep 9,746.0 9,774.0 5,412.0 5,428.0 S-3, 2L-323 225/1999 6.0 IPERF 60 penetrating;2.5"HC deg phase deep 9,796.0 9,928.0 5,440.E 5,515.5 T-2, 2L-323 225/1999 6.0 IPERF 60 penetrating25"HC deg phase deep Notes: General & Safety End Date Annotation 11/9/2010 NOTE: VIEW SCHEMATIC W/Alaska Schematic9.0 Mandrel Details Stn Top (TVD) Top IRKS) (ftKB) Depth Top Incl r) Make Model OD (in) a., Valve Type ch e Port Size TRO (in) Run (Psi) Run Date Com... 1 4,422.9 3,077.7 67.87 CAMCO KBG 2-9 1 GAS LIFT DMY ;NT 0.000 0.0 1227/1998 2 9,386.8 5,201.4 55.34 CAMCO KBG 2-9 1 GAS LIFT DMY 0.000 0.0 1227/1998 Well Conlin -2L-3237/182012220'i6 PM Schematic -Actual HANGER,25 CONDUCTOR, 28-108 NIPPLE, 518 �.. €p3, E SURFACE, 28-2,602 GAS LIFT, 4.423 SLEEVE, 9,339 GAS LIFT, 9,387 NIPPLE, 9,439 %�-�, LOCATOR, 9,446 SEALS, 9,448 IPERF, _ 9.670-9,706 = --- IPERF, 9,746-9. 74 IPERF._ 9.796.9.928 - PRODUCTION 5.S'x3.5" @ 9470% 25 10,395 TD, 10,400 13 ConocoPhillips Alaska P.O. BOX 100360 ANCHORAGE, ALASKA 99510-0360 April 1, 2014 Commissioner Dan Seamount Alaska Oil & Gas Conservation Commission 333 West 7"' Avenue, Suite 100 Anchorage, AK 99501 Dear Commissioner Seamount: RECEIVED APR 0 3 2014 AOGCC ConocoPhillips Alaska, Inc. presents the attached proposal per AIO 16, Rule 10, to apply for Administrative Approval allowing well 2L-310 (PTD 210-028-0) to be online in water only injection service. Currently, the well displays TxIA communication only when injecting MI. ConocoPhillips intends to pursue repairs should MI injection be desired in the future. If a successful repair is achieved we will request the well be returned to normal status and resume ability to inject MI. If you need additional information, please contact myself or Brent Rogers at 659-7224, or MJ Loveland / Martin Walters at 659-7043. Sincerely, Kelly Lyons Problem We s Supervisor ConocoPhillips Alaska Inc. Attachments ConocoPhillips Alaska, Inc. Kuparuk Well 2L-310 (PTD# 210-028-0) Technical Justification for Administrative Relief Request Purpose ConocoPhillips Alaska, Inc. proposes that the AOGCC approve this Administrative Relief request as per Area Injection Order 16, Rule 10, to continue water only injection for Tarn injection well 2L-310. The well displays annular communication only when the well is on MI injection. Well History and Status Kuparuk River Unit well 2L-310 (PTD 210-028-0) was drilled and completed in May 2010 as a development well. It was converted to a WAG service well in May 2013. 2L-310 was initially reported to the Commission on February 3, 2014, as showing signs of tubing by inner annulus (TxIA) communication while on MI injection. Initial diagnostics on 02/05/14 included passing tubing and inner casing packoff tests and an MITIA to 3000 psi. After the inner annulus displayed intermittent periods of repressurization during the approved follow-up monitoring period while on MI injection, the well was WAG'ed to water injection on March 06, 2014. Since then, the well has not shown any signs of TxIA communication while on water injection. ConocoPhillips intends to pursue repairs if the leak worsens enough to be detectable and located while on water injection. However, until the leak is detectable both on gas and water injection, ConocoPhillips requests an AA which will allow the well to remain online in water only injection service. The IA pressure will be maintained below 2000 psi. Barrier and Hazard Evaluation With only water injection, this well has all the barriers of a normal injection well Tubing: The 3-1/2" 9.3# L-80 tubing has integrity to the Baker FHL packer @ 9737' MD (5238' TVD), based on passing normal operating injection differential and the passing MITIA on 02/05/14. Production casing: The 7-5/8" 29.7# L-80 production casing has integrity to the Baker FHL packer @ 9737' MD (5238' TVD) based on passing normal operating injection differential and the passing MITIA on 02/05/14. Surface casing: The well is completed with 10-3/4" 45.5# L-80 surface casing with an internal yield pressure rating of 5210 psi. The surface casing is set at 3521' MD (2417' TVD). Primary barrier: The primary barrier to prevent a release from the well and provide zonal isolation is the tubing and packer. Secondary barrier: The production casing is the secondary barrier should the tubing fail. Problem Wells Supervisor 4/1/2014 1 Monitoring: Each well is monitored daily for wellhead pressure changes. Should leaks develop in the tubing or production casing above the surface casing shoe it will be noted during the daily monitoring process. Any pressure trends that indicate annular communication require investigation, Commission notification, and corrective action, up to and including a shut-in of the well. T/IO plots are compiled, reviewed, and submitted to the AOGCC for review on a monthly basis. Proposed Operating and Monitoring Plan 1. Well will be used for water only injection (no MI or gas injection allowed); 2. Perform a passing MITIA every 2 years to the maximum anticipated injection pressure; 3. Allow operating IA pressure up to 2000 psi, operating OA pressure up to 1000 psi; 4. Submit monthly reports of daily tubing & IA pressures, injection volumes and pressure bleeds for all annuli; 5. Shut-in the well should MIT's or injection rates and pressures indicate further problems with appropriate notification to the AOGCC. Problem Wells Supervisor 4/1/2014 2 cc ti ti UJ KJ W 4J kJ O a> s M O 8 cA Gb _ W CY C3 u sJ o N a� w In Ln O o t7 c'a [3 O J c7 �`R r s+r M cue 04 ABap v C is tU C tts �C 3 ff} C Q a r Cu m L Ci xi .0 c� G E 0 L (} C pq fG r e- r7rv�h z C O U O r1 ri rr cV N .- Od19 bi= H _ 0Y f4 ISd 'n0uj KUP PROD 2L-310 �-y ConocoPhillips iWell Attributes _ Max An le & MD TD Nasta.illt; WellboreAPIIUWI F Id Name 501032061600 TARN PARTICIPATING AREA Wellbore PROD Status Incl(°) MD(ftKB) 67.51 2,780.72 Act Sun [ftKB) 10,252.0 - Comment H2S (ppm) Date Annotation End Date KB-Grd (ft) Rig Release Date SSSV: NIPPLE 20 12/23/2012 LastWO: 2010 5/13/te Well Conf HORIZONTAL - 2L-310, 8/272D1380621 AM Schematic -Actual Annotation Depth (ftKB) End Date Annotation Last Last Mod End Date Last Tag: SLM 10,055.0 5/11l2013 Rev Reason: it WELL CONVERTED TO INJECTION osbod 8/27Y2013 HANGER. 23 a ' h Strin s Casing Descnption String 0... String ID ... Top (ftKB) Set Depth (f... Set Depth (ND)... String Wt... String ... String Top Thrd CONDUCTOR 16 15.062 28.0 112.0 112.0 62.50 H-40 WELDED " .a. Casing Description String 0... String ID ... Top (ftKB) Set Depth (f Set Depth (ND) ... String Wu... String ... String Top Thrd SURFACE 10314 9.950 27.6 3,521.0 2,416.5 45.50 1-80 BTC Casing Description String 0... String ID ... Top (ftKB) Set Depth (f... Set Depth (ND) ... String Wt... String ... String Top Thrd ' PRODUCTION 75/8 6,875 25.6 10,247.0 5,615.2 29.70 L-80 BTC-m -- _._9- Tubin St_rin s Tubing D ption String 0... String ID �T Set Depth (f... Set Depth (TV D) ... String Wt.. Stnng ... String Top Third TUBING 3 1/2 2992 23.3 9,800.0 5,283.1 9.30 L 80 EUE8rdABMOD Com letion Details _._ rTop Depth _ (ND) Top IncI� Nomi.., Too fftK81 (ftKB) (°) Item Description Comment ID (in) CONDUCTOR, 28-112 NIPPLE, 51E SURFACE, 26-3.521 GAS LIFT. GAS LIFT, 8,717 GAS LIFT, 9,617 SLEEVE-C, 9.671 CHOKE, 9,790 NIPPLE. 9.790 WLEG, 9,800 10,00SPERF, FRAC, 10,019 RAC, 10,005 Other In Hole Wireline retrievable plugs, valves, pumps, fish, etc.)_ Top Depth (ND) Topinet Top (ftKB) (ftKB) (°) Description Comment Run Date ID (in) 9,790.3 5,276.11 43.36 CHOKE .406" CHOKL ON 2.75" C-LOCK SET IN NIPPLE 5/31/2013 0.406 Perforations & Slots _ - Shot Top (7VD) Stm (TVD) Dens Top (ftKB) St. (ftKB) (ftKB) (ftKB) Zone Date (°h - Type Comment 10,005.0 10,019.0 5,434.5 5,444.9 Bermuda, 2L-310 6/82010 6.0 IPERF 2.5" Prospector RDX DP charges, 60 deg phase :Stimulations & Treatments Bottom Min Top Max Bum Top Depth Depth Depth Depth (ND) (ND) (ftKB) (ftKB) (ftKB) (ftKB) Type Date Comment 10,005.0 10,019.0 5,434.5 5444.9 FRAC 6/10/2010 Pumped 242,621 Ibs of Carbolite, placing 240,731lbs behind pipe (pumped 2,602 bbls of fluid). Completed FRAC w/9 ppa on formation. Dotes: General & Safety ncl OD (°) Make Model (in) Valve I Latch I Size ITRO Run Type Type (in) (pal) Run Data I Co.... PRODUCTION, _ 2&10,247 TD, 10,252 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION Mechanical Integrity Test Submit to: jim.reQq(a)alaska.gov; AOGCC.Ins ectors alaska. ov phoebe.brooks(cbalaska.gov chds.wallace(a)alaska.aov OPERATOR: ConocoPhillips Alaska Inc. FIELD / UNIT / PAD: Tarn / KRU / 2L Pad DATE: 02/05/14 OPERATOR REP: Richwine / Manjarrez AOGCC REP: Packer Depth Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. Well 2L-310 I Type Inj. I G TV D 5,238' Tubing 2,225 2,225 2,225 2,225 Interval p P.T.D. 2100280 I Type test I P Test psi 1500 Casing 1,890 3,0001 2,9501 2,940 P/F P Notes: Diagnostic MITIA OA 371 3741 3761 375 IA bled back to 1240 psi post MITIA for monitoring. Well I I Type Inj. I I TVD Tubing Interval P.T.D.1 I Type test I Test psi Casing P/F Notes: OA Well I Type Inj. TVD Tubing Interval P.T.D.1 I Type test Test psi Casing P/F Notes: OA Well I Type Inj. I TV D Tubing Interval P.T.D. I Type test Test psi Casing P/F Notes: OA Well Type Inj. I TV D Tubing Interval P.T.D.1 I Type test I Test psil Casing 4- P/F Notes: OA TYPE INJ Codes TYPE TEST Codes D = Drilling Waste M = Annulus Monitoring G = Gas P = Standard Pressure Test I = Industrial Wastewater R = Internal Radioactive Tracer Survey N = Not Injecting A = Temperature Anomaly Survey W = Water D = Differential Temperature Test INTERVAL Codes I = Initial Test 4 = Four Year Cycle V = Required by Variance O = Other (describe in notes) Form 10-426 (Revised 11 /2012) MIT KRU non -witnessed 2L-310 02-05-14.Xls #12 THE STATE Conservation Commission GOVERNOR SEAN PARNEI.,L August 16, 2013 CERTIFIED MAIL — RETURN RECEIPT REQUESTED 7009 2250 0004 3911 5884 Mr. Jerry Dethlefs Well Integrity Director ConocoPhillips Alaska, Inc. P.O. Box 100360 Anchorage, AK 99510-0360 Re: Amendment of Alternative MIT schedule for tJIC injection Wells Dear Mr. Dethlefs: 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 By a letter received on May 9, 2013 ConocoPhillips Alaska, Inc (CPAI) requested approval to amend the permanent Mechanical Integrity Test (MIT) schedule for Class I1 injection wells in fields operated by CPAI on the North Slope of Alaska. The Alaska Oil and Gas Conservation Commission (AOGCC) hereby APPROVES the requested amendment establishing the MIT due date for Kuparuk River Unit 1J-pad injection wells as May, and Colville River Unit pads CD3 as February and CD4 as June. AOGCC also APPROVES CPAI's request to allow for a test month for MITs in lieu of an anniversary date. No further action is deemed necessary regarding MITs in Area Injection Orders 2B, 16, 18C, 21A, 28, 30 and 35. Should you have any questions, please contact Chris Wallace at 907-793-1250. P Cathy P. oers er Chair, Commissioner RECONSIDERATION AND APPEAL NOTICE As provided in AS 31,05.080(a), within 20 days after written notice of the entry of this order or decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration of the matter determined by it. If the notice was mailed, then the period of time shall be 23 days. An application for reconsideration must set out the respect in which the order or decision is believed to be erroneous. The AOGCC shall grant or refuse the application for reconsideration in whole or in part within 10 days after it is filed. Failure to act on it within 10-days is a denial of reconsideration. If the AOGCC denies reconsideration, upon denial, this order or decision and the denial of reconsideration are FINAL and may be appealed to superior court. The appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision denying reconsideration, UNLESS the denial is by inaction, in which case the appeal MUST be filed within 40 days after the date on which the application for reconsideration was filed. If the AOGCC grants an application for reconsideration, this order or decision does not become final. Rather, the order or decision on reconsideration will be the FINAL order or decision of the AOGCC, and it may be appealed to superior court. That appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision on reconsideration. As provided in AS 31.05.080(b), " Whe questions reviewed on appeal are limited to the questions presented to the AOGCC by the application for reconsideration." In computing a period of time above, the date of the event or default after which the designated period begins to run is not included in the period; the last day of the period is included, unless it falls on a weekend or state holiday, in which event he period runs until 5:00 p.m. on the next day that does not fall on a weekend or state holiday. Postal CERTIFIED, tDonlestic Mail Only; .- .0 For ,, a Q" Postage $ M Certified Fee Retun Receipt Fee Postmark Here ED (Endorsement Required) ED Recuia d Delivery Fee lD (Endorsement Required) to rU Total Postage E ri3 11 end o Q Mr. Jerry DetMefs SVeet,ApLNo.; Well Integrity Director � or PO Box No. Conoco Phillips Alaska, Inc. City Siai®, ZiPi< Post Office Box 100360 Anchors e AK 99510-0360 :r r E Cosnpfete, items 1, 2, and 3. Also complete item 4 if Restricted Delivery is desired. if Print your name and address on the reverse so that we can return the cart} to you. f Attach this card to the back of the mailpiece, or on the front if space permits. 1. Article Addressed to: Mr. Jerry Dethlefs Well Integrity Director ConocoPhillips Alaska, Inc. Post Office Box 100360 Anchorage, AK 99510-0360 A. Sig ure X Q Agent i ❑ Addressee R'4Xed by ( Printe ame) C. Date of Delivery 5--e D. Is deliv ry address different from item 1? ❑ Yes If YES, enter delivery address below: ❑ No 3. S ce Type Certified Mail 0 Express Mail ❑ Registered ❑ Return Receipt for Merchandise ❑ Insured Mail ❑ C.O.D. 4. Restricted Delivery? (Extra Fee) ❑ Yes 2. Article Number 7009 2250 0004 3911 5884 (transfer from service fabeq PS Form 3811, February 2004 Domestic Return Receipt 102595-02-tt-1540 i THE STATE ,,ALASKA Alaska Oil an d Gas GOVERNOR SEAN PARNELL 333 west Seventh Avenue Anchorage, Alaska 99501-3572 td�a�rc 5�7.279. � =;33 rax:907,276.7542 August 16, 2013 AOGCC Industry Guidance Bulletin No. 10-02A Mechanical Integrity Testing The Alaska Oil and Gas Conservation Commission (AOGCC) provides the followin« clarification of injection well mechanical integrity pressure test (M17-) requirements set forth in 20 AAC 25252 and 25.402. Injection orders supplement AOGCC regulations by providing additional operating and testing obligations. MIT Preparation - The AOGCC must be notified at least 24 hours in advance (48 hows for wells remote from the nearest AOGCC office) for an opportunity to witness the MIT; - Pumping into and bleeding pressures from annuli should be avoided for 24 hours prior to the MIT; if necessary, information should be available to document such activity; - The well's annulus must be fluid packed before the AOGCC Inspector arrives; - Calibrated pressure gauges with suitable range and accuracy must be installed on the tubing, inner (tubing by casing) annulus, and outer (casing by casing) annuli; current calibration should be evident with proper labels or other documentation; - Suitable flow measurement equipment should be available to determine the volume of fluids pumped into and returned from the tested space; - Other equipment (e.g., tanks, lines, bleed trailers, etc.) necessary for the safe pressure testing and suitable for the operating environment should be rigged up prior to AOGCC Inspector arrival at the location. The following information must be available at the location for AOGCC Inspector review: - Valid approved waivers, if any, relating to the integrity of the tested well; - Current well schematic; - Graph of tubing, inner annulus, and outer annulus pressures for the preceding 90 days. Equipment Pressure Rating Equipment subject to test pressure must have a rated working pressure that meets or exceeds the planned test pressure. API defines the rated working pressure of equipment to be the maximum internal pressure that the equipment is designed to contain or control. • Guidance Bulletin 10-02A Mechanical Integrity Vesting Pagc 2 of 3 Test Cycle After the initial MIT, Class 11 disposal wells injecting solid slurries (used muds, cuttin�ps, produced sand, etc.) require an MIT once every 2 years; otherwise, MITs must be conducted once every 4 years. Injection wells used for enhanced recovery operations must be tested once every 4 years. The AOGCC may, in its discretion, approve an alternate MIT schedule. A 2- or 4-year MIT means the test must be performed not later than the 2- or 4-year anniversary of the test month, unless a specific anniversary date for the MIT has been established by AOGCC approval (e.g., Area Injection Order administrative approval). For example, a test due August 14, 2014 would — under the new "test month" approach - be allowed to be tested not later than August 10, 2014. Operators are encouraged to take advantage of operating efficiencies in scheduling groups of MITs, and to initiate scheduling early in the month to increase inspector availability and allow time for retesting or unplanned events. The AOGCC must be provided the opportunity to witness the MIT for a test to establish a new test due date. The AOGCC may require a witnessed test to be rescheduled to accommodate workload priorities. A pre -injection MIT performed prior to demobilizing a drilling rig from a well should be documented on the AOGCC's MIT Form 10-426 and emailed to the AOGCC addressees noted on the test report form. Test Pressure Unless otherwise required by the AOGCC, an MIT of the inner annulus is required to a minimum pressure of 1500 psi or a pressure determined by multiplying 0.25 psi per foot times the true vertical depth of the packer — whichever is greater. A minimum pressure differential of 500 psi should be maintained between the tested annulus and tubing or adjacent annulus. The operator has the discretion to test to a higher pressure. A passing MIT will have no more than a 10 percent decline in pressure (based on the actual test pressure), a stabilizing pressure trend, and a final pressure that is at or above the required test pressure. For example, the operator may choose to start a required 1500 psi test at or above 1650 psi (additional 150 psi to allow for the 10 percent pressure decline over test duration). Reporting Unless otherwise required by the AOGCC, MIT results must be verified by an operator's designated representative and submitted electronically using Form 10-426 to the AOGCC no later than the 51h calendar day of the month following the testing. 0 Guidance Bulletin 10-02A Mechanical Integrity Testing I'aae 3 of Shut-in Wells The AOGCC's preference is to witness an MIT while a well is actively injecting and wellbore conditions (rate and temperature) are stable. If the well is in a short-term shut-in status when the MIT is due, the AOGCC should be notified and provided an alternate date for testing based on when injection will be recommenced. Injection wells that are shut in long-term (undetermined when injection will restart) need not be tested until they are ready to recommence injection. In lieu of an MIT for the long term shut-in well the operator must provide to the AOGCC a quarterly graph of tubing, inner annulus and outer annulus pressures. Please share this Guidance Bulletin with all appropriate members of your organizations. Questions or discussion regarding this Guidance bulletin should be directed to Chris Wallace. at (907) 793-1250. Sincerely, Cathy P.-oerster Chair, Commissioner • ConocoP hillips May 8, 207,2 Mr. Chris Wallace Alaska Oil & Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, AK 99501 9 P!' C 1 I V Efo MAY 0 2014 AlOGICC Subject: Amendment of alternative MIT schedule for UIC injection wells Dear Mr. Wallace: Jerry Dethlefs Well Integrity Director ConocoPhillips Alaska, Inc 700 G Street Anchorage, AK Phone 907-265-1464 ConocoPhillips Alaska, Inc. (CPAI) requests approval to amend the permanent Mechanical Integrity Test (MIT) schedule for Class II injection wells in fields operated by CPAI on the North Slope of Alaska. The amendment is to include new pads installed since the original approval and to clarify the affected Area Injection Orders (AIO). On February 13, 2006, CPAI requested approval to adopt an alternate MIT schedule for their North Slope Class II injection wells so as to allow the majority of the wells to be tested during the summer months (schedule attached). On March 23, 2006, administrative approval was granted for the alternate schedule by the AOGCC (attached). The approval letter states "The requested schedule modification will allow for greater operating efficiency and will reduce risks to personnel and the environment. The Commission hereby APPROVES the requested modification." The alternative test schedule also complies with the AOGCC Industry Guidance Bulletin No. 10-002 Mechanical Integrity Testing. The section titled "Test Cycle" reads: "Injection wells used for enhanced recovery operations must be tested once every 4 years. The Commission may, in its discretion, approve an alternate MIT schedule. A 2- or 4-year MIT means the test must be performed not later than the 2- or 4-year anniversary of the most recent test date, unless a specific anniversary date for the MIT has been established by a Commission approval (e.g., Area Injection Order administrative approval)." ....."Operators are encouraged to take advantage of operating efficiencies in scheduling groups of MITs within the 2- or 4-year window"...... A key component of the 4-year testing program is that each pad is assigned a specific month to be tested every four years. (see attached schedule). The number of pads and wells are divided over the four year period so that roughly one-fourth of the required MITs are performed each year. The specified month is the due date, rather than the specific day of the prior test, to eliminate schedule creep over time. All injection wells on a pad will be tested during the visit. This method was adopted and put into practice with the March 23, 2006 approval and has proven to work well. Please note that CD3, due to lack of summer road access, is scheduled for February by prior AOGCC approval. • • CPAI is requesting an amendment to incorporate new drillsites and clarify the affected AIOs. Drillsites 1J, CD3 and CD4 have been added to the list. The administrative approval regards Rule 6 in AIOs 2B, 16, 18C, 28, 30 and 35, and Rule 4 in 21A. The MIT schedule applies only to CPAI wells on the standard 4-year test frequency, with the exception of 2P (Meltwater) which is on a 2-year cycle due to recent changes in AIO 21A. Wells with specific approvals or variances on 2-year test cycles will continue to be tested on or before the exact 2-year anniversary date. Approval of this request at your earliest convenience is appreciated. Please call Brent Rogers or Kelly Lyons at 659-7224, or me at 265-1464 if you have any questions. Sincerely, Jerry Dethlefs Well Integrity Director cc: Jim Regg Cathy Forester Attachments • • ConocoPhillips Alaska, Inc. UIC MIT Permanent Test Schedule Revised May 7, 2013 Target 4-year Cycle: The following schedule repeats every 4 years Year 1 Kuparuk Alpine May 2A, 2B, 2G, 2H June IF, 1 L, 2M, 2V July 2E, 2F, 3J, 3M August 3N, 3Q, 3R, 2P* Year 2 May 3K June 1 B & WSW, 2T, 3H, 30 CD1 July 1Q, 1Y August 1 H, 2C, 2D, 3A, 3C Year 3 February CD3 May 1 C, 1 J June 1 E CD2 July 1 D August 2L, 2N, 2P*, 2U, 3S Year 4 May 1 R, 2W June 2K, 2X, 3B, 3F CD4 July 1A, 1G, 31 August 3G, 2Z Note: Year 1=2012 Revised 05-07-13 Contact: CPAI Problem Well Supervisor, 907-659-7224 • ConocoPh i I I i ps Alaska P.O. BOX 100360 ANCHORAGE, ALASKA 99510-0360 February 13, 2006 Mr. Tom Maunder Alaska Oil & Gas Commission 333 West 7ch Avenue, Suite 100 Anchorage, AK 99501 Subject: Proposal for permanent MIT schedule on UIC injection wells Dear Mr. Maunder: On December 19, 2005, ConocoPhillips Alaska, Inc. (CPAI) requested approval to delay UIC 4-year Mechanical Integrity Tests (MIT) due in 2006 for a limited time beyond their due date so the tests could be performed during the summer months. The request was approved by the AOGCC on December 29, 2005, with the stipulation no further extensions would likely be granted for future years. CPAI is proposing an alternative test plan that should meet the objectives of both CPAI and AOGCC. The AOGCC position is that UIC MIT tests be performed no later than the exact due date of the previous 4-year test on each well, as specified in 20 AAC 25.412 and in Area Injection Orders 2B and 18B. The justification for this date enforcement is lack of precedent within the regulations for an Operator to alter the due date without specific approval from the AOGCC. Previously these tests had routinely been delayed to the summer months due to safety and spill potential issues and efficiency/cost savings associated with performing these tests during warm weather. CPAI is proposing a schedule for UIC MIT testing patterned after the AOGCC required program used for testing the Safety Valve System (SVS). In that program each pad is assigned to two specific months of the year for testing. To prevent schedule creep over time, there is some flexibility to perform the tests anytime during the assigned month. The pads are scheduled to roughly balance the workload from one month to the next. For 4-year UIC MIT testing, CPAI is proposing that each pad be assigned a specific month to be tested every four years. The number of pads and wells will be divided over the four year period so that roughly one-fourth of the required MITs will be performed each year. The specified month will be the due date, rather than the specific day of the prior test, to eliminate schedule creep over time. To implement this schedule Mr. Tom Maunder Page 2 of 2 02/13/06 CPAI will accelerate testing on a number of wells over the next few years. The proposed schedule and pad/month assignments are attached. There are a number of benefits to this proposal: • Each well will be tested close to the previous 4-year test if a small allowance is approved to prevent schedule creep. This should meet the "every 4-year" test frequency requirement in the UIC regulations. • All the injection wells on a given pad will be addressed during the same testing operation, regardless of when the last test was performed on a particular well. This will keep all the wells on the same schedule, results in efficiencies in time and reduces fluid handling risk. • Eliminates requests to "reset" the 4-year clock when tests are performed during the year, eliminating significant record keeping efforts. • The proposed months are in the May through August time period that meets the CPAI goal of testing during warmer weather. The AOGCC is specifically being requested in this proposal to approve the "due month" concept of this plan rather than the "exact due date" specified in the letter dated December 29, 2005. In addition, the proposal applies only to CPAI wells on the standard 4-year test frequency. Wells with specific approvals or variances on 2-year test cycles will continue to be tested on or before the exact 2-year anniversary date. Approval of this request at your earliest convenience is appreciated. Please call MJ Loveland, Marie McConnell, or me at 659-7224 if you have any questions. Sincerely, Jerry Dethlefs Problem Well Supervisor Attachment ConocoPhillips Alaska, Inc. Proposed UIC MIT Permanent Test Schedule Initial 4-year Cycle: Requires accelerating tests for all wells on a pad to be on same cycle Year 1: 2006 Total Wells Kuparuk Pads Alpine Pads Total Wells May 22 1C June 56 1 B, 3H, 30, 1 E July 54 1 D, 1 Q, 1Y, 3F' August 48 1A*, 1 R*, 2G*, 2K', 2L, 2N, 2P, 21J, 2W, 2Z*, 3G', 3S CD2 29 Total 180 Year 2: 2007 May 21 1 R, 2W June 53 2K, 2T, 2X, 3B, 3F July 28 1 A, 1 G, 31 August 25 1 F', 2D', 217', 2H', 2M*, 3G, 3M*, 2Z Total 127 Year 3: 2008 _ May 23 -- 2A, 2B, 2G, 2H _ June 38 1 F, 1 L, 2M, 2V July 30 2E, 2F, 3J, 3M CD1* 2 August 24 3N, 3Q, 3R Total 115 Year 4: 2009 May 14 3K June 39 1 B, 2T, 3H, 30 July 19 1Q, 1Y August 35 1 H, 2C, 2D, 3A, 3C CD1 22 Total 107 Target 4- ear Cycle: The followin schedule repeats every 4 years Year 5 May 22 1C June 31 1E July 34 ID August 32 2L, 2N, 2P, 2Z, 3S CD2 29 Total 119 Year 6 May 21 1 R, 2W June 38 2K 2X, 3B, 3F July 18 1 A, 1 G, 31 August 18 3G, 2Z Total 95 Year 7 May 23 2A, 2B, 2G, 2H June 38 1 F, 1 L, 2M, 2V July 30 2E, 2F, 3J, 3M August 24 3N,30,3R Total 115 Year 8 May 14 3K June 40 2T, 1 B, 3H, 30 July 27 1Q, 1Y August 35 1 H, 2C, 2D, 3A, 3C CD1 24 Total 116 Notes: 1) * Denotes pads to be accelerated prior to due -date for combining all wells on a pad to same test date 2) New pads will be added to the schedule as they are brought in service • • zffA E 0 91ALTASEA / FRANK H. MURKOWSKI, GOVERNOR AlFiASlA 011L AND GAS 3331 7"' AVENUE, SURE 100 CONSERQAI`ION COMHSSION ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 FAX (907) 276-7542 Mr. Jerry Dethlefs Problem Well Supervisor ConocoPhillips Alaska, Inc. P.O. Box 100360 Anchorage, AK 99510-0360 RE: North Slope MIT Schedule Dear Mr. Dethlefs: On February 13, 2006 ConocoPhillips Alaska, Inc ("CPAI") requested approval to modify the schedule for demonstrating mechanicalintegrity on their North Slope injection wells so as to allow the majority of the wells to be tested on a rotating schedule during the summer months. The requested schedule modification will allow for greater operating efficiency and will reduce risks to personnel and the environment. The Commission hereby APPROVES the requested modification. In order to allow opportunity for AOGCC Inspectors to witness the testing, CPAI is requested to provide the planned schedule for Summer 2006 as soon as practical. If you have any questions, please contact Jim Regg at 793-1236. As provided in AS 31.05.080(a), within 20 days after written notice of this decision, or such further time as the Commission grants for good cause shown, a person affected by it may file with the Commission an application for reconsideration. A request for reconsideration is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. A person may not appeal a Commission decision to Superior Court unless reconsiderationA been requested. Alaska and dated March 23, 2006 1 1 o an Dan T. Seamount, Jr. arm Commissioner *Cathy. Foerster Commissioner • 0 ConocoPhillips April 8, 201� Mr. Dan Seamount Alaska Oil & Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, AK 99501 Jerry Dethlefs Well Integrity Director ConocoPhillips Alaska, Inc 700 G Street Anchorage, AK Phone 907-265-1464 Nvlb�b 5 (L3 (13" b od(etdoj- )-3 • 1(0 Subject: Administrative Approval for alternative MIT schedule for UIC injection wells (revised) Dear Mr. Seamount: ConocoPhillips Alaska, Inc. (CPAI) requests approval for a modified Mechanical Integrity Test (MIT) schedule for Class II injection wells in fields operated by CPAI on the North Slope of Alaska. A provision in AOGCC Industry Guidance Bulletin No. 10-002 Mechanical Integrity Testing, under "Test Cycle" states: "Injection wells used for enhanced recovery operations must be tested once every 4 years. The Commission may, in its discretion, approve an alternate MIT schedule. A 2- or 4-year MIT means the test must be performed not later than the 2- or 4-year anniversary of the most recent test date, unless a specific anniversary date for the MIT has been established by a Commission approval (e.g,, Area Injection Order administrative approval)." CPAI is requesting administrative approval from Rule 6, Area Injection Orders 2B, 16, 18B, 27, 28, 30 and 35, and Rule 4, AIO 21, in order to "take advantage of operating efficiencies in scheduling groups of MITs within the 2- or 4-year window" (reference Bulletin 10-002). On February 13, 2006, CPAI requested approval to modify the MIT schedule for their North Slope Class II injection wells so as to allow the majority of the wells to be tested during the summer months (attached). On March 23, 2006, approval was granted for the modified schedule by the AOGCC (attached). The approval letter states "The requested schedule modification will allow for greater operating efficiency and will reduce risks to personnel and the environment. The Commission hereby APPROVES the requested modification." CPAI complied with the MIT schedule as approved until the AOGCC issued Industry Guidance Bulletin No. 10-002 Mechanical Integrity Testing. According to the AOGCC, as of the date of the Guidance Bulletin the administrative approval for the MIT test schedule was revoked. Although the Guidance Bulletin may meet the needs of other operators in the state, it also results in placing CPAI back to the point of the initial schedule modification request. Therefore, CPAI is again requesting approval to modify the MIT schedule by Area Injection Order administrative approval. The justification for the schedule change request has not altered since the original request in 2006. CPAI requests relief from the requirement in Bulletin 10-002: "A 2- or 4-year MIT means the test must be performed not later than the 2- or 4-year anniversary of the most recent test date, unless a specific anniversary date for the MIT has been established by a Commission approval (e.g., Area Injection Order administrative approval). " CPAI proposes a schedule for UIC MIT testing patterned after the AOGCC required program used for testing the Safety Valve System (SVS). In that program each pad is assigned to two specific months of the year for testing. To prevent schedule creep over time, there is some flexibility to perform the tests anytime during the assigned month. The pads are scheduled to roughly balance the workload from one month to the next. For 4-year UIC MIT testing, CPAI is proposing the same schedule as that approved in 2006; that each pad be assigned a specific month to be tested every four years (see attached schedule). The number of pads and wells are divided over the four year period so that roughly one-fourth of the required MITs are performed each year. The specified month is the due date, rather than the specific day of the prior test, to eliminate schedule creep over time. This method was adopted and put into practice with the March 23, 2006 approval and has proven to work well. Please note that CD3, due to lack of summer road access, is scheduled for February by prior AOGCC approval. There are a number of benefits to this proposal: • Each well will be tested close to the previous 4-year test if a small allowance is approved to prevent schedule creep. This should meet the "every 4-year" test frequency requirement in the UIC regulations. • All the injection wells on a given pad will be addressed during the same testing operation, regardless of when the last test was performed on a particular well. This will keep all the wells on the same schedule, results in efficiencies in time and reduces fluid handling risk. • Eliminates requests to "reset" the 4-year clock when tests are performed during the year, eliminating significant record keeping efforts. • The proposed months are in the May through August time period that meets the CPA] goal of testing during warmer weather to minimize risks regarding personnel safety and releases to the environment. The AOGCC is being requested to approve the "due month" concept of this plan rather than the "exact. due date" specified in Bulletin 10-002. In addition, the proposal applies only to CPAI wells on the standard 4-year test frequency. Wells with specific approvals or variances on 2-year test cycles will continue to be tested on or before the exact 2-year anniversary date. Approval of this request at your earliest convenience is appreciated. Please call Brent Rogers or Kelly Lyons at 659-7224, or me at 265-1464 if you have any questions. Sincerely, Jerry Dethlefs Well Integrity Director cc: Cathy Forester Jim Regg Attachments • • ConocoPhillips Alaska, Inc. UIC MIT Permanent Test Schedule Target 4-year Cycle: The following schedule repeats every 4 years Year 1 Kuparuk p� Alpine May 2A, 2B, 2G, 2H June 1 F, 1 L, 2M, 2V July 2E, 2F, 3J, 3M August 3N, 3Q, 3R Year 2 May 3K June 1B & WSW, 2T, 3H, 30 CD1 July 1Q, 1Y August 1 H, 2C, 2D, 3A, 3C Year 3 February CD3 May 1 C, 1 J June 1 E CD2 July 1 D August 2L, 2N, 2P, 2U, 3S Year 4 May 1 R, 2W June 2K, 2X, 3B, 3F CD4 July 1A, 1G, 31 August 3G, 2Z Note: Year 1=2012 Revised 04-05-12 Contact: CPAI Problem Well Supervisor, 907-659-7224 • • ConocoPhillips Alaska P.O. BOX 100360 ANCHORAGE, ALASKA 99510-0360 February 13, 2006 Mr. Tom Maunder Alaska Oil & Gas Commission 333 West 7`h Avenue, Suite 100 Anchorage, AK 99501 Subject: Proposal for permanent MIT schedule on UIC injection wells Dear Mr. Maunder: On December 19, 2005, ConocoPhillips Alaska, Inc. (CPAI) requested approval to delay UIC 4-year Mechanical Integrity Tests (MIT) due in 2006 for a limited time beyond their due date so the tests could be performed during the summer months. The request was approved by the AOGCC on December 29, 2005, with the stipulation no further extensions would likely be granted for future years. CPAI is proposing an alternative test plan that should meet the objectives of both CPAI and AOGCC. The AOGCC position is that UIC MIT tests be performed no later than the exact due date of the previous 4-year test on each well, as specified in 20 AAC 25.412 and in Area Injection Orders 2B and 18B. The justification for this date enforcement is lack of precedent within the regulations for an Operator to alter the due date without specific approval from the AOGCC. Previously these tests had routinely been delayed to the summer months due to safety and spill potential issues and efficiency/cost savings associated with performing these tests during warm weather. CPAI is proposing a schedule for UIC MIT testing patterned after the AOGCC required program used for testing the Safety Valve System (SVS). In that program each pad is assigned to two specific months of the year for testing. To prevent schedule creep over time, there is some flexibility to perform the tests anytime during the assigned month. The pads are scheduled to roughly balance the workload from one month to the next. For 4-year UIC MIT testing, CPAI is proposing that each pad be assigned a specific month to be tested every four years. The number of pads and wells will be divided over the four year period so that roughly one-fourth of the required MITs will be performed each year. The specified month will be the due date, rather than the specific day of the prior test, to eliminate schedule creep over time. To implement this schedule Mr. Tom Maunder Page 2 of 2 02/13/06 CPAI will accelerate testing on a number of wells over the next few years. The proposed schedule and pad/month assignments are attached. There are a number of benefits to this proposal': • Each well will be tested close to the previous 4-year test if a small allowance is approved to prevent schedule creep. This should meet the "every 4-year" test frequency requirement in the UIC regulations. • All the injection wells on a given pad will be addressed during the same testing operation, regardless of when the last test was performed on a particular well. This will keep all the wells on the same schedule, results in efficiencies in time and reduces fluid handling risk. • Eliminates requests to "reset" the 4-year clock when tests are performed during the year, eliminating significant record keeping efforts. • The proposed months are in the May through August time period that meets the CPAI goal of testing during warmer weather. The AOGCC is specifically being requested in this proposal to approve the "due month" concept of this plan rather than the "exact due date" specified in the letter dated December 29, 2005. In addition, the proposal applies only to CPAI wells on the standard 4-year test frequency. Wells with specific approvals or variances on 2-year test cycles will continue to be tested on or before the exact 2-year anniversary date. Approval of this request at your earliest convenience is appreciated. Please call MJ Loveland, Marie McConnell, or me at 659-7224 if you have any questions. Sincerely, Jerry Dethlefs Problem Well Supervisor Attachment • • AIASKA / FRANK H. MURKOWSKI, GOVERNOR A14A KA OIL AND 9S / 333 W_ 7' AVENUE, SUITE 100 CONSERVATION COM USSION � ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 FAX (907) 276.7542 Mr. Jerry Dethlefs Problem Well Supervisor ConocoPhilhps Alaska, Inc. P.O. Box 100360 Anchorage, AK 99510-0360 RE: North Slope MIT Schedule Dear Mr. Dethlefs. On February 13, 2006 ConocoPhillips Alaska, Inc ("CPAI") requested approval to modify the schedule for demonstrating mechanical. integrity on their North Slope injection wells so as to allow the majority of the wells to be tested on a rotating schedule during the summer months. The requested schedule modification will allow for greater operating efficiency and will reduce risks to personnel and the environment. The Commission hereby APPROVES the requested modification. In order to allow opportunity for AOGCC Inspectors to witness the testing, CPAI is requested to provide the planned schedule for Summer 2006 as soon as practical. If you have any questions, please contact Jim Regg at 793-1236. As provided in AS 31.05.080(a), within 20 days after written notice of this decision, or such further time as the Commission grants for good cause shown, a person affected by it may file with the Commission an application for reconsideration. A request for reconsideration is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. A person may not appeal a Commission decision to Superior Court unless reconsideration j4 been requested. Alaska and dated March 0, 2006 o an Dan T. Seamount, Jr. iairm Commissioner Cathy Y. Foerster Commissioner ConocoPhillips Alaska, Inc. Permanent UIC MIT Test Schedule Initial 4-year Cycle: Requires accelerating tests for all wells on a pad to be on same cycle Year 1: 2006 Total Wells Kuparuk Pads Alpine Pads Total Wells May 22 1C June 56 1B & WSW, 1E, 3H, 30 July 54 1 D, 1 Q, 1Y, 3F* August 48 1A*, 1R*, 2K*, 2L, 2N, 2P, 2U, 2W*, 2Z*, 3G*, 3S CD2 29 Total 180 Year 2: 2007 May 21 1R, 2W June 53 2K, 2T, 2X, 36, 3F July 28 1A, 1G, 31 August 25 1F*, 2D*, 2F*, 2G*, 2H*, 2M*, 3G, 3M*, 2Z Total 127 Year 3: 2008 May 23 2A, 2B, 2G, 2H June 38 1 F, 1 L, 2M, 2V CD1* 2 July 30 2E, 2F, 3J, 3M August 24 3N, 3Q, 3R Total 115 Year 4: 2009 May 14 1 J*, 3K June 39 1B & WSW, 2T, 3H, 30 CD1 22 July 19 1Q, 1Y CD4* 15 August 35 1 H, 2C, 2D, 3A, 3C Total 144 Year 5 , Feb CD3 8 - -- -----.--- -. - - ----- - - - -- May ------ --- 37 ------------ ------ - - ----- 1C, 1J - -- June I _ 31 1 E CD2 29 __...__ ___.__. _ _ ............._____.. July ; 34 1 D . August i 32 2L, 2N, 2P, 2U, 2Z, 3S - . Total .......... ------- .____ _ Year 6 __ ..__ _ _ May 21- 1 R, 2W June--j----- - 38--- --- -- - - - -- 2K 2X, 3B, 3F CD4 -- - - July 18 1A, 1G, 31 - - ---- -- j _ _.__ ---- -- - --- - - -- - -- - August 18 3G,2Z Total.._.._._ .:........ 95._..__ __........ ......_._--------- ..---- ------- Year.�..._..__�_ ..._ _._,......_.._ ..._....._ ...__... __...... ........ _ May j 23 2A 2B, 2G, 2H -._. _....__. ..__.. __ .;.. ___J1F, une_38 1 F, 1 L, 2M, 2V ----- ---- --- - - --- ---- -- _.. _. ------- _ _ _ . - - -- -- - - - ----..------------ July---- J.-_ 30. _.- - 2E 2F, 3J, 3M _........ ._.. _._ _ _ _._._ August j 24 3N 30, 3R Total 115 Year _ - May 14 3K -- --- -- - - - - - --- --._ -- June ' 40 - 16 &WSW, 2T, 3H, 30 CD1 24 July 27 1 Q,1Y August 35 1H, 2C 2D, 3A 3C Total 116 Notes: 1) * Denotes pads to be accelerated prior to due -date for combining all wells on a pad to same test date 2) New pads will be added to the schedule as they are brought in service; load leveling may be required Revised 08-16-06 *11 • • r RECEIVED ConocoPhillips NOV 0 6 2012 Alaska AOGCC P.O. BOX 100360 ANCHORAGE, ALASKA 99510 -0360 November 4, 2012 Commissioner Dan Seamount Alaska Oil & Gas Conservation Commission 333 West 7 Avenue, Suite 100 Anchorage, AK 99501 Dear Commissioner Seamount: ConocoPhillips Alaska, Inc. presents the attached proposal per AIO 16, Rule 10, to apply for Administrative Approval allowing well 2L -319 (PTD 207 -112) to be online in water only injection service. Currently, the well displays TxIA communication only when injecting MI. ConocoPhillips intends to pursue repairs should MI injection be desired in the future. If a successful repair is achieved we will request the well be returned to normal status and resume ability to inject MI. If you need additional information, please contact myself or Brent Rogers at 659 -7224, or MJ Loveland / Martin Walters at 659 -7043. Sincerely, i / -41111111111. Kelly Lyo Problem Wells Supervisor ConocoPhillips Alaska Inc. Cc: Working Well File, Legal Well File • i ConocoPhillips Alaska, Inc. Kuparuk Well 2L -319 (PTD# 207 -112) Technical Justification for Administrative Relief Request Purpose ConocoPhillips Alaska, Inc. proposes that the AOGCC approve this Administrative Relief request as per Area Injection Order 16, Rule 10, to continue water only injection for Tarn injection well 2L -319. The well displays annular communication only when the well is on MI injection. Well History and Status Kuparuk River Unit well 2L -319 (PTD 198 -240) was drilled and completed in November 2007 as a development well and converted to a WAG MI well in January 2010. 2L -319 was initially reported to the Commission on September 23, 2012, as showing signs of TxIA communication after being on continual MI injection for more than a year, since May 2011. The IA would slowly repressurize over several days after pressure bleed events. On September 24, 2012, AOGCC granted permission for a 30 day water only injection test in order to confirm that the communication was only evident when on MI injection service. The well did not show any signs of TxIA communication while on water injection from September 28, 2012 - October 27, 2012. Tubing packoff tests (positive and negative) passed, indicating that the communication may be via a small downhole thread leak. The well passed a diagnostic MITIA to 3000 psi on October 4, 2012. An additional State witnessed MITIA can be scheduled after AA approval if required. ConocoPhillips intends to pursue repairs if the leak worsens enough to be detectable and located while on water injection. However, until the leak is detectable both on gas and water injection, ConocoPhillips requests an AA which will allow the well to remain online in water only injection service. The IA pressure will be maintained below 2000 psi. Barrier and Hazard Evaluation With only water injection, this well has all the barriers of a normal injection well Tubing: The 3 -1/2" 9.2# L -80 tubing has integrity to the Baker 80 -40 casing seal assembly @ 12,143' MD (5225' TVD), based on passing normal operating injection differential and a passing diagnostic MITIA to 3000 psi completed 10/04/12. Production casing: The 7" 26# L -80 production casing has integrity to the Baker 80 -40 casing seal assembly @ 12,143' MD (5225' TVD) based on the passing MITIA test outlined above as well as the differential operating pressure between the tubing and casing. Surface casing: The well is completed with 9 -5/8" 40# L -80 surface casing with an internal yield pressure rating of 5750 psi. The surface casing is set at 4295' MD (2386' TVD) and the cement shoe was left open after being drilled out. Primary barrier: The primary barrier to prevent a release from the well and provide zonal isolation is the tubing and packer. Second barrier: The production casing is the secondary barrier should the tubing fail. Well Integrity Supervisor 11/4/2012 • • Monitoring: Each well is monitored daily for wellhead pressure changes. Should leaks develop in the tubing or production casing above the surface casing shoe it will be noted during the daily monitoring process. Any pressure trends that indicate annular communication require investigation, Commission notification, and corrective action, up to and including a shut -in of the well. T /IO plots are compiled, reviewed, and submitted to the AOGCC for review on a monthly basis. Proposed Operating and Monitoring Plan 1. Well will be used for water only injection (no MI or gas injection allowed); 2. Perform a passing MITIA every 2 years to the maximum anticipated pressure; 3. Allow operating IA pressure up to 2000 psi, operating OA pressure up to 1000 psi; 4. Submit monthly reports of daily tubing & IA pressures, injection volumes and pressure bleeds for all annuli; 5. Shut -in the well should MIT's or injection rates and pressures indicate further problems with appropriate notification to the AOGCC. Well Integrity Supervisor 11/4/2012 2 KUP • 2L -319 ConocoPhtlUps 0. Well Attributes Max Angle & MD TD Alaska, ( Wellbore API /UWI Field Name Well Status Inc' ( °) MD (ftKB) Act Btm (RKB) cnnaoFtalipa 501032055200 TARN PARTICIPATING AREA INJ 73.42 2,913.12 13,010.0 ° Comment H2S (ppm) Date Annotation End Date KB (ft) Rig Release Date „'„ SSSV: NIPPLE Last WO: 35.63 11/2/2007 Well Gon89: - 2L -319 7/182012 9 45:21 AM Schematic - Actual Annotation Depth (RKB) End Date Annotation Last Mod ... End Date Last Tag: SLM 12,487.0 5/28/2011 Rev Reason: WELL REVIEW osborl 7/18/2012 Casing Strings _ _ Casing Description String 0... String ID ... Top (RKB) Set Depth (1... Set Depth (TVD) ... String Wt... String ... String Top Thrd HANGER, 26 µ .< CONDUCTOR 16 15.250 300 110.0 110.0 65.00 H - WELDED Casing Description String 0... String ID ... Top (RKB) Set Depth (1... Set Depth (TVD) ... String Wt... String ... String Top Thrd SURFACE 95/8 8.835 30.0 4,294.8 2,385.8 40.00 L BTC • Cuing Description String 0... String ID ... Top (RIM) Set Depth (L.. Set Depth (TVD) ... String Wt.. String ... String Top Thrd PRODUCTION 7 6.276 28.6 12,963.2 5,852.3 26.00 L -80 BTCM 7 "x4.5" @ 12130' Tubing Strings , il i Tubing Description String 0... String ID ... Top (RKB) Set Depth (1... Set Depth (TVD) .. String Wt... String .. String lop Thrd TUBING 3 1/2 2.992 26.3 12,143.4 5,225.8 9.20 L-80 EUE 8rd Mod Completion Details T-----7 (TVD) Depth (TVD) Top Inc! Nom'... Top (RKB) (RKB) ( °) Item Description Comment ID (in) 26.3 26.3 - 0.01 HANGER FMC HANGER 3.500 CONDUCTOR, 30-110 510.4 510.3 2.30 NIPPLE CAMCO "DS" NIPPLE w/ 2.875" Profile 2.875 NIPPLE. 510 1 _ 12,000.0 5,127.5 47.75 SLEEVE BAKER CMU SLIDING SLEEVE w/2.813" DS Profile 2.812 op 12,072.8 5,176.3 46.31 NIPPLE CAMCO 'D' NIPPLE w/ 2.75" No Profile 2.750 12,141.9 5,224.8 44.95 LOCATOR BAKER LOCATOR SUB (7 above Top PBR @ 12145' DrID) 3.000 12,142.7 5,225.3 44.93 SEAL ASSY BAKER 80-40 GBH -22 SEAL ASSEMBLY w/ 16' Stroke wBaker Locator 3.000 Sub 2' above No GO CHEM LINE, 26 Other In Hole (Wireline retrievable plugs, valves, pumps, fish, etc.) Top Depth (TVD) Top Inc! SURFACE. Top (MB) (RKB) (°) Description Comment Run Date ID (In) 30 - 4,295 26.3 26.3 - 0.01 CHEM LINE .375" Encapsulated line run from CIM to Surface. Used 5 11/1/2007 (1/2) cannon clamps and 123 full clamps. 12,190.0 5,260.2 45.31 FISH Remnant of Rubber wiper plug and cmt left after cementing. 10/27/2007 0.010 GAS LIFT, Unable to C/O when running completion. IIIII 4,]3] Perforations & Slots ® Shot Top (TVD) Btm ( TVD) Dens Top (RKB) Btm (RKB) (ftKB) (RKB) Zone Date (sh.- Type Comment 12,480.0 12,500.0 5,473.5 5,488.6 T -2, 2L -319 12/31/2007 6.0 IPERF HYPERJET PERFS CHEMICAL. _ Notes: General & Safety 7.416 End Date Annotation 7/20/2008 NOTE: VIEW SCHEMATIC w/9.0 GAS LIFT. 8,184 MI 099 LIFT, 10,962 M GAS LIFT. f 11,918 SLEEVE, , , ' 12,000 NIPPLE, 12,073 - _ �1ffti LOCATOR, MI 1 SEAL ASSY. ° , 12.143 . Mandrel Details Top Depth Top Port (TVD) Inc! OD Valve Latch Size TRO Run Stn Top (RKB) (RKB) (1 Make Model (In) Sery Type Type (ie) ( Run Date Com... 1 4,737.1 2,543.3 69.52 CAMCO KBMG 1 GAS LIFT DMY BK -5 0.000 0.0 11/1/2007 1 2 7,415.8 3,448.4 70.81 CAMCO KBMG- 1 CHEM DMY BK -5 0.000 0.0 11/1/2007 Chem da LTS -CIV INJ IPERF, -- - VLV 12,480- 12,500 FISH, 12,190 - -- 3 8,184.0 3,698.0 69.80 CAMCO KBMG 1 GAS LIFT DMY BK -5 0.000 0.0 11/12007 - 4 10,962.0 4,631.3 70.90 CAMCO KBMG 1 GAS LIFT DMY BK -5 0.000 0.0 11/1/2007 5 11,918.2 5,072.2 49.35 CAMCO KBMG 1 GAS LIFT DMY BK 0.000 0.0 11/29/2009 PRODUCTION 7'x4.5 12130', 29- 12.963 TD, 13.010 Well Name I 2L -319 Notes: TxIA communication while on MI 8 Start Date .6 2012 Days 90 End Date 11.4:2012 Annular Communication Surveillance 3000 - — 150 WHP OAP — 145 2500 WHT —140 2000 1 — — 135 • I T 'Pr —130 1500 CI- 125 — 120 1000 — 115 500 — 105 0 • ' 1 - 100 Aug -12 Sep -12 Oct -12 2544 - DG 2444 ryl {al O. 1500 Pt�fl SWI �aaa �BLPD s ' 500 Aug -12 Sep -12 Oct -12 Date r - • • STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION Mechanical Integrity Test Submit to: jim. reagealaska. gmdoa. aoacc.prudhoe.bavCa)alaska.aov; phoebe.brooks alaska.00v; puv.schwartsaalaska.gov OPERATOR: ConocoPhillips Alaska, Inc FIELD / UNIT / PAD: Kuparuk / KRU / 2L pad DATE: 10/04/12 OPERATOR REP: Phillips / Manjarrez AOGCC REP: N/A Packer Depth Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. Well 2L -319 Type It W TVD 5,225 Tubing 1100 1100 1100 1100 Interval 0 P.T.D. 2071120 Type test P Test psi 1500 Casing 686 3,000 2,960 2,948 P/F P Notes: Diagnostic MITIA OA 497 624 606 606 Well Type Inj. TVD Tubing Interval P.T.D. Type test Test psi Casing P/F Notes: OA Well Type Inj. TVD Tubing Interval P.T.D. Type test Test psi Casing P/F Notes: OA Well Type Inj. TVD Tubing Interval P.T.D. Type test Test psi Casing P/F Notes: OA Well Type Inj. TVD Tubing Interval P.T.D. Type test Test psi Casing P/F Notes: OA TYPE INJ Codes TYPE TEST Codes INTERVAL Codes D = Drilling Waste M = Annulus Monitoring I = Initial Test G = Gas P = Standard Pressure Test 4 = Four Year Cycle I = Industrial Wastewater R = Intemal Radioactive Tracer Survey V = Required by Variance N = Not Injecting A = Temperature Anomaly Survey T = Test during Workover W = Water D = Differential Temperature Test 0 = Other (describe in notes) Form 10-426 (Revised 06/2010) MIT KRU 2L - 319 10 - 12.xls • • Wallace, Chris D (DOA) From: NSK Problem Well Supv [n1617 @conocophillips.com] Sent: Monday, September 24, 2012 8:15 PM To: Wallace, Chris D (DOA) Subject: RE: 2L -319 (PTD 207 -112) report of suspected TxIA communication while on gas injection 09 -23 -12 Thanks Chris, WAGing to water process began today and should be completed tomorrow. Yes this well has been on MI injection for a while. However, I also see in our records that we sent in a 10-404 for sealant pumped into the conductor in May of this year. We will keep you updated with the progress on the well. Thanks again Brent Rogers / Kelly Lyons Problem Wells Supervisor ConocoPhillips Alaska, Inc Desk Phone (907) 659 -7224 Pager (907) 659 -7000 pgr 909 From: Wallace, Chris D (DOA) [ mailto :chris.wallace ©alaska.gov] Sent: Monday, September 24, 2012 4:30 PM To: NSK Problem Well Supv Subject: [EXTERNAL]RE: 2L -319 (PTD 207 -112) report of suspected TxIA communication while on gas injection 09 -23- 12 Thank you for the notice. How long before the well can be placed back to water? Our expectation is within 2 days. I see a passing Water MITIA of 8/8/2010 in our files and nothing since going to MI in Jan 2011. Is this correct or are we missing data? We agree to water only injection for 30 days for further diagnostics. If diagnostics continue to indicate Tubing x IA comm. Or if fails a MIT -IA on water, notify us and proceed with application for an Admin Approval if further water only injection is your intent. Please send a separate well status update at the end of the diagnostic period to update your findings. This would either be accompanying the AA request or your notice to shut in the well. Adding to the monthly TIO report is a good reminder for us all, but my intent will be to have this well separately reported and closely monitored, and have paperwork processed in a timely manner to ensure the well can be in compliance at all times without any undue disruptions in injection. Thanks and Regards, 1 Chris Wallace • • Sr. Petroleum Engineer Alaska Oil and Gas Conservation Commission 333 West 7 Avenue Anchorage, AK 99501 (907) 793 -1250 (phone) (907) 276 -7542 (fax) chris.wallace@alaska.gov From: NSK Problem Well Supv [ mailto :n1617@conocophillips.com] Sent: Sunday, September 23, 2012 8:07 PM To: Wallace, Chris D (DOA) Subject: 2L -319 (PTD 207 -112) report of suspected TxIA communication while on gas injection 09 -23 -12 Chris, Tam WAG injector 2L -319 (PTD 207 -112) is suspected of TxIA communication while on gas injection based on a failed IA DDT over the weekend. T -POTs (positive and negative) passed. We will be wagging the well over to water as soon as possible. ConocoPhillips requests that the well be allowed to remain on water injection to allow for further diagnostics (to include an MITIA to be conducted as soon as possible). Pending a passing MITIA, we would then want to monitor the well for an extended period of time (30 days) while on water injection to look for any continued TxIA communication. It will be added to the monthly report and appropriate paperwork submitted. Attached is the schematic and 90 day TIO plot. 2 • Well Name 21 -319 Notes: Start Date 6,2512012 Days 90 End Date 9 :212012 Annular Communication Surveillance 4000 - ..._.___ ._..__...__.___._..___.._ _� ____.__.._�_____..____..._ �_e__.________� _ _. ___._____ 150 k 3500 — _ WHP — 145 lAP - 140 OAP 3000 — lft -135 2500 \ - 130 V • 2000 f 125 - 120 1500 - 115 1000 - 110 500 - 105 0 100 Jun -12 Jul -12 Aug -12 Sep -12 6004 5040 •• DGl '.. MG! 6. 4440 di 300 u �BLPD : x000 7 ■ 1000 •_ Jun -12 Jul -12 Aug -12 Sep -12 Date Brent Rogers / Kelly Lyons Problem Wells Supervisor ConocoPhillips Alaska, Inc Desk Phone (907) 659 -7224 Pager (907) 659 -7000 pgr 909 3 r . a KUP 2L 319 ri- Con coPhilli} 5 `" " - Max Angle & MD I ' a AfasEa I nc, Wellbore APOUWI R eid Name Well Status Ind I) MD (ftKB) Act Btm (RKB) ,.......„„i„,,,, k 501032055200 TARN PARTICIPATING AREA INJ 73.42 2,913.12 13,010.0 2o7 11 2 O Comment 1128 (ppm) Date Annotation End Date KB-Ord (R) Rig Release Date •,. Sot coma' • 2L-31s, 7/1&2012 s4szt AM SSSV: NIPPLE Last WO: 35.63 11/2/2007 Schenato -A apl Annotation Depth (MEI) End Date Annotation Last Mod ... E nd Date Last Tag: SLM 12,487.0 5/28/2011 Rev Reason: WELL REVIEW osborl 7/18/2012 Casing `Strings_ ;' ;u, ; _. _. Description - _... g SMng 0... String ID ... Top (ftK8) Set Depth (f... Set Depth (ND) ... String Wt... String ... String T Casing Thrd HANGER, 26 u s, ; CONDUCTOR 16 15.250 30.0 110.0 110.0 65.00 11 WELDED • ID _. Top ` Casing Description String 0... String . Top (ftKB) Set Depth (T... Set Depth (WO)... String Wt.. String ... String Top Thrd t � S URFACE 95/8 8835 30.0 4,294.8 2,385.8 40.00 L-80 BTC Casing Description String 0... St ing ID . Top (ORB) Set Depth (f ... Set Depth (TVD) ... String WI... String ... String Top Thrd PRODUCTION 7 6276 28.6 12,963.2 5,852.3 26.00 L-80 BTCM , e a., 7 "x4.5" @ 12130' Tubing Strings li Tubing Description 'String O. String g ID Top ((MB) 'Set Depth (7... Set Depth (NO) Ttnng Wt... St Ing String Top Thrd TUBING 31/2 2.992 26.3 12,143.4 5,225.8 i 9.20 1 L-80 I EUE 8rd Mod -. .,, „.,, Completion Details , t Top Depth W. W - (ND) Top Intl Nomi... T op (RKB) MB) l"I item Description _ Comment to (in) a . • 26.3 26.3 -0.01 HANGER FMC HANGER 3.500 CONDUCTOR, 30 510.4 510.3 2.30 NIPPLE CAMCO "DS" NIPPLE w/ 2.875" Profile 2.875 NIPPLE 610 12,000.0 5,127.5 47.75 SLEEVE BAKER CMU SLIDING SLEEVE w/2.813" DS Profile 2.812 12,072.8 5,176.3 46.31 NIPPLE CAMCO 'D' NIPPLE w/ 2.75" No-Go Profile 2.750 12,141.9 5,224.8 44.95 LOCATOR BAKER LOCATOR SUB (2' above Top PBR @ 12145' DAD) 3.000 12,142.7 5,225.3 44.93 SEAL ASSY BAKER 80-40 GBH -22 SEAL ASSEMBLY w/ 16' Stroke w/Baker Locator 3.000 CHEM LINE, 26 Sub 2' above No GO +d . t` „ < _r _ =t-� 1s r -tea rum nests . �... «'. .T � ,,`X ` +. Top Dept (ND) Top Incl SURFACE, Top (IIKB) Pal P) Description Comment Run Date ID (in) 30 - 4,295 26.3 26.3 -0.01 CHEM LINE .375" Encapsulated line run from CIM to Surface. Used 5 11/1/2007 ∎ __ (1/2) cannon damps and 123 full damps. 1. 12,190.0 5,260.2 45.31 FISH Remnant of Rubber wiper plug and ant left after cementing. 10/27/2007 0.010 GAS LIFT. Unable to GO when running completion. 4,797 Perforations 8 Slots fi . , . S I Top (ND) Rim (TVD) Dens Top (MB) Btm (RKB) MB) (RKB) Zone Date Oh- Type Comment 12,480.0 12,500.0 5,473.5 5,488.6 T -2, 2L-319 12/31/2007 6.0 IPERF HYPERJET PERFS CHEMICAL, Notes: General & Safe ,.. ... N 'r'.:a '" ." QR ' _ s a< "µb 7,416 End Date Annohtion a : 7/20/2008 NOTE: VIEW SCHEMATIC w/9.0 GAS LIFT, 6,184 iir lit GAS UFT, lim "... 10,962 O I Vi GAS LIFT, n sls ir t r. SLEEVE, 12000 S. IP NIPPLE, 12073 ' ' ! 1 7 } LOCATOR, 12,142 SEAL ASSY, ..: 12143 i Mandrel Details Top Depth Top Port (TVD) Incl OD Valve Latch Size TRO Run Stn Top (MB) () ( ") Make Model (In) Sere Type Type (in) (psi) Ben Dab Com... 1 4,737.1 2,543.3 69.52 CAMCO KBMG 1 GAS LIFT DMY BK-5 0.000 0.0 11/1/2007 2 7,415.8 3,448.4 70.81 CAMCO KBMG- 1 CHEM DMY BK-5 0.000 0.0 11/1/2007 Chem IPERF LTS-CIV INJ 12460 - 12,500 ' -' VLV FISH, 12190 - - 3 8,184.0 3,698.0 69.80 CAMCO KBMG 1 GAS LIFT DMY BK -5 0.000 0.0 11/1/2007 4 10,962.0 4,631.3 70.90 CAMCO KBMG 1 GAS LIFT DMY BK-5 0.000 0.0 11/1/2007 I 5 11,918.2 5,072.2 49.35 CAMCO KBMG 1 GAS LIFT DMY BK 0.000 0.0 1129/2009 PRODUCTION 7'x4.5" a 121301 29-12963 TD, 13,010 0 V"' 4 t • • Conoco Phillips Alaska P.O. BOX 100360 ANCHORAGE, ALASKA 99510 -0360 December 12, 2011 INL t ' i .'ti Commissioner Dan Seamount Aie tika Alaska Oil & Gas Conservation Commission ` Gas rp s.p ►l js Sion 333 West 7 Avenue, Suite 100 A.rtchcr Anchorage, AK 99501 Dear Commissioner Seamount: ConocoPhillips Alaska, Inc. presents the attached proposal per AIO 16, Rule 10, to apply for Administrative Approval allowing well 2L -305 (PTD 198 -240) to be online in water only injection service. Currently, the well displays TxIA communication only when injecting MI. ConocoPhillips intends to pursue repairs should MI injection be desired in the future. If a successful repair is achieved we will request the well be returned to normal status and resume ability to inject MI. If you need additional information, please contact myself or Brent Rogers at 659 -7224, or MJ Loveland / Martin Walters at 659 -7043. Sincerely, Kelly Lyons Problem Wells Supervisor ConocoPhillips Alaska Inc. Cc: Working Well File, Legal Well File • ConocoPhillips Alaska, Inc. Kuparuk Well 2L -305 (PTD# 198 -240) Technical Justification for Administrative Relief Request Purpose ConocoPhillips Alaska, Inc. proposes that the AOGCC approve this Administrative Relief request as per Area Injection Order 16, Rule 10, to continue water only injection for Tarn injection well 2L -305. The well displays annular communication only when the well is on MI injection. Well History and Status Kuparuk River Unit well 2L -305 (PTD 198 -240) was drilled and completed in December 1998 as a development well and converted to a WAG MI well in November 2004. 2L -305 was initially reported to the Commission on June 18, 2011, as showing signs of T x IA communication after being on MI injection for several weeks. All pressure diagnostics (a diagnostic MITIA, tubing and inner casing packoff tests and an IA drawdown test) continue to pass integrity testing. However, the IA pressure slowly increases over several hours while on MI injection indicating a very slow TxIA leak to gas. The well has not shown any signs of TxIA communication while on water indicating that the communication is possibly a very small thread leak or a seal leak. There is no recordable leak rate so the exact location of the communication is not detectable. The well passed a diagnostic MITIA to 3500 psi on August 16, 2011. An additional State witnessed MITIA can be scheduled after AA approval if required. ConocoPhillips intends to pursue repairs if the leak worsens enough to be detectable and located on water injection. However, until the leak is detectable both on gas and water injection, ConocoPhillips requests an AA which will allow the well to remain online in water injection service. The IA pressure will be maintained below 2000 psi. Barrier and Hazard Evaluation Tubing: The 3 -1/2" 9.3# L -80 tubing has integrity to the Baker 80 -40 casing seal assembly @ 8367' MD, based on passing normal operating injection differential and a passing diagnostic MITIA to 3500psi completed 8/16/11. Production casing: The 5.5" 15.5# L -80 production casing has integrity to the Baker 80 -40 casing seal assembly @ 8367' MD based on the passing MITIA test outlined above as well as the differential operating pressure between the tubing and casing. Surface casing: The well is completed with 7 -5/8" 29.7# L -80 surface casing with an internal yield pressure rating of 6890 psi. The surface casing is set at 2667' MD (2291' TVD) and the cement shoe was left open after being drilled out. Primary barrier: The primary barrier to prevent a release from the well and provide zonal isolation is the tubing and packer. Second barrier: The production casing is the secondary barrier should the tubing fail. Monitoring: Each well is monitored daily for wellhead pressure changes. Should leaks develop in the tubing or production casing above the surface casing shoe it will be noted during the daily monitoring process. Any pressure trends that indicate annular communication require Well Integrity Supervisor 12/12/2011 • • investigation, Commission notification, and corrective action, up to and including a shut -in of the well. T/IO plots are compiled, reviewed, and submitted to the AOGCC for review on a monthly basis. Proposed Operating and Monitoring Plan 1. Well will be used for water only injection (no MI or gas injection allowed); 2. Perform a passing MITIA every 4 -years as per AOGCC criteria (0.25 x TVD @ packer, 1500 psi minimum) for a normal well; 3. Allow operating IA pressure up to 2000 psi, operating OA pressure up to 1000 psi; 4. Submit monthly reports of daily tubing & IA pressures, injection volumes and pressure bleeds for all annuli; 5. Shut -in the well should MIT's or injection rates and pressures indicate further problems with appropriate notification to the AOGCC. Well Integrity Supervisor 12/12/2011 2 a p � KU P 2L -305 ConocoPhillips " !L..4 Well Attributes • Max Angle & MD TD J Wellbore APUUWI Field Name Well Status Inc! (°) MD (MB) Act Btm (RKB) Alaska Inc' '$ 501032027900 TARN PARTICIPATING AREA INJ 65.77 4,469.95 9,210.0 Comment H25 (ppm) Date Annotation End Date KB-Ord (R) Rig Release Date ... Well Con69t - 2L305, 5257N11 9 SSSV: NIPPLE Last WO: MKS) _ 37.50 _ 12/6/1998 Schemes - Actual Annotation Depth 8) Entl Date Annotation Last Mod ... End Date Last Tag: SLM 8,608.0 J 2/13/2011 Rev Reason: TAG ninam 5/25/2011 - Casing Strings RANGER, 23 = x , ' Casing Description String 0... String ID ... Top (ftKB) Set Depth (f... Set Depth (TVD) ... String Wt... String ... String Top Thrd CONDUCTOR 16 15.062 29.0 108.0 108.0 62.58 H-40 WELDED Casing Description String 0... String ID ... Top (ftKB) Set Depth (f... Set Depth (TVD)... String Wt... String ... String Top Thrd SURFACE 75/8 6.750 28.5 2,667.2 2,291.1 45.50 L-80 BTC -MOD icl 1 1 Casing Detion String 0... String ID ... Top (MB) Set Depth (f... Set Depth (TVD) ... String Wt... String ... String Top Thrd PRODUC 51/2 4.950 26.3 9,199.6 5,656.6 15.50 L-80 LTC MOD 5.5 "x3.5" Tubing Strings Tubing Description tring 0... String ID ... Top (RKB) Set Depth (f. Set Depth (TVD) . Str W Strng Sop TUBING is 3 1/2 2 I 23 I 8,384.1 I 5 9 ing t. 1 L i -80 ... tring I EU Thrtl Completion Details' I .- Top VD) Depth CONDUCTOR, (T Top loci Noml... 29 -108 Top (RK8) (RKB) ( °) Item Deacriptlon C omment ID (in) _ 23.4 23 .4 -0.30 HANGER FMC GEN V TUBING HANGER 3.500 NIPPLE, 512 1r 511.7 511.7 0.66 NIPPLE CAMCO 'DS' NIPPLE 2.875 Imo. 8,257.0 5,186.5 58.53 SLEEVE BAKER CMU SLIDING SLEEVE w 2.813 CAMCO PROFILE (CLOSED 2.813 8/30/2000) 8,359.2 5,239.5 58.56 NIPPLE CAMCO'D' NIPPLER 2.750 8,366.3 5,243.2 58.58 LOCATOR BAKER LOCATOR 2.985 8,367.1 5,243.6 58.58 SEAL ASSY BAKER SEAL ASSEMBLY 2.985 Other In Hole (Wireline retrievable plugs, valves, pumps, fish, etc.) Top Depth (TVD) Top Inc! SURFACE, 4 di, Top (ftKB) (RIO) (1 Description Comment Run Date ID (In) 29-2,667 9,000 5,563.1 61.33 FISH FISH 1.85" ROLLER WHEEL LOST IN RATHOLE 6/4/2001 '6/4/2001 1 Perforations & Slots Shot GAS LIFT, Top (TVD) 9tm (TVD) Dens 5,284 Top (MB) 81m (RKB) (RKB) (RKB) Zone Date Oh- Type , 8,526 8,534 5,325.9 5,330.0 S-8, 2L- 305 6/7/2005 6.0 APERF 2.5 "HSD PJ/2506 PJ,60deg ph 8,548 8,556 5,337.2 5,341.3 S -7, 2L-305 6/7/2005 6.0 APERF 2.5 "HSD P1/2506 PJ, 60deg ph 8,586 8,604 5,356.7 5,365.8 S -5, S -3, 2L- 305 6(7/2005 6.0 APERF 2.5 "HSD PJ /2506 PJ,60deg ph SLEEVE, 8,257 8,648 8,688 5,388.1 5,408.4 T -2, 2L -305 12/22/1998 6.0 IPERF 2.5" HC, BH,60 DEG PH 1 N 8,690 8,700 5,409.4 5,414.5 T -2, 2L-305 6/7/2005 6.0 APERF 2.5 "HSD PJ/2506 PJ,60deg ph 8,712 8,722 5,419.8 5,425.0 T -1.5, 2L-305 6/7/2005 6.0 APERF 2.5 "HSD PJ/2506 PJ,60deg ph OAS LIFT, Notes: General & Safety 8,307 End Date Annotation 111 6/15/2009 NOTE: VIEW SCHEMATIC w /Alaska Schemafc9.0 1 ii NIPPLE, 8,359 11 1 LOCATOR, 8,366 ''1 SEAL ASSY, 8,367 APERF, II 8,528.8,534 PERF, 8, 548$ A 558 III APERF, LE 8,5868,604 PERF, 8,64 &8,688 Mandrel Details' APERF, Top Depth Top Porn 8.6908.700 ■ (TVD) Intl OD Valve Latch Site TRO Run Stn Top (ftKB) IRKS) (°) Make Model (in) Sery Type Type (in) (psi) Run Date Corn... II 1 5,283.5 3,535.7 57.91 CAMCO KBG -2 -9 1 GAS LIFT DMY - INT 0.000 0.0 12/6/1998 APERF, 8,712.8,722 2 8,307.0 5,212.6 58.70 CAMCO KBG -2 -9 1 GAS LIFT DMY INT 0.000 0.0 11/13/2004 FISH, 9,000 PRODUCTION 5.5'x3.5', 28 -9,200 .. T0, 9,210 • • • STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION Mechanical Integrity Test Email to:jim.regg @alaska.gov; phoebe.brooks @alaska.gov; tom.maunder @alaska.gov; doa .aogcc.prudhoe.bay @alaska.gov OPERATOR: ConocoPhillips Alaska Inc. FIELD / UNIT / PAD: Kuparuk / KRU / 2L DATE: 08/16/11 OPERATOR REP: Colee / Phillips AOGCC REP: No state representative present Packer Depth Pretest Initial 15 Min. 30 Min. I Well 2L -305 Type Inj. N TVD 5,244' Tubing 2,300 2,350 2,350 2,350 Interval 0 P.T.D. 1982400 Type test P Test psi 1500 Casing 1,925 3,500 3,440 3,440 P/F P Notes: Ann comm evaluation 1.25bbls diesel OA 250 300 300 300 Well Type Inj. TVD Tubing Interval P.T.D. Type test Test psi Casing P/F Notes: OA Well Type Inj. TVD Tubing Interval P.T.D. Type test Test psi Casing P/F Notes: OA Well Type Inj. TVD Tubing Interval P.T.D. Type test Test psi Casing P/F Notes: OA Well Type Inj. TVD Tubing Interval P.T.D. _ Type test Test psi Casing P/F Notes: OA TYPE INJ Codes TYPE TEST Codes INTERVAL Codes D = Drilling Waste M = Annulus Monitoring I = Initial Test G = Gas P = Standard Pressure Test 4 = Four Year Cycle I = Industrial Wastewater R = Internal Radioactive Tracer Survey V = Required by Variance N = Not Injecting A = Temperature Anomaly Survey T = Test during Workover W = Water D = Differential Temperature Test 0 = Other (describe in notes) MIT Report Form BFL 11/27/07 MIT KRU 2L -305 08- 16- 11.xls 9 ~I ConocoPhillips P.O. BOX 100360 ANCHORAGE, ALASKA 99510-0360 January 24, 2010 Mr. Dan Seamount Alaska Oil & Gas Commission 333 West 7~' Avenue, Suite 100 Anchorage, AK 99501 Dear Mr. Seamount: RECEIVED JAN 2 6 2a10 Al~tk~ Oil ~ 8ti COna. CommissiAn AnchAra~ ConocoPhillips Alaska, Inc. presents the attached proposal per AIO 2B, Rule 9, to apply for Administrative Approval allowing we112N-325 (PTD 198-163) to be online in water only injection service with a known surface casing leak. ConocoPhillips intends to pursue repairs should MI injection be desired in the future. If a successful repair is achieved we will request the well be returned to normal status and resume the ability to inject MI. If you need additional information, please contact myself or Martin Walters at 659-7224, or MJ Loveland / Perry Klein at 659-7043. Sincerely, Brent Rogers Problem Wells Supervisor ConocoPhillips Alaska Inc. Attachments C~ ConocoPhillips Alaska, Inc. • Kuparuk We112N-325 (PTD# 198-163) Technical Justification for Administrative Relief Request Purpose ConocoPhillips Alaska, Inc. proposes that the AOGCC approve this Administrative Relief request as per Area Injection Order 2B, Rule 9, to continue water only injection with a known surface casing leak for Kuparuk injection we112N-325. Well History and Status Kuparuk River Unit we112N-325 (PTD# 198-163) was drilled and completed in September 1998 as a service well. 2N-325 was reported to the Commission on 12/24/09 with a suspected surface casing leak discovered while the operator was performing their daily well walk. Additional diagnostics were conducted which determined the surface casing to formation leak , with a minor leak to atmosphere via the conductor, to be estimated at 120' (conductor shoe is at 108'). A passing MITIA was conducted on 12/30/09. Considering that the leak is too deep to access via excavation, the well will require a workover or an alternate repair technology to remediate. ConocoPhillips requests an AA to continue water only injection until the well can be repaired. Barrier and Hazard Evaluation Tubing: The 3-1/2" 9.3# L-80 tubing has integrity to the Baker 80-40 casing seal assembly @ 7396' MD based upon a passing MITIA to 2050 psi on 12/30/09. Production casing: The 5.5" 15.5# L-80 production casing has integrity to the Baker 80-40 casing seal assembly @ 7396' MD (5016' TVD) based upon a passing MITIA to 2050 psi on 12/30/09. The production casing is set at 7397' and has an internal yield rating of 7000 psi. Surface casing: The well is completed with 7-5/8" 29.7# L-80 surface casing in the upper portion of the hole with an internal yield pressure rating of 6890 psi. 'The surface casing is set at 2662' MD (2317' TVD) and the cement shoe was left open after being drilled out. Primary barrier: The primary barrier to prevent a release from the well and provide zonal isolation is the tubing and seal assembly. Second barrier: The production casing is the secondary barrier should the tubing fail. Monitoring: Each well is monitored daily for wellhead pressure changes. Any deviations from approved MAOP annular pressures require investigation and corrective action, up to and including ashut-in of the well. T/IO plots are compiled, reviewed, and submitted to the AOGCC for review on a monthly basis. Well Integrity Supervisor 1/24/2010 Proposed Operating and Monitoring Plan 1. Well will be used for water injection only (no gas or MI allowed). 2. Perform a passing MITIA every 2 years as per AOGCC criteria (0.25 x tvd @ packer, 1500 psi minimum). 3. IA pressure not to exceed 2000 psi (29% internal yield). 4. OA pressure will be maintained as low as reasonably possible. 5. Submit monthly reports of daily tubing & IA pressures, injection volumes, and any pressure bleeds on any annuli. 6. Shut-in the well should MIT's or injection rates and pressures indicate further problems with appropriate notification to the AOGCC. 7. Workover and/or repair the well prior to gas injection consideration with appropriate AOGCC notification Well Integrity Supervisor 1/24/2010 2 • Email to:jim.regg@alaska.gov; phoebe.brooks@alaska.gov; tom.maunder@alaska.gov; doa.aogcc.prudhoe.bay@alaska.gov OPERATOR: ConocoPhillips Alaska Inc. FIELD /UNIT /PAD: Kuparuk /KRU / 2N DATE: 12/30/09 OPERATOR REP: Ives !Hurley - AES AOGCC REP: STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION Mechanical Integrity Test ~~ Packer Depth Pretest Initial 15 Min. 30 Min. Well 2N-325 Type Inj. W TVD 5,016' Tubin 2,700 2,700 2,700 2,700 Interval O P.T.D. 1981630 T pe test P Test psi 1500 Casin 540 2,050 2,010 2,010 P/F P Notes: Diagnostic MITIA OA 0 0 0 0 Well Type Inj. TVD Tubing Interval P.T.D. Type test Test psi Casin P/F Notes: OA Well Type In'. TVD Tubin Interval P.T.D. Type test Test psi Casing P/F Notes: OA Well T pe In'. TVD Tubin Interval P.T.D. Type test Test psi Casin P/F Notes: OA Well T pe Inj. TVD Tubin Interval P.T.D. Type test Test psi Casin P/F Notes: OA TYPEINJ Codes D =Drilling Waste G =Gas I =Industrial Wastewater N =Not Injecting W =Water TYPE TEST Codes M =Annulus Monitoring P =Standard Pressure Test R =Internal Radioactive Tracer Survey A =Temperature Anomaly Survey D =Differential Temperature Test INTERVAL Codes I =Initial Test 4 =Four Year Cycle V =Required by Variance T =Test during Workover O =Other (describe in notes) MIT Report Form BFL 11/27/07 KRU 2N-325 12-30-09.x1s .~ ConocoPhillips AI:3iK.i. II k CONDUCTOR, __~ 35108 NIPPLE, 517 BURFACE, 29-2,662 SLEEVE-C. r ze7 GAS LIFT, 7334 NIPPLE, 7 3t18 LOCATOR, 7395 SEAL ASSY, 7,398 L APERF, 7 ~0 7 708 IPERF, 7,7147,728 IPERF, 7,731-7,750 IPERF, 7,750-7,770 IPERF, 7,77&7,78/ IPERF, 7,7947,802 IPERF, 7,819-7,835 PRODUCTION 5 5'a3 5', 20-8,162 iD, B,1B2 KUP ! 2N-325 Well Attributes Max An le 81 MD TD Wellbo•e APINWI Fleltl Name Well SIaNS 501032026900 TARN PARTICIPATING AREA INJECTING Inc! (°) MD (ftl(B) 57.34 4,097.08 Act Btm (RKB) 8,182.0 Comment H23 Ippm) SSSV: NIPPLE 0 Dale Annotation 1/1/2009 Last WO: End Data NBlird (R) 34.59 Rlg Release Dab 9/18/1998 Annotatlon Last Tag: RKB Depth (RI(B) E 7,962.6 nd Data 6/21/2009 Annotation Rev Reason: TAG, 128' RATHOLE Last Mod By Imostxx End Oate 6Y22Y2009 Casin Strin s Casing Description CONDUCTOR String 0... 16 String ID .. 15.062 . Top (ftNB) 34.6 Bet Depth IL.. S 108.0 et Depth (TVD)... 108.0 String Wt... 62.58 String ... H-40 String Top Thrd Welded Casing Descriptlon SURFACE String 0... 75!8 String ID .. 6.875 . Top (RKB) 29.1 Sel Depth (f... S 2,661.7 at Depth (TVD) ... 2,317.3 Btring Wt... 29.70 String ... L-80 String Top ThrO BTC Casing Descriptlon PRODUCTION 5.5"x3.5" String 0... 5 1/2 String ID .. 4.950 . Top IRKBI 27.5 Set Depth (t... S 8,162.0 at Depth ITVD) ... 5,448.4 String WL.. 15.50 String ... L-SO String Top Thrd LTC MOD Tubin Strin s Tubing Descriptlon String 0... String ID ... Top (RKB) Sat Depth (f... Set Depth ITVD) ... String Wt... Bting ... Btring Top Thrd TUBING 31/2 2.992 25.8 7,412.8 5,025.5 9.30 L-80 EUE9rd Com letion Details Top (ftXB) Top Depth (TVD) (RKB) Top lncl (°) I bm Dascrlptbn Comment ID (In) 25.8 25.8 -1.38 H ANGER FMC GEN V TUBING HANGER 3.500 517.2 517.2 0.23 N IPPLE CAMCO'DS' NIPPLE 2.875 7,286.7 4,952.3 54.45 S LEEVE-C BAKER CMU SLIDING SLEEVE (CLOSED 11126/1998) 2.813 7,387.7 5,010.9 54.61 N IPPLE G\MCO'D' NIPPLE 2.750 7,394.7 5,015.0 54.61 L OG~TOR LOCATOR 2.985 7,396.2 5,015.9 54.60 S EAL ASSY BAKER 80-00 CASING SEAL ASSEMBLY w115' STROKE 2.985 Perforations & Slots Top (RKB) Btm (RKB) Top (TVD) (RKB) Btm (TVD) (RKB) Zone Date Shot Dens ten... Typs Commen! 7,690 7,708 5,186.5 5,196.9 S5, 2N325 6/2011999 6.0 APERF 2.5" HGDP, 60 Deg phasing 7,714 7,728 5,200.3 5,208.4 S-5, 2N325 11124/1998 6.0 IPERF 2.5' HC/DP, 60 Deg phasing 7,734 7,750 5,211.9 5,221.1 S-5, 2N~25 11/2511998 6.0 IPERF 2.5" HGDP, 60 Deg phasirg 7,750 7,770 5,221.1 5,231.8 S-3, 2N~25 11/25!1998 6.0 IPERF 2.5" HGDP, 60 Deg phasing 7,778 7,784 5,236.5 5,240.0 S-3, 2NJ25 11/25/1998 6.0 IPERF 2.5" HGDP, 60 Deg phasing 7,794 7,802 5,245.8 5,250.4 S-3, 2N325 11/25!1998 6.0 IPERF 2.5" HGDP, 60 Deg phasing 7,819 7,835 5,260.2 5,269.3 S-3, 2N325 11/2411998 6.0 IPERF 2.5" HGDP, 60 Deg phasing Notes: General & Safe End Data Annotatlon 6/312009 NOTE: ZONES NOT LOADED TO WELLVIEW YET 6/22/2009 NOTE: VIEW SCHEMATIC w/Alaska Schemafic9.0 Ma ndrel Details Stn Top (RKB) Top Depth (TVD) (RKB) Top Inc! I°) Make Model OD llnl Serv Valve Type Latch Type Port Size Ilnl TRO Run (psi) Run Dab Com... 1 7,334.3 4,980.0 54.52 CAMCO K BG-2-9 1 GAS LIFT DMY INT 0.000 0.0 9/1/1998 #8 ) ) .~ ~ .r-\ '"'~:::J'-"'¡ if \.l.l.J.·.· ~. ¡ " /.1 I,q. ".' '"1 . ,..Ii .~<'~ :' ,':\ "\ :: :¡' F·, . ....,; .~.', " :r:i) iI.: . :. ,.ì .¡ï\. '\..'1. : .,,: \~ 1..,. ii '~J\::oJ l.:::J (-"'['''''''"..:::1 :,1 J.·n.. ì,..1 j'.' ·;1 :\1 : 'I . ::-. :",W U IT\ n ¡i<¡'1:( cd / I '\1[, I \ \\.. ''>'" ! ,J:\ ::1 / ,~\ .""'~ "\ .j,'"'"'\ ';11" i i ¡\ ·,(11 J ::..J 1..:\ 1....'::::1 i-JU '\,..;::,./ IT\ /f'\ '\ )1-1 \ .!FU FRANK H. MURKOW5KI, GOVERNOR AI~ASIiA. OIL AlO) GAS CONSERVATION COMMISSION 333 W. "fTH AVENUE, SUITE 100 ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 FAX (907) 276-7542 September 27, 2004 Proposals to Amend Underground Injection Orders to Incorporate Consistent Language Addressing the Mechanical Integrity of Wells The Alaska Oil and Gas Conservation Commission ("Commission"), on its own motion, proposes to amend the rules addressing mechanical integrity of wells in all existing area injection orders, storage injection orders, enhanced recovery injection orders, and disposal injection orders. There are numerous different versions of wording used for each of the rules that create confusion and inconsistent implementation of well integrity requirements for injection wells when pressure communication or leakage is indicated. In several injection orders, there are no rules addressing requirements for notification and well disposition when a well integrity failure is identified. Wording used for the administrative approval rule in injection orders is similarly inconsistent. The Commission proposes these three rules as replacements in all injection orders: Demonstration of Mechanical Integrity The mechanical integrity of an injection well must be demonstrated before injection begins, at least once every four years thereafter (except at least once every two years in the case of a slurry injection well), and before returning a well to service following a workover affecting mechanical integrity. Unless an alternate means is approved by the Commission, mechanical integrity must be demonstrated by a tubing/casing annulus pressure test using a surface pressure of 1500 psi or 0.25 psi/ft multiplied by the vertical depth of the packer, whichever is greater, that shows stabilizing pressure and does not change more than 10 percent during a 30 minute period. The Commission must be notified at least 24 hours in advance to enable a representative to witness mechanical integrity tests. Well Integrity Failure and Confinement Whenever any pressure communication, leakage or lack of injection zone isolation is indicated by injection rate, operating pressure observation, test, survey, log, or other evidence, the operator shall immediately notify the Commission and submit a plan of corrective action on a Form 10-403 for Commission approval. The operator shall immediately shut in the well if continued operation would be unsafe or would threaten contamination of freshwater, or if so directed by the Commission. A monthly report of daily tubing and casing annuli pressures and injection rates must be provided to the Commission for all injection wells indicating well integrity failure or lack of injection zone isolation. Administrative Actions Unless notice and public hearing is otherwise required, the Commission may administratively waive or amend any rule stated above as long as the change does not promote waste or jeopardize correlative rights, is based on sound engineering and geoscience principles, and will not result in fluid movement outside of the authorized injection zone. The following table identifies the specific rules affected by the rewrite. Injection Order "Demonstration of Mechanical In te gri ty' ~ Affected Rules '"Well Integrity Failure and Confinement" "Administrative Action" Area Ioj ection Orders AIO 1 - Duck Island Unit AIO 2B - Kuparuk River Unit; Kuparuk River, Tabasco, Ugnu, West Sak Fields AIO 3 - Prudhoe Bay Unit; Western Operating Area AIO 4C - Prudhoe Bay Unit; Eastern Operating Area AIO 5 - Trading Bay Unit; McArthur River Field AIO 6 - Granite Point Field; Northern Portion AIO 7 - Middle Ground Shoal; Northern Portion AIO 8 - Middle Ground Shoal; Southern Portion Ala 9 - Middle Ground Shoal; Central Portion Ala 10B - Milne Point Unit; Schrader Blut1: Sag River, Kuparuk River Pools AIO 11 - Granite Point Field; Southern Portion AIO 12 - Trading Bay Field; Southern Portion AIO 13A - Swanson River Unit AIO 14A - Prudhoe Bay Unit; Niakuk Oil Pool AIO 15 - West McArthur 6 7 9 6 7 9 6 7 9 6 7 9 6 6 9 6 7 9 6 7 9 6 7 9 6 7 9 4 5 8 5 6 8 5 6 8 6 7 9 4 5 8 5 6 9 ) ) Affected Rules "Demonstration of "Well Integrity "Administrati ve Injection Order Mechanical Failure and Action" Integrity" Confinement" River Unit AIO 16 - Kuparuk River 6 7 10 Unit; Tarn Oil Pool 6 8 AIO 17 - Badami Unit 5 AIO 18A - Colville River 6 7 11 Unit; Alpine Oil Pool AIO 19 - Duck Island Unit; 5 6 9 Eider Oil Pool AIO 20 - Prudhoe Bay Unit; 5 6 9 Midnight Sun Oil Pool AIO 21 - Kuparuk River 4 No rule 6 Unit; Meltwater Oil Pool AIO 22C - Prudhoe Bay 5 No rule 8 Unit; Aurora Oil Pool 6 9 AIO 23 - Northstar Unit 5 AIO 24 - Prudhoe Bay Unit; 5 No rule 9 Borealis Oil Pool AIO 25 - Prudhoe Bay Unit; 6 8 13 Polaris Oil Pool AIO 26 - Prudhoe Bay Unit; 6 No rule 13 Orion Oil Pool Disposal Injection Orders DID 1 - Kenai Unit; KU No rule No rule No rule WD-l DID 2 - Kenai Unit; KU 14- No rule No rule No rule 4 DID 3 - Beluga River Gas No rule No rule No rule Field; BR \VD-l DID 4 - Beaver Creek Unit; No rule No rule No rule BC-2 DIG 5 - Barrow Gas Field; No rule No rule No rule South Barrow #5 DIG 6 - Lewis River Gas No rule No rule 3 Field; WD-l DIO 7 - West McArthur 2 3 5 River Unit; WMRU D-l DID 8 - Beaver Creek Unit; 2 3 5 BC-3 DIO 9 - Kenai Unit; KU 11- 2 3 4 17 DIO 10 - Granite Point 2 3 5 Field; GP 44-11 Injection Order "Demonstration of Mechanical Integrity" 2 DIO 11 - Kenai Unit; KU 24-7 DIO 12 - Badami Unit; WD- I, WD- 2 DIO 13 - North Trading Bay Unit; S-4 DIO 14 - Houston Gas Field; Well #3 DIO 15 - North Trading Bay Unit; S-5 DIO 16 - West McArthur River Unit; WMRU 4D DIO 17 - North Cook Inlet Unit; NCill A-12 DIO 19 - Granite Point Field; W. Granite Point State 17587 #3 DIO 20 - Pioneer Unit; Well 1702-15DA WDW DIO 21 - Flaxman Island; Alaska S tate A - 2 DIO 22 - Redoubt Unit; RU Dl DIO 23 - Ivan River Unit; fRU 14-31 DIO 24 - Nicolai Creek Unit; NCU #5 DIO 25 - Sterling Unit; SU 43-9 DIO 26 - Kustatan Field; KFl Storage Injection Orders SIO 1 - Prudhoe Bay Unit, Point McIntyre Field #6 SIO 2A- Swanson River Unit; KGSF # I SIO 3 - Swanson River Unit; KGSF #2 Enhanced Recovery Injection Orders EIO 1 - Prudhoe Bay Unit; Prudhoe Bay Field, Schrader Bluff Fonnation Well V-I05 2 2 2 2 2 2 3 3 3 3 No rule 3 3 No rule 2 2 No rule Affected Rules "Well Integrity "Administrati ve Failure and Action" Confinement" 3 4 3 5 3 6 3 5 3 Rule not numbered 3 5 3 6 4 6 4 6 4 7 No rule 6 No rule 6 Order expired 4 7 4 7 No rule No rule No rule 6 No rule 7 No rule 8 Injection Order EIO 2 - Redoubt Unit; RU-6 ') "Demonstration of Mechanical Integrity" 5 ) Affected Rules "Well Integrity Fail ure and Confinement" 8 "Administrative Action" 9 I 02-902 (Rev. 3/94) -1 Publisher/Original Copies: Department Fiscal, Department, Receiving AO,FRM STATE OF ALASKA ADVERTISING ORDER SE:E BOTTOM FÖ~IN"OICE ADDRESS NOTICE TO PUBLISHER ADVERTISING ORDER NO. INVOICE MUST BE IN TRIPLICATE SHOWING ADVERTISING ORDER NO" CERTIFIED AO-02514016 AFFIDAVIT OF PUBLICATION (PART 2 OF THIS FORM) WITH ATIACHED COPY OF ADVERTISEMENT MUST BE SUBMITIED WITH INVOICE F R o M AOGCC 333 West th Avenue, Suite 100 Anchorage, AK 99501 907-793-1221 AGENCY CONTACT DATE OF A.O. lody Colombie September ')7, ),004 PHONE PC~ (907) 793 -I ')') 1 DATES ADVERTISEMENT REQL'IRED: T o Journal of Commerce 301 Arctic Slope Ave #350 Anchorage, AK 99518 October 3, 2004 THE !VIA TERIAL BETWEEN THE DOUBLE LINES MUST BE PRINTED IN ITS ENTIRETY ON THE DATES SHOWN. SPECIAL INSTRUCTIONS: United states of America AFFIDAVIT OF PUBLICATION REMINDER State of ss INVOICE MUST BE IN TRIPLICATE AND MUST REFERENCE THE ADVERTISING ORDER NUMBER. A CERTIFIED COPY OF THIS AFFIDAVIT OF PUBLICATION MUST BE SUBMITTED WITH THE INVOICE. ATTACH PROOF OF PUBLICATION HERE. division. Before me, the undersigned, a notary public this day personally appeared who, being first duly sworn, according to law, says that he/she is the of Published at in said division and state of and that the advertisement, of which the annexed is a true copy, was published in said publication on the day of 2004, and thereafter for _ consecutive days, the last publication appearing on the _ day of , 2004, and that the rate charged thereon is not in excess of the rate charged private individuals. Subscribed and sworn to before me This _ day of 2004, Notary public for state of My commission expires 9/29/2004 1: 10 PM 10f2 Subject: Public Notices From: Jody Colombie <jody_colombie@admin.state.ak:.us> Date: Wed, 29 Sep2004 13:01 :04 -0800 To: undisclosed~recipi~nts:; Bee:' Cynthia BMciver <bren_ mciver@admin.state.ak. us>, Angel~'W ebh <aÏ1gie~ webb@ad~n.state.ak.1is>, Robert E Mintz <robert~miµtz.@law ~ståte~ak:.us>, Christine Hansen <c~h~sen@iogcc.sta.te.ok. us>, 'TemeHubbI¢ <hubbletf@bþ.com>; Sondra Stewman <StewmaSD@BP~com>,. Scott & Cari1m.y Taylor <staylor@alaska.net>,st~ekj . <stanekj.@unocaI.com>, ecolaw <ecolaw@trustees.org>, f()seragsdale, <roseragsdåle@gci.net>, tnnjr 1 <trmjr 1 @aol.cOrt1>, jbriddle<jbri~dle@maratl1onoiI.coIQ.>, rockhill <rockhill@aoga.org>, shaneg <shan~g@evergreengas~com>, jdarlington <jdarlington@forest~*l~cotµ>, ;n¢lson . <knelson@petro.leurrinews:cotr1> ,cboddy~cbóddy@usibelli.corp.> ,l'4ark. Dalton <mark.dalton@hdrinc.com.>, Shannon Donnelly. <shannoi1.donnel1y@conocophiUips.9om>;. '~Mark P. Worcester" <mark.p.worcester@conocophillips.com>, "JerryC.Dethlefs" '. . .": ~ .' <jerry.c.dethlefs@conocophillips.com:>,Bob <bob@inletke~þer.org>, wdv <wdV@4m.stélte.ak.us>, tjr <tjr@dnr.state.ak.us>,bbritch <bbritch@alaska.net>, mjnèlson <mjnelson@pu:rvingem.com>, Charles O'Donnell <charles.o'donneIl@veco.com>, "RandY,L: Skillern" <SkìlleRL@BP.com>, "Deborah J. Jonestl <JonesD6@BP.com>,"Paul G.Hyatt" <hyattpg@BP.coin>, "Steven R.Rossberg" <RossbeRS@BP .c()m>, Lois <lois@inletkeeper.org>, Dan Bross<kuacnews@þac.org>,Gordon Pospisil <PospisG@BP.com>, "Francis S.·Sommer" <SommerFS@BP~coni>,'Mikel Schultz <MikeLSchultz@BP . com>, "Nick W~ Glover'" <GloverNW@BP . com>, ".Daryl· J.K1eppinrt <K.leppiDE@BP~com>, "Janet D. Platt" <~lattJD@BP.com>'."Rosánne M. Jacobs'en" <JacobsRM@BP.com>, ddonkel <ddonkel@cfl.rr.com>, Collins Mount <collins _ mount@revenue~state.ak:us>, mckay <mckay@gci.net>,Barbara F Fullrp:er <barbara~f.fulbner@c.oí1ocophil1ips.com> ~ bocastwf ~bócaStwf@bp~coni>" Cºarles Bark~r . <barker@usgs.gov>, dOtlg_schultze <doug_scbultze@Xtoenergy.com>,fIamc Alford '.' <hank.alford@exxonmobil.com>,.MarkKovac<yesnol@."gcLnet> t 'gspfoff <gspfoff@aurorapower.com>, GreggN ady <gregg.nady@shelLcotn>, Fred.Steece <fted.steece@state.sd.us>, rcrotty <rcrotty@ch2m.·.com>, jejones<jejortes@aurorapower.cöm>, dapa <dapa@alaska.net>,jrQderick<jroderick@gci.net>, e~, cy<eyapcy@se~tl~tit~.net?:, "J~es M. Ruûdtl <james.m.ruud@conocophillìps.com>·,.Brit Lively <rrtap~aska@ak~ri~t>,.jah <jah@dnr.state~a.k.us>, Kurt EOIson <kurt _ olson@legis.state.ak.us>, buc>noje <buonoje@bp.com>, Mark Hanley <mark _ hanley@anadarko.com>, loren _ k~mall <lore~leman@gov.state.ak. us>, Julie Houle <julie_houle@dnr.state.ak.us>, John W Katz<jwkatz@'sso~org>, S~a.n.J Hill . <suzan_hil1@dec.state.ak.us>, tablerk <tablerk@unoca1.com>, :ßr~y <brady@~o8a.org>, Brian Havelock·<beh@dnr.state.ak.us>, bpopp <bpopp@borough~kenai.ak.us>, Jim White <jimwhite@satx.rr.com>, "John S. Haworth" <john.s.haworth@exxorimobi1.com>, marty <marty@rkin~ustria1.com>, ghammons <ghammo.ns@a()1.com>~nncleatl ~~~~r~@~.~~~~·:~~~~.~~~~..~1;20Ø«rnlmI72Ð(1@aolj.êøm~,;cBman.'~íl~e~pie:. 4i,~It1~~!1,~~~~~~~~~~~"P~y~<i,:~Boe.l~ns <dboelens@aµr~rapowe~.com>, Todd Dw:ke.e.. <:rº~~~~Çi~T~?,~.~~~hultz <gary _ sehultz@drir.state·ak.µS>,. W a.yne".R~qi~~ <~~91JB~~]J)~~75~~a::9~~~i'~~1 IyIiller <Bill_ Miller@xtOåI~ka~cQm>, .Brandon . Gagnon <Qgªgn9J;Ì@t)reìi.å.lªw~¢9m?:,.r~itt'Wjnslow <pm~iIislow@forestpil~¢òm>, GarrY C"~)l1 . <çåtÌQ~@Î)p.~()~~,:·$~~~~;~opeland <cppelàsv@bp..com>, Suz~e: AÏlexal1 ... .···..i ~~.a1!7IIIi.~~...11!I~¢k. ) ) Public Notices Public Notices <scott.cranswick@mms.gov>, Brad McKiIll <Il1ckÌI1lbs@BP.com> ~té~sè.... f,*~d...tlJ,~i·.·à~t~SÞ.7d...··r.J'()tïceaIldAtt~éhtÎl~I1t.· . for ...·.l~~~~c)J(?~~~ amendment of '\;1;I1g<7:t'groqnd'i~ject:iqn orders and ·the Ptlb:r~c ·.~øticeHa;PP¥v.:è3.J.1.€f¥ #1:0>. 9"9c1yCölo111bie ; ..... '. . ....... ........... ...... ...... .' .. . ..... ........ ........ .¡ColÌ~~ÌJ.t-tYpe: ªppIicàtìon!msword iM)~"~JI;lçl);J;..tegFlty proP~~aJ;4~C'I€Qlì"teì1t~~n~~:..,~3St)64 ., ...,. ""'''''~'''''.''''_.~':.''--'''''''' ,_.._~_.....'--'. ._';_·.......'.v..__.'.."'n_\ ......'~'.".,....".",. ._.'~'. ..:'''''. .. .;.L.......~.,_...."_,.,~,,.., I. . ;.. '._~ "-'R__.".,....,.~. ,.~'-:"'___"'".-J..-:"~..,,__....,....... ,..:...~.~ .r.~'-.,' ~,,,"".~ ". .,. ~'w .'_"...__._:" _. " '."..~...~_~;.~~._...,." :.....~....,.... . . ......::".'.....':................::..............::,..,:..:..,.:.... . . .........::.....::.......:"...':...............:.'.........................:;';:,:.......:'.....':'...:::,:,,:'........':..':'.......................'...'............'.;..:'...'...:..'..........:....''"'..''''' i.. . ............... ........ ..........:..... ....................... ....< < ...... I Content-Type: ~pp~icati9n;'msword Mêëhanicå.IIl1tegrity·ofWeIfs Notice.doc: .............. ....... ..·.····vi. ..~..i.. ····b' ...·...6..4. ! Content...;~nc0c:lll1g: .·ase , .... ........ ..' .' ................ ...i...... ........./ ........ .'. :........ .... .... .. .... ....··..·.·...·....··:Cog:t~nt-Typ¢: aFpliç~tion/msw()rd BapPYVa.II~y'OIle~~lIlgNotlce.d()c. · C··'· ....... ........ ..............: ..' · ...... '.. ....... ................... .............. .....1:......................... ............. ".1.:. ..... ··....·.··....·6............4····.. .. ~ .' .... . ..... ." :ontent-EncotUltg:.uase ,. ,.~ ~,~,. ~,,,,~, -~,.. ';;., ..~,~,.:.,:..'~,~.~.. .::~:..~:.~",..;,;-,. ':'~.~":'. :.;, :.:......:. '-...,.-.....-.,. .,;,~ .¥.. ..~-_.. :' , , '. ' .' ". ". ;"':, "," "." "",;-'-:'.:: ':., "..:. ," .... ~.." _""~.,....''''_' .-,-.....-.,;...,...... '-" .....'.....~'-,..". .-'". ~...,...¥_...,,',-~.....,_..,... '-~.._-~.~'--._..,...__.._-_._~,..- ... .'.~-,~~,.,._..... -~..,~_.~~..~--.~. 20f2 9/29/2004 1: 10 PM tblic Notice ) Subject: Public Notice From: Jody Colombie <jody _colombie@admin.state;ak.us> Date: Wed, 29 Sep 2004 12:55:26 -0800 To: legal@alaskajöumal.com Please publish the attached Notice on October 3, 2004. Thank you. Jody Colombie Mechanical Integrity of Wells Content-Type: applicationlmsword Content-Encoding: base64 Ad Order form.doc 1 of 1 9/29/2004 1: 10 PM Citgo Petroleum Corporation PO Box 3758 Tulsa. OK 74136 Mary Jones ><TO Energy, Inc. Cartography 810 Houston Street, Ste 2000 Ft. Worth, TX 76102-6298 1íJc:t¡/¿;d /ð/0 David McCaleb IHS Energy Group GEPS 5333 Westheimer, Ste 100 Houston, TX 77056 Kelly Valadez Tesoro Refining and Marketing Co. Supply & Distribution 300 Concord Plaza Drive San Antonio, TX 78216 Robert Gravely 7681 South Kit Carson Drive Littleton. CO 80122 George Vaught, Jr. PO Box 13557 Denver, CO 80201-3557 Jerry Hodgden Hodgden Oil Company 408 18th Street Golden, CO 80401-2433 Richard Neahring NRG Associates President PO Box 1655 Colorado Springs, CO 80901 John Levorsen 200 North 3rd Street, #1202 Boise, ID 83702 Kay Munger Munger Oif Information Service, Inc PO Box 45738 Los Angeles, CA 90045-0738 Samuel Van Vactor Economic Insight Jnc. 3004 SW First Ave. Portland. OR 97201 Michael Parks Marple's Business Newsletter 117 West Mercer Sf, Ste 200 Seattle, WA 98119-3960 Mark Wedman Halliburton 6900 Arctic Blvd. Anchorage. AK 99502 Schlumberger Drilling and Measurements 2525 Gambell Street #400 Anchorage, AK 99503 David Cusato 200 West 34th PMB 411 Anchorage, AK 99503 Baker Oil Tools 4730 Business Park Blvd., #44 Anchorage, AK 99503 Cirì Land Department PO Box 93330 Anchorage, AK 99503 Jill Schneider US Geological Survey 4200 University Dr. Anchorage, AK 99508 Gordon Severson 3201 Westmar Cr. Anchorage, AK 99508-4336 Jack Hakkila PO Box 190083 Anchorage. AK 99519 Darwin Waldsmith PO Box 39309 Ninilchick, AK 99639 James Gibbs PO Box 1597 Soldotna, AK 99669 Kenai National Wildlife Refuge Refuge Manager PO Box 2139 Soldotna, AK 99669-2139 Penny Vadla 399 West Rìverview Avenue Soldotna, AK 99669-7714 Richard Wagner PO Box 60868 Fairbanks, AK 99706 Cliff Burglin PO Box 70131 Fairbanks, AK 99707 Bernie Karl K&K Recycling Inc. PO Box 58055 Fairbanks, AK 99711 Williams Thomas Arctic Slope Regional Corporation Land Department PO Box 129 Barrow, AK 99723 North Slope Borough PO Box 69 Barrow, AK 99723 ~wd: Re: Consistent Wording for Injection ìrs - Well Integrity ... ) ~ubJect:,,' [Fwd:Re: 'C9tlSisteIJ.tWOrd:ìlf~..,f()t lr1jêc~io~ .?rdets"'-Wél1lr!t¢gpifY<R~vis~q)] F~om:" John Normal1.,,<j0hn--,-110?an($aqrni~:sta~e.~~u~> Pate: Fri" 01 Oct 200411:09:26;.0800 Î'~;·,.Jþªy:~·çpt9~Þi~:·~~ª~l.¿R~R~þf~@~~j#'·:~t~~¢;~·µ~~..."", more -------- Original Message -------- Subject:Re: Consistent Wording for Injection Orders - Well Integrity (Revised) Date:Wed, 25 Aug 2004 16:49:40 -0800 From:Rob Mintz <robert mintz@law.state.ak.us> To:jim regg@admin.state.ak.us CC:dan seamount@admin.state.ak.us, john nonnan@admin.state.ak.us Jim, looks good, but I still think maybe it would be good to include the following sentence or something like it in the well integrity and confinement rule: "The operator shall shut in the well if so directed by the Commission." My thinking is that otherwise, an operator might argue that the Commission can only require the well to be shut in by going through an enforcement action, issuing an order after notice and opportunity for hearing, or meeting the strict requirements for an emergency order under the regulations. The proposed language makes clear that it is a condition of the authorization to inject, that the operator must shut in the well if directed by the Commission after a notification of loss of integrity, etc. »> James Regg <.iim regg@admin.state.ak.us> 8/25/2004 3:15:.06 PM »> Rob - Thanks for the review; here's a redraft after considering your comments. I have accepted most of the suggested edits; also attached is response to questions you pose (responses are embedded in the comments, using brackets [JBR - ...J to set apart from your questions). Jim Regg Rob Mintz wrote: Jim, I have some questions abQut the draft language, which are shown as comments on the first document attached. Based on my current guesses about what the answers will be to my questions, I also have some suggested edits, which are shown as redlines on the second document attached. »> James Regg <iim regg~admin.state.ak.us> 8/17/20044:33:52 PM »> Please delete previous version (email sent 8/9/04); I found another inconsistency in the injection orders regarding well integrity that I have integrated into the proposed fix. Attached is a proposal for consistent language in our injection orders addressing 3 rules related to well integrity: - "Demonstration of Tubing/Casing Annulus Mechanical Integrity" - "Well Integrity Failure" - "Administrative Actions". This proposal includes input from all Sf. staff (except Jack). If you agree with the approach, I'll work with Jody to prepare the public notice. Main points - Demonstration of Tubing/Casing Annulus Mechanical Integrity - standardizes the wording used for mechanical integrity demonstrations, and establishes abililty to grant alternate methods (e.g., temp survey, logging, pressure monitoring in lieu of pressure testing 10f2 10/2/2004 4:07 PM [Fwd: Re: Consistent Wording for Injection .ers - Well Integrity... - specific to AIO 2C for Kuparuk, there is wording that is more appropriately included in Well Integrity Failure (ì.e., more frequent MITs when communication demonstrated) - establishes more frequent MIT schedule for slurry injection wells (every 2 yrs) which is consistent with our current practice (but not addressed in regulations) Well Integrity Failure - retitles to "Well Integrity Failure and Confinement"; inserted language regarding injection zone integrity (see DIO 25 and 26) - consistent language regardless of type of injection (disposal, EOR, storage); - eliminates requirement for immediate shut in and secure; allows continued injection until Commission requires shut in if there is no threat to freshwater; - eliminates delay in notifying Commission after detect leakage or communication ("i.e., "immediately notify"); - removes language about notifying "other state and federal" agencies; - requires submittal of corrective action plan via 10-403; - requires monthly report of daily injection rate and pressures (tubing and all casing annuli); this is a requirement we currently impose when notified of leak or pressure communication; - notice and action not restricted to I,eaks above casing shoe as stated in several DIOs Administrative Actions - adopts" Administrative Actions" title (earlier rules used" Administrative Relief'); - consistent language regardless of type of injection (disposal, EOR, storage); - uses "administratively waive or amend" in lieu of terms like "revise", "reissue", etc.; - adds geoscience to "sound engineering principles"; - language is more generic regarding fluid movement out of zone; existing versions mention varying combinations of protecting "freshwater", "aquifers", "USDWs"; "risk of fluid movement"; "fluid escape from disposal zone" Jim Regg JohnK. Norrnan <John Norrnan@admin.state.us> Commissioner . Alaska Oil & Gas Conservation Commission 20f2 10/2/2004 4:07 PM [Fwd: Re: Consistent Wording for Injection ( h - Well Integrity... ) ~~~ject: [Fwd: Re: ConsistentW ordingfor IrijëctipnOrders "" We111l1tégrity(~evised)] ~rºrn: John Norman <johri~n()rman@admin.stat~.ak.µ,s> Date: Fri, 01 Oct 2004'11 :08:55 -0800 ~~~:J:gªYJèJq~~Ìtiþ~é,~:ø~¥¿#~l,~~þj,~@~~~i~·~tél~~.'~:'~š?>:' please print all and put in file for me to review just prior to hearing on these amendments. thanx -------- Original Message -------- Subject:Re: Consistent Wording for Injection Orders - Well Integrity (Revised) Date:Thu, 19 Aug 2004 15:46:31 -0800 From:Rob Mintz <robert mintz@law.state.ak.us> To:dan seamount@admin.state.ak.us, jim regg@admin.state.ak.us, john norman@admin.state.ak.us Jim, I have some questions about the draft language, which are shown as comments on the first document attached. Based on my current guesses about what the answers will be to my questions, I also have some suggested edits, which are shown as red lines on the second document attached. »> James Regg <.iim regg@admin.state.ak.us> 81l7/2004 4:33:52 PM »> Please delete previous version (email sent 8/9/04); I found another inconsistency in the injection orders regarding well integrity that I have integrated into the proposed fix. Attached is a proposal for consistent language in our injection orders addressing 3 rules related to well integrity: - "Demonstration of Tubing/Casing Annulus Mechanical Integrity" - "Well Integrity Failure" - "Administrative Actions". This proposal includes input from all Sr. staff (except Jack). If you agree with the approach, I'll work with Jody to prepare the public notice. Main points - Demonstration of Tubing/Casing Annulus Mechanical Integrity - standardizes the wording used for mechanical integrity demonstrations, and establishes abililty to grant alternate methods (e.g., temp survey, logging, pressure monitoring in lieu of pressure testing - specific to AIO 2C for Kuparuk, there is wording that is more appropriately included in Well Integrity Failure (i.e., more frequent MITs when communication demonstrated) . - establishes more frequent MIT schedule for sluny injection wells (every 2 yrs) which is consistent with our current practice (but not addressed in regulations) Well Integrity Failure - retitles to "Well Integrity Failure and Confinement"; inserted language regarding injection zone integrity (see 010 25 and 26) - consistent language regardless of type of injection (disposal, EOR, storage); - eliminates requirement for immediate shut in and secure; allows continued injection until Commission requires shut in if there is no threat to freshwater; - eliminates delay in notifying Commission after detect leakage or communication ("i.e., "immediately notify"); - removes language about notifying "other state and federal" agencies; - requires submittal of corrective action plan via 10-403; - requires monthly report of daily injection rate and pressures (tubing and all casing annuli); this is a requirement we currently impose when notified of leak or pressure communication; - notice and action not restricted to leaks above casing shoe as stated in several OIOs Administrative Actions 10f2 10/2/20044:07 PM [Fwd: Re: Consistent Wording for Injection .=rs - Well Integrity... - adopts "Administrative Actions" title (earlier rules used "Administrative Relief"); - consistent language regardless of type of injection (disposal, EOR, storage); - uses "administratively waive or amend" in lieu of terms like "revise", "reissue", etc.; - adds geoscience to "sound engineering principles"; - language is more generic regarding fluid movement out of zone; existing versions mention varying combinations of protecting "freshwater", "aquifers", "USDWs"; "risk of fluid movement"; "fluid escape from disposal zone" Jim Regg JohnK. Norman <John Norman@admin.state.us> Commissioner Alaska Oil & Gas Conservation Commission Content-Type: application/msword Injection Order language - questions.doc Content-Encoding: base64 Content-Type: application/msword Injection Orders language edits.doc Content-Encoding: base64 20f2 10/2/2004 4:07 PM ) Standardized Language for Injection Orders Date: August 17, 2004 Author: Jim Regg Demonstration of Tubing/Casing Annulus Mechanical Integrity The mechanical integrity of an injection well must be demonstrated before injection begins, after a workover affecting mechanical integrity, and at least once every 4 years while actively injecting. For slurry injection wells, the tubing/casing annulus must be tested for mechanical integrity every 2 years. The MIT surface pressure must be 1500 psi or 0.25 psi/ft multiplied by the vertical depth, whichever is greater, must show stabilizing pressure and may not change more than 10% during a 30 minute period. Any alternate means of demonstrating mechanical integrity must be approved by the Commission. The Commission must be notified at least 24 hours in advance to enable a representative to witness pressure tests. Well Integrity Failure and Confinement The tubing, casing and packer of an injection well must demonstrate integrity during operation. The operator must immediately notify the Commission and submit a plan of corrective action on Form 10-403 for Commission approval whenever any pressure communication, leakage or lack of injection zone isolation is indicated by injection rate, operating pressure observation, test, survey, or log. If there is no threat to freshwater, injection may continue until the Commission requires the well to be shut in or secured. A monthly report of daily tubing and casing annuli pressures and injection rates must be provided to the Commission for all injection wells indicating pressure communication or leakage. Administrative Actions Unless notice and public hearing is otherwise required, the Commission may administratively waive or amend any rule stated above as long as the change does not promote waste or jeopardize correlative rights, is based on sound engineering and geoscience principles, and will not result in fluid movement outside of the authorized injection zone. Standardized Language for Injection Orders Date: August 17, 2004 Author: Jim Regg Demonstration of Tubing/Casing Annulus Mechanical Integrity The mechanical integrity of an injection well must be demonstrated before injection begins, at least once every four years thereafter (except at least once every t\\/O years in the case of a slurry injection \vell), and before rcturnin,g a wen to sc:rvice fol1o\ving affet: a workover affecting mechanical integrity, and at leDst once every /1 year~; while actively injecting. For ~;Iurry injection \vells, the tubing/casing ~Ulnulus tTIust be t~skd fl^n" mechanical integrity every 2 years. Unless an alternate ITIeat1S is approved by the COl11il1Ìssion. Inechanical integrity 111ust be den10nstratcd by a tubin,!Z pressure test using a +fie M-ff-surface pressure ofnlust be 1500 psi or 0.25 psi/ft multiplied by the vertical depth, whichever is greater, that ffi-tl-Sf-show~ stabilizing pressure that does~nd Inay not change more than 10Qið- percent during a 30 minute period. -Any alten1ate il1cans of dCll10nstrating Illcchanical integrity rnust be approved by the COll1il1ission. The Commission must be notified at least 24 hours in advance to enable a representative to witness pressure tests. Well Integrity Failure and Confinement Except as othenvise provided in this rule, +lhe tubing, casing and packer of an injection well must demonstrate Inaintaìn integrity during operation. \Vhenever any pressure cornmunication, leakage or lack of injection zone isolation is indicated by injection rate, operating pressure observation, test, survey, log. or other evidencc, t+he operator fH:-1±Sf-shall immediately notify the Commission and submit a plan of corrective action on a Form 10-403 for Commission approval:. \\'henever any pressure cOl1ununication, leakage or lack of injection zone isolation is indicated by injection ratc, operatíng pressure observation, test, survey, or log. The operator shall shut in the well if so directed bv the Comn1ìssion. The operator shall shut in the \-vell \vithout a\vaitin,g a response horn the Comluission if continued operation would be unsafe or would threaten contamination of freshwaterlf there is no threat to fresl1\vater, injection Inay continue until the COlTIlnission requires the v:ell to be shut in or secured. Until corrective action is successfully completed, ^ª monthly report of daily tubing and casing annuli pressures and injection rates must be provided to the Commission for all injection wells indicating pressure communication or leakage. Administrative Actions Unless notice and public hearing is otherwise required, the Commission may administratively waive or amend any rule stated above as long as the change does not promote waste or jeopardize correlative rights, is based on sound engineering and geoscience principles, and will not result in fluid movement outside of the authorized injection zone. ¡[Fwd: Re: [Fwd: AOGCC Proposed WI LanL}e for Injectors]] ) ~tI~J.ect: [Fwd: Re: [Fwd: AOGCCProposed WI Language for Injectors]] ~r()nH'Winton',Aubert'<winton_aubert@adtnin.state.ak·us> ~~:~~:·!~Y:,~~.9s~~·?80g9:;{ê.:.?~~~~92...",.,.,. .'.' ,"'·,.,.i., ",',·i, "'."'.,, '.',"...'.',. ",··ii..".,.',.,·",,·.'.,'.,,",',·.',., " :JF.~:·:·lè·~Y.~::P~]qm~!<;·tic?ª>'6~Q~ç#ip·:~~@~~~fu~~r~tt:\.#k.:µs~< ,',,' " ' ". This is part of the record for the Nov. 4 hearing. WGA -------- Original Message -------- Subject: Re: [Fwd: AOGCC Proposed WI Language for Injectors] Date: Thu, 28 Oct 2004 09:41:55 -0800 From: James Regg <jim regg@admin.state.ak.us> Organization: State of Alaska To: Winton Aubert <winton aubert@admin.state.ak.us> References: <41812422.8080604@admin.state.ak.us> These should be provided to Jody as part of public review record Jim Winton Aubert wrote: FYI. -------- Original Message -------- AOGCC Proposed WI Language for Tue, 19 Oct 2004 13:49:33 -0800 Engel, Harry R <EngeIHR@BP.com> winton aubert@admin.state.ak.us Injectors Subject: Date: From: To: Winton... Here are the comments we discussed. Harry *From: * NSU, ADW Well Integrity Engineer *Sent: * Friday, October 15, 2004 10:43 PM *To: * Rossberg, R Steven¡ Engel, Harry R¡ Cismoski, Doug A¡ NSU, ADW Well Operations Supervisor *Cc: * Mielke, Robert L.¡ Reeves, Donald F¡ Dube, Anna T¡ NSU, ADW Well Integrity Engineer *Subject: * AOGCC Proposed WI Language for Injectors Hi Guys. John McMullen sent this to us, it's an order proposed by the AOGCC to replace the well integrity related language in the current Area Injection Orders. Listed below are comments, not sure who is coordinating getting these in front of Winton/Jim. Overall, looks okay from an Operations perspective. We do have a few comments, but could live with the current proposed language. Note the proposed public hearing date is November 4. The following language does not reflect what the slope AOGCC inspectors are currently requiring us to do: liThe mechanical integrity of an injection well must be demonstrated before injection begins, at least once every four years thereafter (except at least once every two years in the case of a slurry injection well), and * before* ** 10f3 10/28/2004 11:09 AM [Fwd: Re: [Fwd: AOGCC Proposed WI Lan!. ~ for Injectors]l returnj.ng a well to service following a workover affecting mechanical integrity. II After a workover, the slope AOGCC inspectors want the well warmed up and on stable injection, then we conduct the AOGCC witnessed MITIA. This language requires the AOGCC witnessed MITIA before starting injection, which we are doing on the rig after the tubing is run. Just trying to keep language consistent with the field practice. If "afterll was substituted for IIbefore" , it would reflect current AOGCC practices. It would be helpful if the following language required reporting by the "next working day" rather than lIimmediatelyll, due to weekends, holidays, etc. We like to confer with the APE and get a plan finalized, this may prevent us from doing all the investigating we like to do before talking with the AOGCC. "Whenever any pressure communication, leakage or lack of injection zone isolation is indicated by injection rate, operating pressure observation, test, survey, log, or other evidence, the operator shall * immediately* ** notify the Commission" This section could use some help/wordsmithing: "A monthly report of daily tubing and casing annuli pressures and injection rates must be provided to the Commission for all injection wells indicating well integrity failure or lack of injection zone isolation. II Report content requirements are clear, but it's a little unclear what triggers a well to be included on this monthly report. Is it wells that have been reported to the AOGCC, are currently on-line and are going through the Administrative Action process? A proposed re-write would be: IIAIl active injection wells with well integrity failure or lack of injection zone isolation shall have the following information reported monthly to the Commission: daily tubing and casing annuli pressures, daily injection rates." Requirements for the period between when a well failure is reported and when an administrative action is approved are unclear. This document states "the operator shall immediately notify the Commission and submit a plan of corrective action on a Form 10-40311. If we don't plan to do any corrective action, but to pursue an AA, does a 10-403 need to be submitted? The AOGCC has stated they don't consider an AA as "corrective action". Let me know if you have any questions. Joe -----Original Message----- From: Kleppin, Daryl J Sent: Wednesday, September 29, 2004 1:37 PM To: Townsend, Monte A; Digert, Scott A; Denis, John R (ANC); Miller, Mike E; McMullen, John C Subject: FW: Public Notices FYI -----Original Message----- From: Jody Colombie [ mailto:jody colombie@admin.state.ak.us Sent: Wednesday, September 29, 2004 1:01 PM Subject: Public Notices Please find the attached Notice and Attachment for the proposed amendment of underground injection orders and the Public Notice Happy Valley #10. Jody Colombie «Mechanical Integrity proposal. ZIP» «Mechanical Integrity of Wells Notice.doc» 2 of3 10/28/2004 11 :09 AM #7 ') ) 1 2 3 4 In Re: ALASKA OIL AND GAS CONSERVATION COMMISSION PUBLIC HEARING ) ) 5 THE APPLICATION OF ARCO ALASKA INC. FOR ) A PUBLIC HEARING TO DEFINE THE TARN OIL ) 6 POOL. AN AREA INJECTION ORDER IS ALSO ) REQUESTED FOR CLASS II INJECTION FOR THE ) 7 PURPOSES OF ENHANCED OIL RECOVERY ) OPERATIONS. ) 8 ) ^ ^ ^ Du,¡.at " v v 9 TRANSCRIPT OF PROCEEDINGS 10 11 Anchorage, Alaska April 28, 1998 9:00 o'clock a.m. 12 APPEARANCES: 13 Commissioners: MR. DAVID W. JOHNSTON, CHAIRMAN MS. CAMILLE OECHSLI 14 15 ARCO Alaska Inc.: MR. RYAN STRAMP MR. DOUG HASTINGS MR. LAMONT FRAZER MR. FRED JOHNSON 16 17 * * * * * * 18 19 20 21 22 23 24 25 ELITE COURT REPORTING 4051 East 20th Avenue #65 Anchorage Alaska 99508 907·333'0364 ) ) 2 1 PRO C E E DIN G S 2 (On record - 9:05 a.m. ) 3 CHAIRMAN JOHNSTON: I'd like to call this hearing into 4 session. The date is April 28, 1998, the time is approximately 5 five after 9:00 o'clock in the morning. We are located at 3001 6 Porcupine Drive, Anchorage, Alaska, and that is the offices of 7 the Alaska Oil and Gas Conservation Commission. To begin I'd 8 like to introduce the head table. My name is David Johnston, 9 I'm chairman of the commission. And to my right is 10 Commissioner Cammy Oechsle. Laurel Earl, of Elite Court 11 Reporting, will be making the transcript of these proceedings. 12 If you'd like a copy of the transcript we'd ask that you 13 contact Elite Court Reporting directly to do so. 14 The purpose of these proceedings are to consider an 15 application by ARCO Alaska to define and establish pool rules 16 for the Tarn Oil Pool and to approve an area injection order 17 authorizing enhanced oil recovery operations in the pool. 18 The commission published notice of hearing in the 19 Anchorage Daily News on March 28, 1998. And at this time I'd 20 like to note our hearing notice as Alaska Oil and Gas 21 Conservation Commission Exhibit 1, and enter that into the 22 public record. 23 These proceedings will be held in accordance with 24 20 AAC 25.540. Those are regulations governing public 25 hearings. Those regulations provide that we can consider sworn ELITE COURT REPORTIRG 4051 East 20th Avenue #65 Anchorage Alaska 99508 907,333,0364 ) 3 1 testimony or oral statements. We will give greater weight to 2 sworn testimony, of course. If you wish to be considered an 3 expert in this matter, before you testify or provide that 4 statement we'd ask that you state your qualifications. The 5 commission will then rule as to whether we would consider you 6 an expert in this matter. The commission will hear from the 7 applicant first and then we'll allow an opportunity for other 8 interested parties to approach the commission if they so 9 desire. If you have questions of an applicant or of the 10 applicant we would ask that you write those questions down, 11 forward it to the head table, and if we feel that the question 12 is germane, then the commission will ask that question. 13 So at this time I would like to invite our applicant to 14 introduce themselves and approach the commission. 15 MR. STRAMP: Chairman Johnston, my name is Ryan Stramp 16 and I'll be the first to testify for ARCO as the applicant, and 17 I would like to be considered an expert witness. I'll state my 18 qualifications briefly now. 19 CHAIRMAN JOHNSTON: Before you state your 20 qualifications, will you be giving sworn testimony? 21 MR. STRAMP: Yes. 22 CHAIRMAN JOHNSTON: If you would ralse your right hand, 23 please? 24 (Oath administered) 25 MR. STRAMP: Yes, sir, I do. ELITE COURT REPORTING 4051 East 20th Avenue #65 Anchorage Alaska 99508 907·333,0364 ) ) 4 1 CHAIRMAN JOHNSTON: Thank you. Please state your 2 qualifications. 3 MR. STRAMP: I graduated from the University of 4 Oklahoma in 1977 with a bachelor of science degree in petroleum 5 engineering. Upon graduation I went to work for ARCO, 6 initially working in West Texas and Southeast New Mexico in a 7 variety of reservoir engineering and production engineering 8 assignments. In 1981 I moved to Alaska, still with ARCO, and 9 have resided here ever since, working in a variety of 10 positions, including reservoir engineering, production 11 engineering, project management, production optimization, 12 on-site production supervision, business planning, and most 13 recently for the past year I have been the coordinator for the 14 Tarn Development Project. 15 CHAIRMAN JOHNSTON: Thank you. Do you have any 16 objections to..... 17 COMMISSIONER OECHSLI: I do not. 18 CHAIRMAN JOHNSTON: Thank you. The commission will 19 accept you as an expert witness in this matter. Please 20 proceed. 21 MR. STRAMP: I'd like to begin with a few introductory 22 comments. Just over a year ago ARCO Alaska and BP announced 23 the discovery of the Tarn Field, located just outside the 24 southwestern corner of the Kuparuk River unit. This slide will 25 orient us very quickly. You can see the yellow area here to ELITE COURT REPORTING 4051 East 20th Avenue #65 Anchorage Alaska 99508 907,333·0364 ) ) 5 1 the southwest is the approximate location of the Tarn 2 discovery. It's located in between the Kuparuk River Field and 3 the Alpine Field that's being developed. 4 At the same time that the discovery was announced very 5 important business agreements were also approved in the Kuparuk 6 River unit that paved the way for a small satellite such as 7 Tarn and other developments such as West Sak to have access to 8 the processing facilities in the Kuparuk River Field. With the 9 new discovery in hand and a means to process the oil, ARca and 10 BP chose to pursue a very aggressive early start-up plan for 11 this new discovery, targeting first production before the 12 year-end 1998. Activities are still on course for that with 13 both the facility construction and drilling activities 14 currently underway in the field. 15 We're here this morning to present testimony to support 16 classification of this Tarn reservoir as an oil pool and to 17 establish pool rules. ARCO has been designated as the operator 18 of the Tarn development and is presenting testimony on behalf 19 of all the Tarn Working Interest Owners. The scope of this 20 testimony will include discussion as we currently understand it 21 of the geology and reservoir properties of the Tarn area as 22 well as our 23 in addition 24 facilities. plans for reservoir development, surveillance, and information on our well and facilities -- wells and 25 We have pre-filed written testimony with the commission ELITE COURT REPORTIRG 4051 East 20th Avenue #65 Anchorage Alaska 99508 907-333'0364 } ') 6 1 and will supplement that information today with verbal 2 testimony. We've provided final written copies or copies of 3 the written testimony to the head table today. There are a few 4 copies still available on the table over here. They've had a 5 few minor changes from the earlier drafts that you might have 6 seen. In addition, we have copies of the overhead slides and 7 other materials that we'll be using in the presentation today 8 that we will provide for inclusion in the hearing record. 9 In the verbal testimony this morning we want to provide 10 a general foundation of information about Tarn and also have 11 brief discussions on 13 proposed pool rules that we've drafted. 12 The next slide I'll show is an outline of the presentation that 13 we have planned in support of these pool rules. I'll continue 14 for a little longer with introduction, then Doug Hastings will 15 discuss the geology of the Tarn area. Lamont Frazer will talk 16 about reservoir development. Fred Johnson will talk about 17 drilling and completions. Then I'll get back up and talk about 18 surface facilities and then summarize the overall testimony. 19 I might mention that Doug Hastings' initial 20 presentation on geology includes information that's not 21 currently in the public domain, and as such we would like to 22 request that the first part of that presentation be held in 23 confidential session. At the conclusion of that Doug will 24 continue his discussion with some information that is in the 25 public domain that will establish the basis for the definition ELITE COURT REPORTING 4051 East 20th Avenue #65 Anchorage Alaska 99508 907,333·0364 ) ) 7 1 of the Tarn pool. 2 If there are no immediate questions, I'll begin the 3 actual presentation. I think the next slide in your packet is 4 a listing of the 13 rules that I've previously mentioned. Just 5 to give you an idea of what we're -- I think yeah, they're 6 here in the packet of slides. I'll give you an idea of the 7 sorts of rules that we're talking about. They're very -- 8 should be very familiar. You'll note a lot of similarity 9 between these and the recently approved West Sak pool rules. 10 We used them as a model in many cases, and as we feel as they 11 are appropriate. 12 The next slide I'd like to review briefly just hits 13 upon a few key points that we feel like are appropriate to use 14 as a basis for proposed pool rules and are the items that we're 15 considering as we develop our list of proposals. The first 16 three are very familiar, I'm sure, to the commission, 17 preventing waste and promoting conservation, protecting 18 correlative rights and promoting maximum ultimate recovery. We 19 feel like our development plans and the pool rules that we're 20 proposing are very much in keeping with these ideals. In 21 addition, as I've already mentioned, we would seek to have 22 consistency with the Kuparuk pool rules in that we are in 24 direct -- or going to be operating within the Kuparuk River unit and -- as well as other pools within the Kuparuk unit. The next slide gives just a very brief background of 23 25 ELITE COURT REPORTIBG 4051 East 20th Avenue #65 Anchorage Alaska 99508 907·333,0364 ) ) 8 1 the Tarn project. There have been exploration drilling that 2 Doug will talk about in a few minutes in the area. In earlier 3 years we'd found some tight sands with oil shows but we were 4 not able to consistently predict where that oil would be and we 5 were not able to identify anything of commercial size or 6 quality. The key that really unlocked this for BP and 7 ourselves was acquisition of 3D seismic in 1996 that was used 8 to locate the four wells that were drilled in early 1997, all 9 of which found oil sand, and as noted here, we did an extended 10 test of the Tarn 2 well that produced 1900 barrels of oil a 11 day, and the quality of that oil was very nice, at 37° API. 12 A few points at the bottom of the slide there about the 13 alignment agreements. They are very key to our ability to be 14 moving ahead at this point with the Tarn development, providing 15 access to the Kuparuk facilities for a small project like this 16 that would likely not be economic if we had to go standalone is 17 very important to us. And then the last comment about it also 18 has resulted in alignment of interest very similar to the 19 interest in the Kuparuk participating area. 20 CHAIRMAN JOHNSTON: So these alignment agreements are 21 all signed then? 22 MR. STRAMP: Yes, they are. And that reminds me, we 23 are also, as one of the exhibits to the pool rules, submitting 24 copies for the commission of the alignment agreements. We've 25 got one set of coples or one set of copies of each of the three ELITE COURT REPORTING 4051 East 20th Avenue #65 Anchorage Alaska 99508 907,333,0364 ) ) 9 1 separate agreements that have been executed that we're filing 2 for your records and for the record. 3 The next slide I'd like to show just illustrates the 4 similarity between the ownerships in the Kuparuk participating 5 area, or KPA as it's shown here, and the Tarn area. If you 6 note the ownerships of Unocal, Mobil and Chevron are exactly 7 the same in the KPA and then Tarn. Exxon is not a participant 8 in Tarn. They are a .2 participant in the KPA. ARca and BP 9 basically are sharing that additional interest that would 10 otherwise have shown up under Exxon's name in the Tarn area. 11 So you can see, with the exception of that .2% difference, we 12 are very, very closely aligned between our Kuparuk 13 participating ownership and the Tarn ownership. 14 Another important point to make is that these Tarn 15 ownership decimals apply over the entire area, both initial 16 Tarn development and potential Tarn exploration that we're 17 going to be talking about. So that basìcally means that equity 18 has been set for this play on a lease-by-lease basis. Cross 19 assignments have been made or will be made that set these 20 ownerships and, again, this is another element that makes us 21 able to move ahead at a rapid development pace given that 22 equity is already determined. 23 Just to summarize a few other key points about the Tarn 24 project. We've already mentioned that we're going to share the 25 Kuparuk participating area infrastructure. We have a phase ELITE COURT REPORTING 4051 East 20th Avenue #65 Anchorage Alaska 99508 907·333·0364 ) 10 1 development. We're going to inject Kuparuk miscible injectant. 2 MI, on this slide, stands for miscible injectant from the 3 start, making this an EOR project from the very beginning. We 4 feel like that's a key to successfully developing the Tarn 5 reservoir. You'll hear about some of the reservoir 6 characteristics that make it a prime candidate for an EOR 7 project, and it's very important to -- that we feel the success 8 of this project to start along these lines. 9 We're still targeting first production later this year 10 in 1998, and there is still the opportunity for additional 11 exploration in the area, and that's why the pool area that 12 we're requesting is somewhat larger than the initial 13 development area. We feel it's prudent to go ahead and where 14 we have seismic evidence of additional potential, to start off 15 with a pool definition to include that area. 16 The next slide talks a little bit about the unit and 17 participating area status. In progress òr our plans are to 18 expand the Kuparuk River Unit to include the Tarn area and to 19 form a new participating area for Tarn. We've been involved in 20 pre-application discussions with DNR for several months and we 21 believe we've come to a common agreement on the leases to be 22 included in the unit expansion and in the participating area. 23 We're putting the final touches on the applications for the 24 unit expansion of the participating area and those will be 25 filed with DNR in early May, and those applications will ELITE COURT REPORTING 4051 East 20th Avenue #65 Anchorage Alaska 99508 907'333,0364 ) ) 11 1 include formal plans of development operations and exploration. 2 And we will be sure to copy the commission as those are 3 submitted to DNR. 4 CHAIRMAN JOHNSTON: And you anticipate that that 5 application will go forward and be approved by DNR? 6 MR. STRAMP: Yes, we do. We've -- yes, we've been 7 working with DNR since late last year on these issues and there 8 are no controversial issues that we're aware of at this time. 9 The next slide is a map depicting the proposed unit 10 expansion area down in the southwest area. As I indicate here, 11 the solid line is the proposed unit expansion area, so the 12 Kuparuk River unit is proposed to be expanded to include these 13 leases. The dash line surrounds the leases that are proposed 14 to be included in the initial participating area. 15 CHAIRMAN JOHNSTON: In terms of the area that you wish 16 to be included in the pool rules area, could you describe using 17 this map what that relationship is? 18 MR. STRAMP: It's similar to the unit area. We'll have 19 some additional exhibits that show that in the geologic 20 presentation, but it's more in keeping with the unit area 21 which, again, reflects the fact that we have reason to believe 22 that this play has exploration potential both to the north and 23 to the south. And, again, the lease ownership over this entire 24 area that we're discussing for unit expansion and the PA and 25 even extending farther to the east end of the field is fixed ELITE COURT REPORTIRG 4051 East 20th Avenue #65 Anchorage Alaska 99508 907·333,0364 ) ) 12 1 and set by the alignment agreements. 2 CHAIRMAN JOHNSTON: The dates that I'm seeing on some 3 of these leases in the expansion area looks like 11-30-98; is 4 that the exploration date? 5 MR. STRAMP: Those are the primary exploration dates 6 and we've -- that's been one of the main points of discussion 7 with DNR, and DNR will require exploration work commitments to 8 include those leases in the unit, and we are very willing to 9 comply with those. So the plan, as we will submit it, will 10 include these leases along with the work requirements to drill 11 exploration wells to hold the leases. 12 That brings me to the end of my introductory comments. 13 If there are any questions that I can answer now, I'd be happy 14 to, otherwise Doug Hastings will be next. And as I mentioned, 15 the first part of his presentation we would like to have in 16 confidential session. 17 CHAIRMAN JOHNSTON: In terms of your plans for pool 18 development and operation, when would you be submitting copies 19 of that to the commission? 20 MR. STRAMP: Along with the unit Expansion and PA 21 Application. You will see today in Lamont's presentation an 22 overview of that, but it will be presented in concise final 23 form within, you know, by mid-May is our estimate. 24 CHAIRMAN JOHNSTON: And I imagine what we'll be hearing 25 today is an overture of that plan..... ELI TEe 0 U R T R E P 0 R T I B G 4051 East 20th Avenue #65 Anchorage Alaska 99508 907'333,0364 1 2 3 Thank you. 4 5 6 7 8 name. 9 10 11 morning? 12 13 14 hand? 15 16 17 18 sworn. 19 20 21 ) ') 13 MR. STRAMP: Yes, exactly. CHAIRMAN JOHNSTON: .....of development. Okay. MR. STRAMP: Okay. Doug will be next. CHAIRMAN JOHNSTON: Next witness. MR. HASTINGS: Good morning. CHAIRMAN JOHNSTON: Good morning. If you'd state your MR. HASTINGS: My name is Douglas S. Hastings. CHAIRMAN JOHNSTON: And do you wish to be sworn this MR. HASTINGS: Yes, I do. CHAIRMAN JOHNSTON: Would you please raise your right (Oath administered) MR. HASTINGS: I do. CHAIRMAN JOHNSTON: Thank you. Consider yourself Do you wish to be considered an expert witness? MR. HASTINGS: Yes, I do. CHAIRMAN JOHNSTON: If you'd state your qualifications. 22 my bachelor's degree from the University of Washington in 1975 MR. HASTINGS: I'm a geologist with ARCO. I received 23 in geology; a master's degree in 1977 in geology from UC 24 Santa Barbara; and I've worked for ARCO ever since. I've 25 worked in Denver -- or Alaska and then London and then my most ELITE COURT REPORTIlIG 4051 East 20th Avenue #65 Anchorage Alaska 99508 907,333'0364 ) ) 14 1 recent assignment has been Alaska. I've worked nine years in 2 exploration and throughout 12 years in development. Most all 3 of my development experience has been here in Alaska, and I 4 worked Kuparuk, Prudhoe Bay, and most recently Tarn. I've been 5 working on Tarn for the last year. 6 7 CHAIRMAN JOHNSTON: Thank you. COMMISSIONER OECHSLI: No objection. 8 CHAIRMAN JOHNSTON: The commission will accept you as 9 an expert witness..... 10 MR. HASTINGS: Thanks. 11 CHAIRMAN JOHNSTON: .....in this matter. Please 12 proceed. 13 MR. HASTINGS: As Ryan mentioned, we're going to talk 14 about the pool rules, and I'll be talking about pool rules 1 15 and 2 which define the Tarn reservoir both in vertical and 16 areal extent. Some of the information which I'd like to show 17 you has not -- is not a matter of the public record and that 18 material I'd like to show you in private session. And then 19 once we've done that then I'll show the rest of it to the 20 public. 21 CHAIRMAN JOHNSTON: And could you briefly describe 22 without divulging any confidential information what that 23 information would consist of? 24 MR. HASTINGS: Mainly the Tarn wells we drilled in 25 1997. That would be Tarns 2, 3, 3-A, and 4 which are not ELITE COURT REPORTIRG 4051 East 20th Avenue #65 Anchorage Alaska 99508 907'333·0364 ) ) 15 1 public information at this point. 2 CHAIRMAN JOHNSTON: And so you'd be showing us well 3 logs from those wells? 4 MR. HASTINGS: Showing you well logs for those wells as 5 well as 3D seismic information which is proprietary to ARCO. 6 CHAIRMAN JOHNSTON: Okay. The commission has no 7 objections to going into executive session so that we could 8 take a look at this confidential information. I would ask 9 though that well, two things, first that you identify those 10 people in the room that you would feel comfortable having 11 remain in the room. Presumably that would be ARCO personnel. 12 I also notice 13 the Department 14 Would you have 15 room? that there are some state personnel representing of Natural Resources Division of Oil & Gas. any objection for those people to remain in the 16 MR. HASTINGS: No. 17 CHAIRMAN JOHNSTON: And so I'd ask again that you would 18 peruse the room, make -- and verify that there are no people 19 remaining that you feel uncomfortable being in the room. Also 20 when we return from executive session I would ask that you 21 summarize what we talked about, again without divulging any 22 confidential information, but to give a sense of the type of 23 information that we did look at, for the benefit of the public. 25 MR. HASTINGS: Uh-huh (affirmative). CHAIRMAN JOHNSTON: So with that then I would like to 24 ELITE COURT REPORTIRG 4051 East 20th Avenue #65 Anchorage Alaska 99508 907·333'0364 ) ') 16 1 ask those people that are not ARCO representatives or 2 representatives of the Department of Natural Resources if they 3 could step out of the room. 4 (Off record - 9:27 a.m.) 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 ELITE COURT REPORTING 4051 East 20th Avenue #65 Anchorage Alaska 99508 907·333'0364 ), ) 27 1 PRO C E E DIN G S 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 (On record - 9:53 a.m.) 18 CHAIRMAN JOHNSTON: We've just come back from having a 19 short confidential session. This time we are back in public 20 session. I'd like to note that on the record. If we could 21 have the -- you give us a brief summary of what we talked about 22 in the confidential session without necessarily divulging any 23 of the confidential material? 24 MR. HASTINGS: Excuse me. I drank a glass of water. 25 In confidential session we discussed basically how we define ELITE COURT REPORTIRG 4051 East 20th Avenue #65 Anchorage Alaska 99508 907'333'0364 " ) 28 1 the Tarn pool and the five members within it. In particular we 2 know a lot about two intervals which I'll -- the Bermuda 3 interval and the Cairn interval. And our knowledge about those 4 intervals is based on a combination of 3D seismic data which is 5 proprietary, and on four additional wells which are not now a 6 matter of public record. Those wells are Tarn 2, 3, 3-A and 4. 7 It's the integration of that well and seismic data which tells 8 us that we -- which provides the basis for our definition of 9 the Tarn pool, both stratigraphically and aerially. 10 CHAIRMAN JOHNSTON: And the only additional thing I'd 11 like to add there is that you showed us a map showing what you 12 believe this area to look like. 13 MR. HASTINGS: Yes. I'll show you a summary map of 14 that shortly. 15 CHAIRMAN JOHNSTON: Very good. Okay. Please proceed 16 then with your public testimony. 17 MR. HASTINGS: The first slide is Exhibit 1 from the 18 Tarn Pool Rules Application. It's a slide of the log of the 19 Bermuda #1 well which is the type well for the Tarn pool. The 20 Tarn pool on that well is between 5990 the horizon marked 21 C30 and 4376, which is horizon mark C37. That interval is 22 Cretaceous in age, Cenomanian to Turonian, and is 23 stratigraphically equivalent to the Seabee Formation. 24 We believe that the Tarn pool has at least, or has five 25 intervals that comprise it. No one well has all five -- the ELITE COURT REPORTIRG 4051 East 20th Avenue #65 Anchorage Alaska 99508 907'333,0364 ) 29 1 sand in all five intervals in it, but all the five interval 2 horizons 3 The five 4 5 has not are -- the correlative horizons exist in Bermuda #1. I'll describe them in ascending order: The C30 interval is a fine grain, thin-bedded sand. It has been water bearing where we've seen it do date. 6 We believe it's part of the same depositional system as the 7 rest of the Tarn pool. We think that it has the potential to 8 be hydrocarbon-bearing laterally, and we will be looking at 9 that interval as we develop the Tarn pool. 10 The next horizon is the Bermuda interval which lies 11 between T2 and T3. We have a number of reservoir -- well, it 12 lies between T2 and T3 on that log. It's seen in Bermuda #1 13 which you see there. It's also been penetrated in Tarns 2, 3, 14 3-A -- 2, 3 and 3-A. 15 The next overlying interval is the Cairn interval. It 16 lies between T3 and T4 on this type log. We have penetrated 17 reservoir sands in the Tarn 4 well and reservoir potential 18 sands on the West Sak 20 well. 19 As we discussed in private session, the red interval 20 between T4 and T6 and the Iceberg interval which is between T6 21 and C37 are seismic anomalies at this point. We intend to 22 drill wells in 1998 to determine their reservoir potentials. 23 So those five intervals comprise the Tarn pool 24 stratigraphically. 25 The next slide is a map. This is Exhibit 2 ln the Tarn ELITE COURT REPORTIRG 4051 East 20th Avenue #65 Anchorage Alaska 99508 907,333,0364 ) ) 30 1 Pool Rules Application. The blue line on the map is the area 2 of the proposed Tarn pool, and it's highlighted in yellow. The 3 Kuparuk River unit is in the north -- in the upper right-hand 4 corner of the slide or northeast of the Tarn pool. The green 5 blobs are the generalized outlines of the various intervals 6 within the Tarn pool as we define it. Again, the Bermuda 7 interval and the Cairn interval are pretty well known, and 8 we've got several well penetrations within them. 9 And I apologize, on that slide we're missing Tarn 2, 10 which I noticed this morning and I'll have to get that fixed. 11 Iceberg and Arete are shown just north of Bermuda and 12 we know -- we believe that Cairn extends to the south of the 13 Tarn *4 well in an area approximately outlined in green. 14 CHAIRMAN JOHNSTON: Where would Tarn 2 be on that map? 15 Would you point it out, please? 16 MR. HASTINGS: Tarn 2 would be about there on that map, 17 just upper left of the D. I have another map which shows it 18 and I'll show you later. 19 The Tarn sands are marine sands. They are irregular in 20 shape, they are lobate to linear in outline. We know the most 21 about the Bermuda and the Cairn intervals. 22 The Bermuda interval both the Bermuda interval and 23 the Cairn intervals are fine to very fine grain sandstones, 24 they are relatively quartz pore, they contain abundant rock 25 fragments, secondary zeolite cements, and at places calcite ELITE COURT REPORTING 4051 East 20th Avenue #65 Anchorage Alaska 99508 907-333-0364 ') } 31 1 cement. The porosity ranges from 18 to 27% and the 2 permeability averages about 9 millidarcies. There are no fluid 3 contacts that we know of in the Bermuda interval. We've seen 4 no water down-dip and no gas up-dip. 5 In the Cairn interval there is an apparent oil-water 6 contact in the middle of the well, and probably water in the 7 West Sak 20 down-dip. 8 The next slide is Exhibit 3 of the pool rules. It's a 9 structure map on the T3 surface which is the top of the Bermuda 10 interval. The dip of this interval -- and we believe all of 11 the intervals, is to the west -- or excuse me, to the 12 east-southeast. The top of the structure at Cairn 1, for 13 example, is 4750' subsea, and at West Sak 20 the depth is 5700' 14 subsea. It's a pretty regular west to east dip. Faulting is 15 not an important piece of the development of this reservoir. 16 All the faults which you see on the left-hand side of the 17 slides are at the shelf edge, and it's a jumble of slumps and 18 confusion which doesn't -- but the reservoir doesn't descend 19 that far. To the east is a series of echelon faults which are 20 considerably deeper, and they are to the east of the area which 21 we are ready to develop right now, and we don't think those 22 will be an issue for the reservoir either. 23 The next slide is Exhibit 4 from the Pool Rules 24 Application. This is a slide of -- this is a map on the top 25 T4, which is the top Cairn interval, and like the top Bermuda ELITE COURT REPORTING 4051 East 20th Avenue #65 Anchorage Alaska 99508 907·333'0364 } :) 32 1 interval the dip is to the east. The same fault pattern 2 generally shows up. All that confusion off to the west of the 3 reservoir, and the echelon pattern, which lS to the east of the 4 reservoir as we currently understand it. We expect that from 5 our -- that all of the reservoirs will dip from west to east, 6 and that all the traps are stratigraphic, and so the control is 7 on hydrocarbon distribution and basically the controls of sand 8 distribution and fluid contacts if we encounter them. 9 In summary, what I've covered is Pool Rules 1 and 2. 10 Number 1 has been the field and pool name. It's the Tarn Oil 11 Pool of the Kuparuk River Field as defined stratigraphically 12 and aerially. Pool Rule Number 2 is the pool definition. The 13 type log is the Bermuda #1 well, it lies between 4376' and 14 5990' measured depth on the resistivity log from that well. 15 The last thing I wanted to cover was the reserves that 16 we're basing our initial development on: Are all in the 17 Bermuda interval and a portion of the Càirn interval. 18 136 million barrels -- excuse me, it's not the reserves, it's 19 the oil-in-place. We believe there's 136 million barrels 20 oil-in-place, original, in the Bermuda and Cairn intervals, as 21 we understand it today. 22 CHAIRMAN JOHNSTON: And do you have any estimates for 23 the expanded area? 24 MR. HASTINGS: We don't at this point. That concludes 25 my testimony. Are there any questions? ELITE COURT REPORTING 4051 East 20th Avenue #65 Anchorage Alaska 99508 907'333·0364 1 2 3 Thank you. 4 J 33 CHAIRMAN JOHNSTON: Any questions? COMMISSIONER OECHSLI: I don't have any questions. 5 for you right now, although we may have some later on after the CHAIRMAN JOHNSTON: I don't think we have any questions 6 rest of the presentations. 7 MR. HASTINGS: Okay. Thank you. I'll turn it to our 9 8 next, Lamont Frazer. CHAIRMAN JOHNSTON: If you'd please come up. 10 11 12 record. 13 14 MR. FRAZER: Thank you. CHAIRMAN JOHNSTON: And please state your name for the MR. FRAZER: My name is Lamont Frazer. 15 testimony today? CHAIRMAN JOHNSTON: And do you wish to provide sworn 16 17 18 19 20 21 sworn. 22 23 24 MR. FRAZER: Yes, I do. CHAIRMAN JOHNSTON: Please raise your right hand. (Oath administered) MR. FRAZER: I do. CHAIRMAN JOHNSTON: Thank you. Consider yourself Do you wish to be considered an expert witness? MR. FRAZER: I do. CHAIRMAN JOHNSTON: Please state your qualifications. MR. FRAZER: I'm a senior engineer for ARCO Alaska. I 25 graduated from the University of Michigan in 1981 with a degree ELITE COURT REPORTIIfG 4051 East 20th Avenue #65 Anchorage Alaska 99508 907'333,0364 ) ) 34 1 in chemical engineering, and a master's degree from the 2 University of Alaska Anchorage in 1995 in environmental quality 3 engineering. I have over 16 years of production and reservoir 4 engineering experience with ARCO, the last 10 years of which 5 have been in Alaska. 6 CHAIRMAN JOHNSTON: Thank you. 7 COMMISSIONER OECHSLI: No objections. 8 CHAIRMAN JOHNSTON: We have no objections to 9 considering you an expert witness in this matter. If you'd 10 please proceed. 11 MR. FRAZER: Thank you. Before I proceed a question 12 came up earlier during earlier testimony and I wanted to take 13 the time to address that question. And the question had to do 14 with is there a reason to group all of the zones that are 15 currently proposed for the Tarn pool in a single pool. And the 16 question has also come up as to whether our information 17 indicates those zones are currently in hydraulic communication. 18 And the answers are incomplete. Our best information right now 19 is that Bermuda and Cairn are not in hydraulic communication. 20 However, the zones are very tight and they require hydraulic 21 stimulations to produce base or fracture modeling. We expect 22 fracture gross nominally of 200'. Based on this we will put 23 these zones in communication during development operations. 24 Hence, supporting the reason for grouping these in a single 25 pool. ELITE COURT REPORTING 4051 East 20th Avenue #65 Anchorage Alaska 99508 907,333'0364 ) ) 35 1 What I'd like to provide testimony on today is the 2 reservoir development and surveillance portions of our 3 development plan. The four main topics that I'd like to 4 testify on include our reservoir mechanism selection, our 5 development plan overview, our reservoir surveillance plan, and 6 the proposed pool rules that pertain to these sections. 7 with regard to our reservoir mechanism selection, we 8 initially looked at primary recovery, waterflood, lean gas 9 injection, and miscible gas injectant. We were able to quickly 10 dismiss primary recovery. Its production profile declined 11 very, very quickly and it provided a recovery of nominally 10% 12 of the original oil-in-place. They could not compete 13 economically. 14 We then looked at water injection, and one of the 15 problems associated with water injection is potential formation 16 damage. We had concurrent studies going on in our PIano 17 laboratories, looking at potential water damage, and I'd like 18 to quickly show the result from some of that work. 19 This is a slide showing permeabilities of function of 20 injected volume, and this is with a core from the Tarn 2 well, 21 and it shows that initially we started out with a permeability 22 near 5 millidarcies. As we begin to inject water, and we're 23 using a synthetic Kuparuk brine, we very quickly and 24 precipitously decline on the permeability. So formation damage 25 was a concern associated with water injection. ELI TEe 0 U R T R E P 0 R T I R G 4051 East 20th Avenue #65 Anchorage Alaska 99508 907,333·0364 ) 36 1 Another potential concern was the type of rock that 2 we're dealing with in that it's very, very tight. The next 3 overhead that I'd like to quickly show is a 2D cross-section 4 showing the permeability in the Tarn 2-A area. Now this 5 cross-section was prepared stocastically so it's based on 6 geo-statistics, but what it basically shows is a 2D vertical 7 cross-section of the permeability. The blue squares represent 8 1 millidarcy type rock. Green rock is shown with the -- or 10 9 millidarcy rock is shown with the green squares. And the red 10 squares represent 20 millidarcy or greater. The white lines 11 that are replete in this diagram represent transmissibility 12 barriers. And they're representing calcite cementation, mud 13 drapes, things of that nature. 14 The point I want to make here is that there will be 15 extremely tortuous flow path between the injector and the 16 producer. If we were to take the most -- the highest perm 17 layers in this cross-section and look at the average I 18 \ permeability from a flow standpoint where you use a harmonic 19 average to represent series flow, the highest permeability 20 layers are only on the order of 3 millidarcies, from a pressure 21 support standpoint. So providing pressure support will be very 22 challenging for us. 23 Since water has a viscosity that is 25 to 30 times 24 greater than lean gas or MI, using water as an injectant fluid 25 is problematic. Our simulation suggested that it could not ELITE COURT REPORTIRG 4051 East 20th Avenue #65 Anchorage Alaska 99508 907,333,0364 ) ) 37 1 provide adequate pressure support initially. Our rates fell 2 off and the reservoir pressure declined. A corrected measure 3 that could be used for that is to increase the number of 4 injectors relative to producers, and we had limited our model 5 runs to a 1:1 ratio. 6 For simulation purposes we assumed that there would be 7 no formation damage with water and that we could inject 8 1500 psi above parting pressure and not inject out of zone. A 9 very optimistic assumption for the waterflood case. Even using 10 these optimistic assumptions it could not compete with MI based 11 on economics, so we dismissed it. 12 with regard to lean gas injection, we can provide 13 adequate pressure support with lean gas injection. However, if 14 we eventually plan to go to a miscible injectant process, it 15 makes very little sense from a reservoir standpoint to first go 16 with lean gas. What lean gas will do is it will strip the 17 lighter ends from the oil and then when you come back later and 18 try to obtain miscibility, it's harder because you have to 19 re-saturate the oil with the lighter ends that you've just 20 stripped off. So we ended up selecting the MI process based on 21 its rate benefits. We can provide pressure support at a 22 relatively high producer to injector ratio, somewhere between 2 23 to 3. In addition, because of its recovery benefits. And I'll 24 talk about the recovery benefits coming up. 25 We've done slim tube displacements using Tarn oil and ELITE COURT REPORTING 405l East 20th Avenue #65 Anchorage Alaska 99508 907,333'0364 ) ) 38 1 MI, and a slim tube displacement is emulating a 1D flow. We 2 have a 40' cell that is a k" in diameter, and that cell is 4 3 packed with sand and oil. We'll then inject enriching fluid 4 and then measure the oil and gas as they're displaced. What 5 slim tubes are used for is they help us determine the minimum 6 miscibility pressure or MMP, and we do that by varying pressure 7 at a constant injectant composition. We also use them to 8 determine the MME or minimum miscibility enrichment. And we do 9 that by varying the enrichment at a constant pressure. And the 10 utility of that is we can demonstrate that MI can maximize 11 recovery, we can use it to validate our equation of state that 12 we use in our simulation studies, and we also can use it to 13 validate the correlations that we're using to target miscible 14 compositions. 15 This slide represents slim tube results that we've 16 obtained to date for the Tarn oil. It's a plot that shows 17 recovery on the Y axis is a function of "enrichment. And 18 enrichment here is defined as the fraction of KRU-MI. So a .9 19 value represents 90% KRU-MI and 10% lean gas. The triangles 20 represent actual data points measured in the lab, and a 21 standard technique to determine the MME is to draw straight 22 lines through those points, and the intersection represents an 23 MME. So what this slide tells us is that for Tarn the MME is 24 about .88 or roughly .9, so we have 90% MI, Kuparuk MI and 10% 25 lean gas. The green line represents the best fit fluid ELITE COURT REPORTING 4051 East 20th Avenue #65 Anchorage Alaska 99508 907'333·0364 \ J ) 39 1 characterization that we currently have. And we plan to refine 2 that and do some additional work on it, but as it stands right 3 now, it does a fair job predicting miscibility. 4 The next question is how does this tie into improved 5 recovery. with the 2D vertical slice model that I already 6 showed, which represented the Tarn 2 area, we have gone ahead 7 and· run various types of miscibility and non-miscible 8 processes. This represents a lean gas process and also a MI 9 process followed by a lean gas flood -- slug. It shows 10 recovery as a function of hydrocarbon pore volume injected, and 11 we've arbitrarily used a 20% hydrocarbon pore volume slug size 12 for the MI. What it shows is that there is an appreciable 13 recovery benefit with an enriched fluid, and on this particular 14 run it was about 13% incremental increase in OOIP. 15 I wanted to briefly talk about scale-up because we 16 simply cannot take those results as they come out of the 2D 17 simulation and scale them up. We use 2D vertical models and we 18 run them on a quarter pattern or a half-pattern because we're 19 running them fully compositional. And fully compositional runs 20 take an extremely long time. So what we're doing lS we're 21 preparing 2D idealized models, and now we have to we have to 22 correct those models for the aerial components. So what we did 23 is we prepared the 2D vertical slice models for different types 24 of litho facies that we expect to encounter in the Tarn area, 25 and then we said, let's go ahead and prepare what we think is a ELI TEe 0 U R T R E P 0 R T I H G 4051 East 20th Avenue #65 Anchorage Alaska 99508 907-333'0364 ) 40 1 typical pattern configuration. So we made the typical pattern 2 configuration to have a constant permeability. In some cases 3 the injector producer ratios -- or I'm sorry, the injector 4 producer spacings differed because we expect that due to the 5 irregular shapes we have and we also expect to have side tracks 6 that cause irregular spacings in our actual patterns. We ran 7 that with a constant permeability, black oil simulator. We 8 then compared those results to a constant permeability 2D 9 vertical slice model run, and then we were able to describe the 10 pattern inefficiencies using a series of equations. We then 11 applied those equations to our 2D fully compositional runs to 12 make it a 3D simulation. We then took the 3D results, prepared 13 (indiscernible) from those and projected ultimate recoveries 14 and rates. We scaled it up, again, as a function of litho 15 facies and we ended up with an overall recovery factor of about 16 31% of the original oil-in-place, assuming that 20% hydrocarbon 17 pore volume slug size of MI, followed by lean gas. The 18 resultant rate projection, as shown here, -- and this shows oil 19 rate is a function of time, the top curve represents the 20 metered production or gross production that originates from 21 Tarn, and then the green solid line below that represents the 22 actual benefit that the greater Kuparuk area would realize. 23 The reason that there is a gap initially is that Kuparuk is 24 facility handling limited. They have limited compression 25 capacity, and as we -- as Tarn ships them additional gas, they ELITE COURT REPORTIRG 4051 East 20th Avenue #65 Anchorage Alaska 99508 907·333,0364 ) ) 41 1 will have to either reduce lift gas or shut-in wells elsewhere 2 to accommodate that. In addition, Kuparuk is supplying Tarn MI 3 so we are delaying the EOR process at Kuparuk by having that MI 4 shipped to Tarn. 5 CHAIRMAN JOHNSTON: So what governs the shift? That 6 you feel that you're getting more benefit out of using the MI 7 in Tarn than at Kuparuk? 8 MR. FRAZER: The question is what governs the shift? 9 CHAIRMAN JOHNSTON: Right. In other words, why not -- 10 why does Tarn get the MI as opposed to Kuparuk? 11 MR. FRAZER: Tarn would get the MI because it would 12 have the most benefit at Tarn. MI is a suitable injectant at 13 Tarn, and the other fluids, such as water and lean gas, are 14 not, whereas at Kuparuk lean gas and water are more suitable 15 injectants. So they could maintain pressure support and get 16 without the EOR benefit, whereas at Tarn we need the MI to 17 provide pressure support and get the EOR benefit. 18 CHAIRMAN JOHNSTON: And then once you're done with the 19 MI at Tarn or the MI process then that excess MI then would go 20 back to Kuparuk to fully develop those floods? 21 MR. FRAZER: That's correct. In fact what I just 22 showed was a slide assuming that we do not increase our 23 facility handling capacity for MI at Kuparuk, we're currently 24 looking at that and trying to increase our capacity, so the 25 impact that I've shown, we believe, is greater than it will ELITE COURT REPORTING 4051 East 20th Avenue #65 Anchorage Alaska 99508 907·333,0364 ) ) 42 1 actually be. 2 I'd like to now provide testimony on our development 3 plan, and there are three issues I'd like to touch on. The 4 first is to explain why we're going with the phase development 5 plan. The next is to explain our injection management 6 strategy, and finally I'd like to talk about some key well 7 issues. 8 We plan to use a phase development plan to help us 9 eliminate risk at Tarn. The first phase of the project will 10 involve drilling nominally 20 wells sometime between April and 11 the end of this year. In fact we've already started drilling 12 operations. These wells are really targeted for the thickest 13 portions of the reservoir, the best reservoir. And we also 14 plan to test the periphery to help us understand its productive 15 capabilities and whether or not -- or I should say how 16 aggressively we should pursue that in phase 2 of the program. 17 So phase 2 of the program which also involves drilling 18 nominally 20 wells will occur a year later, April through the 19 end of the year '99, and its main intent will be to develop the 20 periphery after we gain some insight due to the first round of 21 drilling. We currently do not have a phase 3 scheduled, but if 22 the existing accumulation is larger than we believe it is, if 23 some of the exploratory work that Doug Hastings mentioned 24 proves successful, then there will be a phase 3. But that's a 25 good phase 3. There's also a bad phase 3, and that is if we ELITE COURT REPORTING 4051 East 20th Avenue #65 Anchorage Alaska 99508 907'333'0364 ) ) 43 1 find, based on the slide I showed earlier of the tortuous path 2 between the producer injector, if we find that our current 3 spacing which is nominally planned for 100 acres, is 4 insufficient to provide pressure support, then the new phase 3 5 would involve in-fill drilling. 6 with regard to our injection management strategy, as I 7 mentioned, we plan to inject MI, and we will certainly not 8 waste the MI and we'll maintain pressure to insure miscibility 9 during MI injection. We'll follow the MI with lean gas, and 10 the purpose of that lean gas flush will be to recover the MI, 11 and our simulation runs during lean gas flush suggests that the 12 gas production will exceed our surface facility injection 13 capabilities so that reservoir pressures may decline during the 14 lean gas flush. 15 One of the keys to managing injection at Tarn will be 16 our well service conversion strategy. It's going to be very 17 difficult for us to predict which wells will gas out first with 18 this type of the depositional setting. Therefore, what we plan 19 to do is minimize the number of injectors initially and then 20 convert wells to injection as needed as they begin to gas out. 21 What that will accomplish is it will improve our sweep because 22 we're letting the reservoir pick our patterns for us and then 23 maximizing sweep from thereon. 24 As far as our long-term injection plans, we haven't 25 finalized those plans. One possibility is that they will ELITE COURT REPORTING 4051 East 20th Avenue #65 Anchorage Alaska 99508 907'333'0364 ) ) 44 1 include some kind of profile modification treatment such as 2 foam or polymer. We also haven't dismissed water. We'll have 3 to better understand the formation damage issues associated 4 with it, and it's a possibility that we will use water in the 5 future. And if it does cause formation damage, and we have 6 swept the zone, then it has benefit as a profile modification 7 agent. 8 The Tarn Development Plan has not yet been optimized. 9 We're currently doing that right now. Some of the things that 10 we really need to optimize include our cumulative slug size. 11 Is 20% optimum or is there a better cumulative slug size than 12 20%. What's the reservoir pressure we should be operating at; 13 should we try to raise it a little bit, should we lower it a 14 little bit. Based on our MME slim tube work we know that we're 15 overly rich on our solvent. Should we use some Tarn lean gas 16 to dilute it a little bit before we inject it so our enrichment 17 level -- we're going to look at that closer. 18 Well spacing. As I mentioned, we're tentatively -- or 19 we're currently planning a hundred acre spacing, but we've 20 arrived at that without taking into consideration the improved 21 continuity that occurs as you tighten the spacing. So we're 22 currently doing some stochastic modeling to tell us whether or 23 not we should tighten our spacing a little bit, improve our 24 continuity, and what is the optimum spacing. 25 And of course we'll have field based optimization ELITE COURT REPORTIRG 4051 East 20th Avenue #65 Anchorage Alaska 99508 907·333'0364 ) 45 1 ongoing, and that will help. And they include pattern 2 configuration. We'll look to see which patterns are gassing 3 out, what the reservoir tells us which well to convert to 4 injection. 5 Well location refinement. We expect surprises. As 6 Doug mentioned, this is a seismic play that we're developing 7 and based on data we've already seen to date we've been 8 surprised. So we'll have to likely have some sidetracks. 9 with regard to well issues, there's a couple key well 10 issues I want to talk about, and they include artificial lift 11 and secondary targets. with regard to artificial lift, we plan 12 to have Tarn wells employing natural flow. The oil gravity 13 being 37° API is very light. In addition, we're not injecting 14 any water. And finally, we're injecting gas, and as it breaks 15 through it will give us in situ gas lift. So we really do not 16 need artificial lift other than natural flow. One exception to 17 that rule, though, will be if we get into areas where we cannot 18 provide adequate pressure support. Despite our best efforts a 19 zone may be -- or an area may be isolated, and it just will not 20 see pressure support. To address those type of situations 22 we've included in the jewelry of our completions profiles such that we can have gas lift, we can have hydraulic lift, we can have plunger lift employed in the future. 21 23 24 We're also looking, right now, at reducing the back 25 pressure at Tarn. We expect our initial back pressure to be in ELITE COURT REPORTING 4051 East 20th Avenue #65 Anchorage Alaska 99508 907·333·0364 ) ) '\ II l 46 1 the 300 psi range, and we're looking at various types of 2 surface facility options to reduce that back pressure. 3 Secondary targets is an interesting topic. As Doug 4 mentioned earlier, there are some thin, marginal opportunity 5 zones such as Iceberg, that fall above Tarn -- or I should say 6 fall above Bermuda. For us to pursue those zones we would like 7 to be able to have the flexibility -- or we need to have the 8 flexibility of not isolating them behind two strings of pipe. 9 And this illustrates what I'm referring to. If we imagine the 10 lower zone to be Bermuda and the upper zone to be Iceberg or 11 some other thin, secondary pay zone, in this case here we can 12 pursue that if we put our annular isolation up high, perforate 13 and fracture, stimulate at a later date. In this case here, 14 because we've put it behind two strings of pipe, we lose that 15 flexibility. 16 Now, another complicating factor is we don't know 17 whether or not these thin, secondary zones are even productive. 18 We do know that they contain insufficient reserves to justify 19 their own wells and they contain insufficient reserves to 20 modify our completion plans. Since we don't plan to have our 21 facilities functional until the August time frame at the 22 earliest, it's likely that we will not know whether these zones 23 can contribute production until that time frame. So for us to 24 maximize the resource and maximize the recovery what we'll have 25 to do is we'll have to set our annular isolation point high on ELITE COURT REPORTING 4051 East 20th Avenue #65 Anchorage Alaska 99508 907·333,0364 ) ) 47 1 those zones where we have these thin, secondary pay zones. 2 The challenge to us is this: If we do set high and we 3 want to use that well in the future for either injection 4 operations immediately, or the well gasses out, and five years 5 down the road we'd like to convert it to an injector, we'll 6 have a case where we'll have annular isolation potentially more 7 than 200' above our perforated zone. And that would happen if 8 we test this zone, we frac it, and then we find it's 9 non-productive. And in the meantime we've drilled three or 10 four wells and we've set annular isolation high, now we know 11 that this zone is non-productive and it's not worth pursuing, 12 yet we're stuck with having annular isolation more than 200' 13 above our perforated interval. 14 Our fracturing models, as I mentioned earlier, suggests 15 that we can fracture nominally 200' above the zone of interest 16 or the zone we're fracturing into, so if they extend more than 17 200' above the Bermuda interval the only way we can pursue 18 those economically is to set the annular isolation point high. 19 I'd now like to provide some brief testimony on our 20 reservoir surveillance plan. We plan to use well tests. Gas 21 samples will be key. We'll use compositional analysis on our 22 gas samples to help us understand the performance of our EOR 23 flood. We'll also use pressure measurements, making sure that 24 things are in pressure communication, ensuring that we are 25 above minimum miscibility pressure. And we'll use surveillance ELITE COURT REPORTING 4051 East 20th Avenue #65 Anchorage Alaska 99508 907·333,0364 ) ) 48 1 logs on a selective basis. We'll use them when we have more 2 than one interval open to production, but surveillance logs 3 which include production injection logs are really going to be 4 of limited utility to us because we do plan to frac our 5 producers so they won't tell us which zone is producing. And 6 those injectors that were previously producers and had been 7 fracked, they won't tell us which zones are accepting 8 injectant. 9 I'd now like to briefly go over the pool rules that 10 pertain to the testimony I've just given, and this is a brief 11 outline of those rules. I'd like to go through them one by 12 one. 13 The first is our proposed Rule 3, and we're proposing 14 to have a minimum spacing of 10 acres. This will give us the 15 flexibility to address reservoir heterogeneities. We do not 16 intend to develop the reservoir on 10-acre spacing, it would be 17 uneconomic. Nominally we're currently planning on hundred acre 18 spacing, but we do need flexibility to address a lot of the 19 uncertainties in the geology that we're faced with. We're also 20 asking that we do not drill any well within 300 feet of a 21 boundary where the ownership changes. 22 with regard to our injection well completion, we're 23 suggesting that we provide at least 200' between the top 24 perforated interval and annular isolation. However, in cases 25 where we attempt to maximize resource recovery and we pursue ELITE COURT REPORTING 4051 East 20th Avenue #65 Anchorage Alaska 99508 907-333'0364 ) ) 49 1 the secondary targets, in those cases we're asking for 2 exemptions to that rule. 3 Our proposed Rule 8, it deals with pressure monitoring. 4 We're proposing that we provide an initial pressure survey on 5 each well; that we provide at least one pressure survey per 6 section annually; that we have a pressured datum that's 5200' 7 subsea, and that the pressure surveys consist of either 8 stabilized static measurements, fall-offs, build-ups, 9 multi-rate tests, drill stem tests, or open hole tests. We're 10 proposing to report these results quarterly, and if we do any 11 kind of special pressure tests, such as pulse testing, 12 interference testing, we also report those on a quarterly 13 basis, too. 14 Our proposed Rule 9, we're asking for a GOR exemption 15 that we don't shut the wells in if they exceed a given 16 producing GOR limit, and this is in accordance with Title 20, 17 Chapter 25, Section 420. We're applying for that given our 18 enriched gas miscible injection process. 19 CHAIRMAN JOHNSTON: What is your original gas-oil 20 ratio? 21 MR. FRAZER: It will be a function of our draw-down. 22 It was measured in Tarn 2 which produced against 500 pounds 23 back-pressure at 1200 scf per barrel. We expect it to be 24 closer to 1500 scf per barrel initially because we reduced our 25 back-pressure to 300 psi. ELITE COURT REPORTING 4051 East 20th Avenue #65 Anchorage Alaska 99508 907·333,0364 ) ) 50 1 Our proposed Rule 10 is that we're proposing that we 2 initiate injection start-up within six months of production. 3 And our proposed Rule 11, we're proposing that we 4 provide an annual surveillance report that will include 5 reservoir management update. It will include a summary of our 6 produced and injected fluids by intervals. It will include a 7 summary of our reservoir pressure analysis, any multi-interval 8 production injection logs that we run. In addition, we're 9 proposing that it include well allocation and well test 10 evaluation verification. And this is consistent with work 11 that's going to be done in Rule 7, which Ryan Stramp will talk 12 about later. And finally it will include any kind of future 13 development plans that we have. 14 That concludes my section of the testimony. Are there 15 any questions? 16 CHAIRMAN JOHNSTON: Why don't you give us a little bit 17 more information on your -- we heard you testify in terms of 18 original oil-in-place. Why don't you give us a little bit of 19 more information on what you expect to recover out of the pool 20 and your basis for that. 21 MR. FRAZER: Right now we expect to recover nominally 22 43 million barrels of oil out of the pool. We recently 23 received a log last week that, although very preliminary, gave 24 us confidence that if anything, the 136 might be on the low 25 side. We have a lot of uncertainty there, but it increased our ELITE COURT REPORTIBG 4051 East 20th Avenue #65 Anchorage Alaska 99508 907'333'0364 ) ) 51 1 confidence that maybe -- maybe it might be on the low side. 2 So if you're asking for what our estimate is, it's 3 42 million barrels the last time we'd done -- had performed the 4 exercise. If we were to perform the exercise again, it might 5 go up slightly. 6 CHAIRMAN JOHNSTON: And in terms of just generalized 7 information on porosity and permeabilities could you indicate 8 what they may be? 9 MR. FRAZER: Yes. Porosities are typically in the 17 10 to 28% range. Permeabilities, they average in the 9 to 10 11 millidarcy range, with the highest perm rock being around 12 40 millidarcies. But because of the way it's distributed it 13 doesn't allow pressure support -- it doesn't provide 9 or 10 14 millidarcy of rock on a pressure support basis. It behaves 15 more like 3 or 4 -- excuse me, 3 or 4 millidarcy rock. 16 CHAIRMAN JOHNSTON: And do you have any thoughts as to 17 why that is? 18 MR. FRAZER: Yes. It has to do with series flow. 19 Whenever you have series flow and you have low permeability of 20 rock distributed with high permeability of rock, the net 21 effective permeability, which we use a harmonic average to 22 determine, will come down significantly and be overly weighed 23 or, I should say, the low perm rock is -- counts for quite a 24 bit of the lowering, more than a simple average would indicate. 25 CHAIRMAN JOHNSTON: In terms of your EOR process, it ELITE COURT REPORTING 4051 East 20th Avenue #65 Anchorage Alaska 99508 907,333·0364 ) ) 52 1 sounds like you're planning on trying to put in a 20% slug 2 size. How long a period of time do you anticipate that it 3 would take to get the 20%? 4 MR. FRAZER: Right now our estimates are between 3 and 5 4 years. The 20% number is our current estimate, and we 6 certainly need to revise that based on whatever optimization 7 tells us, but right now we're planning on 20%. 8 CHAIRMAN JOHNSTON: And then would you, on a well by 9 well basis, after you've injected sufficient MI in a particular 10 well to acquire that 20% within that general area, would you 11 then immediately go to a lean gas chase or would there be a 12 period of time that you would sit and evaluate and..... 13 MR. FRAZER: We only have one injection line currently 14 supplying us injectant from Kuparuk, so unless we increase our 15 facilities, we'll have to decide overall at that time whether 16 or not it's time to change injectant. 17 CHAIRMAN JOHNSTON: So basically at this point you'd 18 have to complete the MI entirely and then move to a lean gas 19 chase? 20 MR. FRAZER: Unless we were to install an additional 21 injection line, that's true. 22 CHAIRMAN JOHNSTON: And have you looked at that in 23 terms of optimizing development; is there any detrimental 24 effect of waiting until the MI flood is entirely done before 25 you move to lean gas chase or is there a benefit to moving with ELI TEe 0 U R T R E P 0 R T I B G 4051 East 20th Avenue #65 Anchorage Alaska 99508 907,333'0364 ) ) 53 1 lean gas chase as soon as you can in a particular injector? 2 MR. FRAZER: That falls into the optimization that we 3 haven't really gone through yet. 4 CHAIRMAN JOHNSTON: In terms of your written testimony 5 that was submitted, I was noticing -- and if you're not the 6 person to answer this, that's fine, we can wait and address it 7 with another person -- but I'm seeing here on your casing 8 proposal, one of your plans is to set your surface casing to 9 almost right above the pool. But I'm not seeing that in that 10 scenario that you're proposing, cementing the surface casing 11 from top to bottom. 12 MR. FRAZER: Commissioner, can I defer that to 13 Fred Johnson who will speak next? 14 15 then? 16 17 CHAIRMAN JOHNSTON: That will be fine. Any questions COMMISSIONER OECHSLI: No, I don't have any. CHAIRMAN JOHNSTON: Okay. At this time we don't have 18 any further questions, but may have some later on. Thank you. 19 MR. FRAZER: Thank you. 20 CHAIRMAN JOHNSTON: If you'd state your name for the 21 record, please. 22 MR. JOHNSON: My name is Fred Johnson. 23 CHAIRMAN JOHNSTON: And I assume you wish to give sworn 24 testimony today? 25 MR. JOHNSON: Yes, sir. ELITE COURT REPORTING 4051 East 20th Avenue #65 Anchorage Alaska 99508 907'333'0364 1 2 3 4 5 sworn. 6 7 8 ) ) 54 CHAIRMAN JOHNSTON: Please raise your right hand. (Oath administered) MR. JOHNSON: I do. CHAIRMAN JOHNSTON: Thank you. Consider yourself Do you wish to offer expert testimony? MR. JOHNSON: Yes, sir. CHAIRMAN JOHNSTON: Please state your qualifications. 9 chemical engineering from Ohio State, received that in 1974. MR. JOHNSON: I hold a bachelor of science degree in 10 Worked seven years with Texaco in reservoir engineering, 11 production engineering and drilling engineering type positions. 12 In the last 15 years I've worked with ARCO. Eight of the last 13 15 years have been up in Alaska in drilling, completion work or 14 other type operations. 15 16 17 CHAIRMAN JOHNSTON: Thank you. Any objection? COMMISSIONER OECHSLI: No. CHAIRMAN JOHNSTON: The commission will accept you as 18 an expert witness in this matter. Please proceed. 19 20 testimony to support and explain our well designs and drilling MR. JOHNSON: My intention today is just to offer some 21 operations at Tarn for development. 22 As you're aware, ARCO has quite a history of 23 operational experience up on the Slope in development 24 operations, and I guess what we feel we have here is a pretty 25 sound, basic development plan on well design for the Tarn ELITE COURT REPORTIRG 4051 East 20th Avenue #65 Anchorage Alaska 99508 907·333'0364 ) ,) 55 1 development. As such, we're going to be operating within all 2 the present existing regulations of the oil and Gas Commission, 3 and we'll meet all of ARCO's requirements for completing the 4 reservoir. 5 And where is our pointer. Most of my talk, I guess, is 6 going to be based on the well construction here initially. 7 What we show up here on the overhead are the well designs. As 8 proposed now primarily we're looking at monobore type 9 completions for both the production wells and the injection 10 wells. And the only difference between the well on the right 11 and left is the size of the hole in the tubular plan. The well 12 on the right is a little larger. We'd call that our 13 conventional monobore completion, versus the one on the left 14 which is our slim hole monobore. The one on the right would 15 have 12~" surface hole, an 8~" production hole, correspondingly 16 95/8" surface casing in a tapered production casing string, 7" 17 tapered down to 4~. That well -- that design would be used 18 primarily for wells that had higher departure, required 19 stronger tubulars to drill or higher rate requiring 4~ tubing. 20 The well on the right, the slimhole monobore completion 21 comes out of earlier Kuparuk work to primarily reduce well 22 construction costs. The same principle here in the monobore 23 design, monobore being defined as having a common ID through 24 the tubing and casing interval through the pay zone. The 25 advantages that we see of a monobore design from a reservoir ELITE COURT REPORTING 4051 East 20th Avenue #65 Anchorage Alaska 99508 907·333·0364 ) ) 56 1 management aspect is the ability to profile modification or 2 zonal control, being able to mechanically set patches through 3 the common ID to block off certain intervals of the 4 perforations. 5 Operationally and mechanically we see it simplistic in 6 that it is reducing -- eliminating one of the leak paths of a 7 completion, while wells -- injection wells do require tubing in 8 a packer. What we're proposing here is the tubing and a seal 9 bore, eliminating the packer and eliminating the external leak 10 path of a production packer. 11 The injection wells and producing wells are the same 12 design, and that's due a lot to a great extent from Lamont's 13 comments there again that due to the unknown nature of the 14 reservoir here we feel we would need to be able to convert 15 wells from producers to injectors at a time in the future or 16 pre-produce injectors that are initially drilled as a surface 17 well. Mechanically, at the top of the well we will be dealing 18 with 5000 psi wellhead and Christmas tree assemblies. 19 Reservoir pressure is approximately 2500 psi, but the 5000 20 pound equipment will be adequate for the injection purposes. 21 The two rules that I will be discussing here affect the 22 cas1ng and cementing practices and safety shut-in equipment. 23 And what we're proposing for the Tarn casing and cementing 24 rules is to utilize the existing AOGCC regulations and the 25 current Kuparuk Field rRles. So we're sending a conductor 75' ELITE COURT REPORTING 4051 East 20th Avenue #65 Anchorage Alaska 99508 907·333·0364 ) ) 57 1 below ground level. The purpose of the conductor being to 2 provide anchorage for the diverter system while drilling the 3 surface hole. And our surface casing is planned to be set 500' 4 measured depth -- a minimum of 500' measured depth below the 5 base of the permafrost. Again, for well control purposes, 6 containing or supporting our BOP equipment and also to support 7 our annular pumping activity. 8 You had asked the question earlier, Commissioner, about 9 a certain type of well that we had proposed in our testimony. 10 This diagram is going to vary perhaps a little bit from what 11 you've been given in the initial testimony here. This well we 12 would call our possible tubulus monobore completion. And what 13 we're proposing here is to set the surface casing deep, and as 14 it is surface casing, present guidelines are that surface 15 casing needs to be cemented to the surface. We do show a 16 complete cement column there. That would be one of the 17 challenges of trying to institute this type of well design. I 18 guess what really drives this type of tubingless monobore 19 design is to allow this well to be an injector. I think we can 20 permit tubingless monobore producers where the surface casing 21 could be up at its shallower depth. At that point we'd be 22 challenged to just permit that well as an injector. Again, the 23 motivation for this again is to reduce well construction costs. 24 But we do recognize the need for the surface casing cementing. 25 I get to backup and start all over again. We have ELITE COURT REPORTING 4051 East 20th Avenue #65 Anchorage Alaska 99508 907·333,0364 ) ) 58 1 started the Tarn development drilling program. We did mobilize 2 the Doyon 141 rig to the two-end Tarn Development Pad about 3 April 10. We completed our first well the 24th of April and 4 we're presently drilling on our second development well. The 5 drilling rig will be both drilling and completing the wells. 6 While we're showing these, it's the typical completion 7 designs that we initially are installing. We will be reviewing 8 other type of well designs, open hole completions, use of 9 slotted liners, horizontal completions and horizontal wells if 10 we can determine their benefit, multilateral type completions, 11 if circumstances develop where we can apply those type of more 12 newer and more novel completion designs. I guess I'd say this 13 is our phase design right now which we'll probably be sticking 14 to for the first phase of the Tarn development work. 15 They are pretty simple completions. There is tubing 16 completion with a minimum amount of jewelry. We do have, as 17 you can see there, a gas-lift mandrill above our tubing casing 18 sealbore. The mandrill is used for either circulating fluids 19 or perhaps for single point injection if at sometime in the 20 future we do need to gas-lift. We also show a sliding sleeve 21 in the tubing completion. The purpose of that primarily would 22 be for to institute a couple of different type of hydraulic 23 lift mechanisms. 24 In drilling operations, blow-out prevention, safety is, 25 of course, our primary guidance out there, of very much concern ELITE COURT REPORTING 4051 East 20th Avenue #65 Anchorage Alaska 99508 907·333,0364 } ) 59 1 to us. We are utilizing a diverter on our surface hole 2 drilling, a 5000 psi blow-out preventer while drilling a 3 production hole and completing the wells. As part of our well 4 construction activity we will be trying to permit the wells in 5 the APD process for annular disposal of waste drilling fluids. 6 We'll be meeting with the commission in a separate meeting to 7 review that. 8 Other options, annular disposal, and what we're doing 9 right now is hauling waste mud off of the Tarn pad to a class 2 10 disposal well in Kuparuk. Another option would be to drill a 11 dedicated class 2 disposal well at one or two of the Tarn 12 sites, if that was the efficient thing to do. 13 We have to review the wellhead and production tree, a 14 5000 psi working pressure. These wells are drilled from pads 15 so they're all directional wells. They're all relatively high 16 angle wells. We will be utilizing MWD surveys for the 17 directional drilling control, and those "will be used as the 18 definitive survey. 19 In these designs to allow these wells to be injection 20 service wells, we do have the ability to do MIT or mechanical 21 integrity tests on a monthly basis, and that's going to be 22 accomplished by pressuring -- the tubing is sealed off in this 23 seal bore receptacle here, and we would be monitoring the 24 annular pressure between the tubing and our production casing 25 annulus. It's very similar to a tubing packer type of setup ELITE COURT REPORTING 4051 East 20th Avenue #65 Anchorage Alaska 99508 907·333·0364 ) } 60 1 here. 2 The point that Lamont was making, again, has to do with 3 where when we run our production casing and design the string, 4 where do we select this crossover point to our tapered 5 production casing, and that -- we do have shallower pay 6 intervals up here. We would be wanting to be able to move that 7 profile up to be able to access shallower reserves without 8 re-completing the well. 9 Another rule that I guess I'm going to address now is 10 our automatic shut-in equipment. Consistent with the statewide 11 Oil & Gas Commission regulations and the current KRU field 12 practices, there's no apparent need for subsurface safety 13 valves in the Tarn development, and so we have not included 14 those in our well completion designs. We will be installing 15 fail-safe surface safety valves. This shows up as the upper 16 master valve in our Christmas tree assembly. Since we have our 17 wellhead -- two spool wellhead assembly here and we move up 18 into our tree assembly -- whoops, I'm wandering all over the 19 place here manual master valve. And up here is our ,20 fail-~afe, high-low pressure monitoring surface safety valve as 21 the upper master valve. These will be on both our producers 22 and our injectors. 23 A couple of other drilling issues as far as our 24 drilling permit activity here is trying to, I guess, get a 25 development waiver for hydrogen sulfide, H2S contingency ELITE COURT REPORTING 4051 East 20th Avenue #65 Anchorage Alaska 99508 907,333·0364 ) ) 61 1 planning for the development. We've drilled four exploration 2 wells, one development well to date and we haven't detected any 3 H2S concentrations throughout the interval we drilled. So we 4 would be trying to ask for regulations due to the absence of 5 hydrogen sulfide, eliminate that from our permit process until 6 a need would arise. 7 Our data gathering requirements, initially these are 8 all high angle wells, LWD. We do plan to do all our logging 9 primarily with LWD supplemented in a few wells with wireline 10 logging, so we do see a need to request an exemption from some 11 of the data gathering required in the regulations for logging 12 surface holes, mud logs and sample requirements. Initially 13 we're taking a pretty extensive data gathering suite with LWD 14 to include gamma ray resistivity and neutron density porosity 15 logs. We would hope in an effort to reduce data gathering 16 costs in the future to maybe slim that down a little bit, but 17 we're needing to run the logs required for us to fully identify 18 the reservoir. 19 And that's all I have to present. Do you have any 20 questions? 21 CHAIRMAN JOHNSTON: I think you probably answered the 22 one question that I wanted to ask relative to the casing 23 design. And I appreciate your comments there. So any 24 questions? 25 COMMISSIONER OECHSLI: No questions. ELITE COURT REPORTING 4051 East 20th Avenue #65 Anchorage Alaska 99508 907·333,0364 ) ) 62 1 2 3 4 close MR. JOHNSON: Thank you. CHAIRMAN JOHNSTON: Thank you. MR. STRAMP: Again, my name is Ryan Stramp, and I'll out the testimony this morning, first by going over some 5 issues related to our surface facilities and then with some 6 closing comments. 7 This slide just has a brief summary of the scope of our 8 Tarn specific facilities that have largely -- many of these 9 have been installed already. A gravel road extending from 10 drill site 2M -- here's a map. I don't have a copy in your 11 slide packet, but just for orientation. again. We're coming off 12 of drill site 2M, which is an existing Kuparuk drill site, and 13 heading out to Tarn, and it's about seven miles to drill site 14 2L which is the northernmost drill site, and about another 15 three miles due south to get to drill site 2N. So we've got a 16 road that goes out to both drill sites and VSM supporting two 17 pipelines, a 16" production line and an 8" injection line. 18 There's an overhead powerline that goes from 2M to the 19 northernmost drill site, which is about seven miles, and then 20 we have buried powerline in the road between the two drill 21 sites for the run from to 2L to 2N, and obviously as it's shown 22 on the map, we have two new drill sites constructed for Tarn. 23 We'll zoom in a little bit on what we have in terms of 24 on-pad facilities. We're pursuing a trunk and lateral 25 manifolding scheme similar -- somewhat similar to West Sak. ELITE COURT REPORTING 4051 East 20th Avenue #65 Anchorage Alaska 99508 907·333·0364 ) ) 63 1 Our initial well spacing will be 30' , although we will have the 2 capability to go to 15' -- IS' well to well spacing ln the 3 future. We will be using the Accuflow well test equipment 4 which I'm sure you remember from the West Sak testimony. We 5 also will have the ability to remotely control switching wells 6 in and out of test, as well as remotely control the chokes on 7 the injection and producing wells. As you saw from the map, 8 it's a ways out there to get to Tarn, and we intend to rely 9 upon remote control, to a large degree, than a typical Kuparuk 10 drill site to help offset some of that distance. 11 Other facilities on the pad include an ESD skid. It 12 will enable us to remotely shut down production and/or 13 injection operations as well as a small actual control room to 14 house the electrical gear. 15 In the packet I've got a slide that is the pad layout 16 for our southernmost drill site, 2N, which is where the 17 drilling rig is currently located. You can see the 18 configuration with a long single row of wells. Each of those 19 individual wells is shown on 15' spacings. I mentioned the 20 initial drilling will take place only at every other slot shown 21 here. The area back here behind the wells is the pipe rack 22 where the trunks will run, laterals will run from the wells, 23 actually to the trunks and even back behind them a little bit. 24 I'm having a hard time getting oriented upside down here. But 25 one kind of unique design that we're implementing is these ELITE COURT REPORTING 4051 East 20th Avenue #65 Anchorage Alaska 99508 907'333·0364 ) ) 64 1 little boxes that are shown behind the trunk are actually where 2 our chokes are going to be for the operators to operate the 3 wells. So the main operator interface is going to be along the 4 back side of the well or of the pad here. 5 You can see the limited additional surface facilities; 6 the Accuflow meter skid is labeled there as 2N-Ol, and the ESD 7 shelter is 00, and then the other piece of equipment out there 8 is the electrical control room, which is the 02 module. So 9 it's pretty simple and straight-forward. That's one of our 10 goals. And we're moving ahead, like I said, with drilling and 11 construction on this pad right now. 12 A quick review ,of some of the issues associated with 13 the Accuflow well testing equipment. It's not a conventional 14 vessel separator, it relies upon a piping configuration to 15 separate liquid and gas. We then meter the total liquid using 16 a mask flow meter, a water cut and a liquid using a phase 17 dynamics meter and a gas using vortex shutting meters which 18 these metering devices are all presently in use at Kuparuk on 19 more conventional type test separators so that metering devices 20 themselves are not new. What is new is using the Accuflow 21 separation vessel instead of a conventional separator vessel. 22 A couple of the benefits are rapid well stabilization 23 because this system has a very low differential pressure 24 whenever wells are switched in, as well as a small volume. So 25 pre-existing fluids are quickly flushed out of the system so ELI TEe 0 U R T R E P 0 R T I H G 4051 East 20th Avenue #65 Anchorage Alaska 99508 907·333,0364 ) ) 65 1 you can get back to -- or get down to metering the fluids from 2 the well you're testing, and also because of the low Delta P 3 I across the separator, the test conditions vary only to a minor I 4 degree from normal operating conditions. 5 And that leads us to our proposed Rule 7 which has to 6 do with commingling of production. In this rule we would seek 7 to have approved the surface commingling of Tarn with other 8 Kuparuk production. Similar to West Sak, we feel that use of 9 the Accuflow test system, plus the fact that we're only 10 metering oil and water here or excuse me, oil and gas, no 11 water is involved, supports that our well tests should be of a 12 relatively higher degree of accuracy than a typical Kuparuk 13 test, and would like to see a real similar to West Sak received 14 to try an allocation factor of 1 for allocating between cools, 15 of course subject to review with the commission to see if that 16 looks like it's working appropriately at the end of the year. 17 We're very comfortable with two well tests per month, 18 particularly with our initial well count as we increase the 19 number of wells on these pads. Hopefully from the good type of 20 phase 3 drilling that Lamont talked about with adding the area 21 that we're developing, our well counts could get to the point 22 that getting two tests per producer per month could be 23 challenging, but we'll cross that bridge when we come to it. 24 And we, of course, recognize that the commission will be 25 monitoring the test data and allocation data and we'll be ELITE COURT REPORTING 4051 East 20th Avenue #65 Anchorage Alaska 99508 907·333'0364 ) ) 66 1 willing to adjust the requirements as you see fit. 2 We have two final proposed rules, Rule 12 has to do 3 with production anomalies, and that primarily has to do with 4 pipeline proration events. In the event of the pipeline 5 proration our initial goal is to try to cut all pools by equal 6 percentages, however, there are some instances where that may 7 result in increased cost and/or damage to equipment, and we 8 wanted to get that explicitly recognized in the rules. 9 And then the final rule is Rule 13, which has to do 10 with the commission retaining authority to administratively 11 amend the rules. 12 That's the conclusion of the main part of our 13 testimony. I've got a few brief closing comments, but we can 14 get any more questions now, we can do that or I can close 15 things out. Your choice. 16 CHAIRMAN JOHNSTON: Why don't you go ahead and wrap 17 things up. 18 MR. STRAMP: One quick administrative issue, and that 19 is the packet of handouts or slides that we showed today, we 20 would like to be sure are submitted as exhibits for the public 21 record, and you could label those Exhibit 12, if you'd like. I 22 think we had 11 main exhibits in the written application, 23 including the agreements that we provided. 24 CHAIRMAN JOHNSTON: Right. 25 MR. STRAMP: So we'd like to have those entered in. ELITE COURT REPORTING 4051 East 20th Avenue #65 Anchorage Alaska 99508 907,333·0364 ) ) 67 1 Although we've talked a lot about Tarn development being on a 2 fast track for the past year, and it has, we want to ensure 3 that everybody understands that our highest priorities are 4 still associated with being sure that these construction and 5 drilling operations in the ultimate production and maintenance 6 operations are conducted in safe and environmentally sound 7 manners. As Fred mentioned, our drilling program meets or 8 exceeds all requirements that are specified, and similarly our 9 facility construction designs meet or exceeds standards 10 specified by national codes or recommended by organizations 11 or -- and definitely they take into account our time proven 12 practices that we've established over years of operations on 13 the Slope. 14 Another point to make is that from an environmental 15 standpoint using the existing Kuparuk infrastructure to process 16 our fluids and supply injectant not only is the most economic 17 option for us, I think it's the most environmentally sound way 18 we could proceed with this as well. You've heard about many 19 challenges that we have ahead of us with developing the Tarn 20 pool. It's relatively tight. Lamont talked about the tortuous 21 paths between injectors and producers. Doug talked about the 22 complex geologic architecture we're dealing with. And we feel 23 that our plans are flexible enough to effectively overcome 24 these. The phase development, heavy reliance upon seismic, a 25 lot of contingency planning. You know, we talked about being ELITE COURT REPORTIRG 4051 East 20th Avenue #65 Anchorage Alaska 99508 907,333,0364 ) ) 68 1 able to convert wells to injectors later on in the program are 2 going to be very important for us to be able to effectively 3 manage this resource. 4 The cornerstone of our development plan is employing 5 tertiary recovery process using miscible injectant from the 6 beginning. Our studies shows that this use of enriched gas 7 from day one will largely mitigate the effects of the tight 8 reservoir and the tortuous paths and result in ultimate 9 recovery of the maximum number of reserves which is something 10 that we're all after. 11 The pool rules that we've proposed don't deviate far 12 from the typical statewide rules. Two that maybe are 13 noteworthy are deviations for well spacing and GOR limits. As 14 Lamont mentioned, you know, certainly it's in our economic 15 interest to minimize the number of wells that we drill, but 16 there may be instances that we end up desiring wells on well 17 spacing and having the well spacing requirements set to 10 18 acres will minimize the administrative burden of permitting 19 those wells. And the GOR production limit, I think, is an 20 obvious outfall of our recovery process. 21 We've talked quite a lot about well testing, or at 22 least I have here at the end because we are going to be 23 commingling pools. We feel the Accuflow meter is an excellent 24 device for this application and it will give us a larger number 25 of higher quality tests than we could otherwise get, and we ELITE COURT REPORTING 4051 East 20th Avenue #65 Anchorage Alaska 99508 907,333'0364 , ) 69 1 feel like it's a perfect choice for this application. 2 We look forward to working closely with the commission 3 \ as we move ahead with development and further exploration. 4 There are lots of challenges out there, but it's a great 5 opportunity to learn, and I'm sure that as we learn we'll be 6 able to apply those lessons at Tarn and other satellites in and 7 around Kuparuk and across the North Slope. 8 That's the end of what I have to say. We'd love to 9 entertain any questions you might have. 10 CHAIRMAN JOHNSTON: Okay. What was your plan here on 11 the area injection order? 12 MR. STRAMP: We've got a separate, brief set of -- or 13 two -- basically two presenters that will give very brief 14 testimony that will supplement the written application, and we 15 can go ahead and move right into that if you'd like. 16 17 take? 18 19 20 CHAIRMAN JOHNSTON: How long do you think that will MR. STRAMP: Fifteen minutes. MR. FRAZER: Twenty minutes maybe at most. CHAIRMAN JOHNSTON: Why don't we just take a short five 21 minute break right now then and come back and hit the area 22 injection order testimony and then try and wrap this up this 23 morning. 25 MR. STRAMP: Okay. That's fine. (Off record - 11:10 a.m.) 24 ELI TEe 0 U R T R E P 0 R T I R G 4051 East 20th Avenue #65 Anchorage Alaska 99508 907,333'0364 ) 70 1 (On record - 11:17 a.m.) 2 CHAIRMAN JOHNSTON: If we'll all take our seats, 3 please. Can we shut that door over there as well? Thanks. 4 Before we jump into the area injection order aspects of 5 the hearing, I'd like to ask one question having to do with the 6 use of water for EOR processes. What's actually going on there 7 that -- what's your speculation as to why water is not an 8 effective recovery fluid? 9 MR. FRAZER: The work we've done to date..... 10 CHAIRMAN JOHNSTON: If you could step up and talk into 11 the mic there? That would help. 12 MR. FRAZER: Certainly. The work we've done to date 13 suggests that water induces finds migration. 14 CHAIRMAN JOHNSTON: Finds migration. 15 MR. FRAZER: And that's the cause of the formation 16 damage. 17 CHAIRMAN JOHNSTON: Okay. Great. Thank you very much. 18 MR. FRAZER: Sure. 19 CHAIRMAN JOHNSTON: So we can proceed with the 20 elements of the area injection order. 21 MR. HASTINGS: Right. And I'm Doug Hastings and I'll 22 introduce and do part of this, and then Lamont Frazer will 23 finish. 24 CHAIRMAN JOHNSTON: Excellent. 25 MR. HASTINGS: And -- well, that's where we are, the ELITE COURT REPORTING 4051 East 20th Avenue #65 Anchorage Alaska 99508 907·333·0364 ) ) 71 1 Tarn Injection Order Hearing. We have -- there are the 2 regulations, the state regs, there's 20 AAC 2S.402(c), that's 3 pretty good, 14 requirements for an area injection order, and 4 we've covered four in the pool rule hearing that we just 5 completed, and we'll cover the additional 10 in this current 6 testimony. 7 The four that we've covered are discussion of the 8 proposed operation, depth and name of the affected pool. That 9 would be the Tarn Pool of the Kuparuk River Field. Casing and 10 testing methods for injectors, and the incremental increase in 11 ultimate recovery. 12 CHAIRMAN JOHNSTON: Why don't -- I know it appeared in 13 your written testimony, but I don't think we got it on the 14 record in terms of what is your incremental? We talked about 15 the original oil-in-place, what you expected to recover, but 16 there was no statement as to what you would expect just on 17 primary. 18 MR. FRAZER: Our primary recovery is estimated to be 19 approximately 10% of the original oil-in-place, and our 20 enhanced oil recovery project with MI first is estimated to 21 have about 31% incremental I should say percent original 22 oil-in-place recovery, and then with lean gas by itself the 23 total recovery is about 20% of the original oil-in-place. So 24 it's an incremental 20% of the original oil-in-place, more than 25 primary, and approximately 10% of the original oil-in-place ELI TEe 0 U R T R E P 0 R T I R G 4051 East 20th Avenue #65 Anchorage Alaska 99508 907,333,0364 ) ) 72 1 more than lean gas injection. 2 CHAIRMAN JOHNSTON: Okay. So when you say with MI, 3 that also anticipates lean gas after the MI? 4 MR. FRAZER: Yes, it does. 5 CHAIRMAN JOHNSTON: Thank you. 6 MR. HASTINGS: Well, let's see, the areas we'll cover, 7 the additional 10 regulations are listed here, and I'll move 8 again to cover them in order. The slide which is up now is 9 actually Attachment I-A of the area injection order. It's-- 10 again, it's a map of the Tarn pool. 11 The Tarn pool outline on that slide is the heavy blue 12 line. All of the Tarn pool accumulations are shown there. The 13 red outline is the area that we're requesting the injection 14 order for. That's a smaller area and covers the Bermuda and 15 part of the Cairn interval, and as I'll show you in a minute, 16 stratigraphically we're only requesting injection operatings in 17 the Bermuda and Cairn intervals. The existing penetrations 18 within a quarter-mile of that are the open dots on this map. 19 That would be the Bermuda *1 well, Tarn *1, Tarn *2, Tarn i3, 20 Tarn #3-A, and Tarn i4. 21 Also shown on the map in blue triangles and diamonds 22 are the injectors and producers that we plan to drill in phases 23 1 and 2. The pattern is -- well, that's what's on the map. 24 The operator in the area will be ARCO Alaska, the 25 surface owner is the State of Alaska. We have notified the ELI TEe 0 U R T R E P 0 R T I R G 4051 East 20th Avenue #65 Anchorage Alaska 99508 907-333'0364 ) ) 73 1 DNR, the state agency, the representative of the State of 2 Alaska, on April 27, which was yesterday, April 27, 1998. This 3 is the -- the slide here is actually Attachment 7 of the Area 4 Injection Order Application. It is the type log for the Tarn 5 pool, and highlighted in yellow are the Cairn interval and 6 Bermuda interval which are the intervals we propose for 7 injection. a The next slide is Attachment 11-A from the application. 9 It's the Bermuda log again but it extends higher up in the 10 section. The Tarn pool at its shallowest is marked by the C37 11 marker on there at about 4375'. The Tarn pool is separated 12 from the C80 or Colville sands, or in this case the Tabasco 13 interval by about 17 to 1800' of shales which makes it very 14 adequate containment zones for any operations, separating Tarn 15 from the next highest hydrocarbo- bearing zone or potentially 16 hydrocarbon-bearing zone that we're aware of. 17 18 be? 19 20 4376. 21 CHAIRMAN JOHNSTON: And between what depths would that MR. HASTINGS: cao in this case is about 2600'; C37 is CHAIRMAN JOHNSTON: And the shales that you seek are 22 regionally extensive? 23 MR. HASTINGS: Yes. That zone between -- especially -- 24 well, C37 and about a hundred feet higher than that and C80, I 25 can map from Alpine area all the way across the Kuparuk. ELI TEe 0 U R T R E P 0 R T I B G 4051 East 20th Avenue #65 Anchorage Alaska 99508 907·333'0364 ) ) 74 1 The next slide is Attachment ll-C from the Area 2 Injection Order Application. We may want to inject fluids into 3 a dedicated injection well or dedicated injection zone, and at 4 this point we're proposing that the Ivishak sandstone be that 5 zone. This is a log of the Sinclair Colville #1 well. There 6 are several. If there are scattered well penetrations in the 7 area, including the Union Kukpuk, the ARCO Kiluck River well, 8 the Sadlerochit here lies at about 8500' -- excuse me, about 9 8000 to 8500 feet subsea. We expect to have at least 60' of 10 porosity greater than 15% will make a suitable injection zone. 11 There are no hydrocarbons -- these are not hydrocarbon-bearing 12 zones or it doesn't bear hydrocarbons here on the basis of a 13 number of old but, you know, unfortunate exploration wells. 14 It's separated by the closest overlying hydrocarbon-bearing 15 zone which would be the Kuparuk by. at least 1800' of Kingak 16 shale and the Sag at Chublik -- Sag and Chublik here have also 17 not been shown to be hydrocarbon-bearing. 18 CHAIRMAN JOHNSTON: And, again, if you'd give me the 19 depths on that? 20 MR. HASTINGS: Kuparuk here is at about 5900' measured 21 depth. The Sag River sandstone begins at 7700' measured depth 22 on that log. The top of the Ivishak is about 8000' measured 23 depth -- excuse me, about 8050, and the base is at about 8630 24 measured depth. We're off-structure here and we don't expect 25 it to bear hydrocarbons, and it should be a suitable zone for ELITE COURT REPORTING 4051 East 20th Avenue #65 Anchorage Alaska 99508 907·333'0364 " ) 75 1 injectant. 2 Water analysis. We have spin-outs from several core 3 plugs plus a little water extracted from the drill stem test, 4 and on the basis of that analyses, the total dissolved, all its 5 content of the Tarn waters is 30,000 parts per million 6 approximately. 7 Finally, this map is Attachment 13-A from the Area 8 Injection Order Application. It's a map which shows the 9 Kuparuk River Unit outline in blue. The proposed injection 10 area in red -- hatchered red. The black line is an aquifer 11 exemption which was granted in 1983 by the EPA. All the area 12 inside of that was -- we were granted an aquifer exemption for 13 injection near fresh waters, and as that was defined, that 14 effectively is the West Sak and Ugnu zones. 15 CHAIRMAN JOHNSTON: I don't recall, did you provide us 16 a copy of the fresh water exemption? Do you recall if you did 17 in your application? I don't believe you did. 18 MR. HASTINGS: No. 19 CHAIRMAN JOHNSTON: We would request that you get a 20 copy of that over as part of your application. 21 MR. HASTINGS: Yes, we can provide that. If there 22 are -- are there any questions? That ends my portion of this 23 testimony. 24 CHAIRMAN JOHNSTON: Okay. Nothing at this time. 25 MR. FRAZER: Again, my name is Lamont Frazer, and I'm ELITE COURT REPORTIRG 4051 East 20th Avenue #65 Anchorage Alaska 99508 907'333'0364 ) 76 1 going to briefly discuss the last three items on this list. 2 They include the injection fluid data, estimated injection 3 pressures, and evidence of injection confinement. 4 with regard to the injection fluid data, we are asking 5 to inject MI and lean gas into the Bermuda interval and the 6 Cairn interval, and this is the composition that existed at 7 CPF-2 in late '97 of those two fluid streams. 8 With regard to estimated injection pressures, we expect 9 to have injection pressures between 27 and 3700 psi, with the 10 most likely pressures being 3300 psi, plus or minus 200 psi. 11 In terms of evidence of injection confinement we use 12 stirn plan which is a Nolte Smith quasi-3D model to design or 13 look at various types of fracture height growth. And we ran a 14 case for a 10 million a day MI injection rate and lean gas 15 injection rate with a 3500 psi surface injection pressure. And 16 what we found is that there was no height growth whatsoever 17 into either the confining zones above or below the Bermuda 18 interval. We also ran stirn plan with a typical series of 19 various types of fracture treatments. And what we found is 20 that typically we can expect to have about 200' of upward 21 height growth, and in no case were we able to get height growth 22 greater than 500' upward, regardless of what type of 23 assumptions that we used. 24 As Doug mentioned, we're asking to include the Ivishak 25 for -- as a class 2 disposal zone, even though we have no ELI TEe 0 U R T R E P 0 R T I H G 4051 East 20th Avenue #65 Anchorage Alaska 99508 907'333,0364 ) ) 77 1 immediate plans to inject into it. The Ivishak and the Tarn 2 are both hard rock. The Nolte Smith quasi-3D model is based on 3 hard rock. So it's applicable to the type of formations that 4 we're looking at. If we were to try to apply that model to 5 shallow zones, it does have limitations. It assumes a planer, 6 single frac as opposed to dendritic or more than one frac, as 7 we have no branching. The model assumes no disassociation, it 8 assumes that the rock matrix is -- doesn't disintegrate under 9 pressure. So it's not as applicable for looking at height 10 growth in shallow formations. If you were to use it in that 11 capacity what it would do is it would provide a conservative 12 approach because complexities associated with shallow injection 13 such as dentritic fractures, disassociation, rock matrix 14 invasion, those things tend to reduce fracture geometries. So 15 the model would predict too high of a frac height. 16 And that concludes the testimony that we had prepared 17 for the area injection order. Are there any questions? 18 COMMISSIONER OECHSLI: I don't think so. Thanks. 19 CHAIRMAN JOHNSTON: Okay. I guess we have no further 20 questions. 21 MR. ROGERS: You've got a citation for that aquifer 22 (indiscernible) 40 CRF part 147.102 (ph)..... 23 CHAIRMAN JOHNSTON: Oh, it's in the federal regs, 24 that's right. Yeah. I I 251 I REPORTER: Your name, sir? ELI TEe 0 U R T R E P 0 R T I H G 4051 East 20th Avenue #65 Anchorage Alaska 99508 907,333'0364 ¡ / ) 78 1 MR. ROGERS: Dan Rogers. 2 REPORTER: Thank you. 3 CHAIRMAN JOHNSTON: Yeah, I seem to recall that. I 4 appreciate that citation. You have no further questions? 5 MS. OECHSLI: No. 6 CHAIRMAN JOHNSTON: At this time I don't believe the 7 commission has any further questions of either of the of any 8 of the applicants concerning either the pool rules or the area 9 injection order. So at this time I guess it would be 10 appropriate to go ahead and close the hearing. And I do thank 11 you for your time and wish you the best of luck with this 12 accumulation. I think it's exciting that we're seeing Tarn 13 development, and hopefully in the very near future we'll see 14 some oil flowing out of this reservoir. So, again, thank you 15 for your information. Appreciate it. 16 MR. STRAMP: Thank you for your time. 17 (Off record - 11:35 a.m.) 18 END OF PROCEEDINGS 19 20 21 22 23 24 251 ELITE COURT REPORTING 4051 East 20th Avenue #65 Anchorage Alaska 99508 907·333'0364 ELI TEe 0 U R T R E P 0 R T I R G 4051 East 20th Avenue #65 . Anchorage Alaska 99508 907'333,0364 25 24 23 22 ~"'"""~'"~"'''''~-._~ ! OFFICIAL SEAL ~ ~ STATE OF ALASKA i ~ NOTARY PUBLIC J ~ LAUR~L t. ~~L ~ $ My Comm. eX¡Jir:::3: .lLþ....'1..~..._..... :: $_",\",",IM."'." .......\\" .......\ \\' \~\'. ''¡;\\\\' '..,\ V\....\..""'" WW\J: 21 20 19 18 for Ala~ka seal this 14th day of May 1998. £»N.~ ~. Notary PubllC in and 17 ~/ ....~f. """......., 16 affixed my 15 IN WITNESS WHEREOF, I have hereto set my hand and 14 That the hearing was transcribed by myself to the best of my knowledge and ability. 13 12 Porcupine Street, Anchorage, Alaska; 11 offices of Alaska oil & Gas Conservation Commission, 3001 10 April 1998, commencing at the hour of 9:00 o'clock a.m., at the 9 Commission Hearing, was taken before me on the 28th day of 8 That the foregoing Alaska oil & Gas Conservation 7 certify: 6 of Alaska, and Reporter for Elite Court Reporting, do hereby 5 I, Laurel L. Earl, Notary Public in and for the State 4 UNITED STATES OF AMERICA) )ss. STATE OF ALASKA ) 3 2 C E R T I F I CAT E 1 ) ,) #6 ) ) KUPARUK RIVER UNIT TESTIMONY FOR TARN OIL POOL RULES April 28, 1998 ) ) TABLE· OF CONTENTS Page I. Introduction 1 II. Geology 3 III. Reservoir Description 6 IV. Reservoir Development 9 V. Facilities 16 VI. Drilling & Well Design 20 VII. Reservoir Surveillance 26 VIII. Summary of Testimony 29 IX. Proposed Tarn Oil Pool Rules 31 X. Proposed Findings & Conclusions 34 XI. List of Exhibits 35 ') Tarn Oil Pool Rules Testimony ') April 28, 1998 I. Introduction This hearing has been scheduled 'in accordance with 20 AAC 25.540 with a public notice period started on March 27, 1998. The purpose of this hearing is to present testimony to support classification of the Tarn Reservoir in and around the Tarn Participating Area as an oil pool and establish pool rules for development of said oil pool pursuant to 20 AAC 25.520. ARCO Alaska, Inc. (AAI) is presenting testimony on behalf of the Tarn Working Interest Owners (WIOs). The scope of this testimony includes a discussion of geological and reservoir properties, as they are currently understood, and AAI's plans for reservoir development and surveillance, well planning, facilities installation and project scheduling. This testimony will enable the Commission to establish rules that allow economical development of resources within the Tarn Oil Pool. Confidential data and interpretation concerning the Tarn formation will be furnished to the Commission as additional support testimony. Development drilling and facility installation are scheduled to commence during the second quarter of 1998 with initial production beginning by year-end. The proposed Tarn Oil Pool includes all potential hydrocarbon-bearing zones within the Tarn Reservoir. The areal extent of the pool is limited to areas that have been targeted for either development or possible exploratory activities. The WIOs recognize a need for a consistent development strategy for the Tarn Reservoir. Pool rules for the entire reservoir will help maintain this consistency. As additional information and understanding of the Tarn Reservoir is acquired, AAI will work with the Commission to ensure the Tarn Oil Pool definition continues to make sense. Kuparuk River Unit (KRU) facilities will be employed to process production and supply injectant. Greater Kuparuk Area alignment agreements, which set new tract ownership and facility sharing terms in the Tarn area, will help govern business issues associated with sharing infrastructure. The properties to be developed (Le., the Tarn Oil Pool) are leased from the State of Alaska. A portion of the Tarn Oil Pool is located within the present boundaries of the Kuparuk River Unit. AAI, on behalf of the Tarn Oil Pool WIOs, will be filing an application ("Unit Expansion Application") with the Commissioner of the Department of Natural Resources to expand the Kuparuk River Unit area to include the remainder of the Tarn Oil Pool. The Unit Expansion Application will also request Department of Natural Resources approval of a Tarn Participating Area, which will include the Tam Oil Pool. AAI intends to file this application no later than May 29, 1998. The Unit Expansion Application will also include plans of development and operations for the Tarn Participating Area, including the ') / Tarn Oil Pool Rules Testimony ) April 28, 1998 Tarn Oil Pool. AAI will file a copy of the Unit Expansion Application with the Commission. The Tarn WI Os have integrated their interests through a series of alignment agreements. These alignment agreements will be submitted as Exhibits 9, 10 and 11: AAI/BPX Alignment Agreement AAI/BPx/UNOCAL Alignment Agreement AAI/BPX/Chevron/Mobil Alignment Agreement Exhibit 9 Exhibit 10 Exhibit 11 Tarn production ownership of the Tarn Oil Pool is shown below. ARCO Alaska, Inc. BPX UNOCAL MOBIL CHEVRON Total 2 0.55293767 0.39282233 0.04950600 0.00364800 0.00108600 1.00000000 ') Tarn Oil Pool Rules Testimony ) April 28, 1998 II. Geology Introduction This portion of the testimony provides geologic data to the Commission in support of AAI's proposed Tarn Oil Pool. Stratiaraphic Nomenclature The Tarn Reservoir is the sequence of reservoir sandstones and associated mudstones found in the interval between 4376 and 5990 feet measured depth in the ARCO Bermuda #1 well, and in its lateral equivalents. The Tarn Reservoir is late Cretaceous in age and stratigraphically within the Seabee Formation. The reservoir is approximately 1600 feet thick and is composed of five intervals. The initial Tarn Oil Pool includes the entire Tarn Reservoir, however, the pool definition may change as additional information from development and exploratory activities becomes available. All five Tarn Reservoir intervals are shown in the wireline log from the ARCO Bermuda #1 well (Exhibit 1). Brief summaries of these intervals are given below in ascending order. · The 'C30' Interval was encountered between 5990 and 5716 feet measured depth in the ARCO Bermuda #1 well. The boundaries are correlatable markers C30 and C35, respectively. Potential reservoir sands here were wet but may be hydrocarbon-bearing laterally. · The Bermuda Interval was encountered between 5608 and 5542 feet measured depth in the ARCO Bermuda #1 well. The boundaries are correlatable markers T2 and T3, respectively. Hydrocarbon-bearing sands in this interval were encountered in the ARCO Bermuda #1 and in four offset wells. · The Cairn Interval was encountered between 5452 and 5316 feet measured depth in the ARCO Bermuda #1 well. The boundaries are correlatable markers T3 and T4, respectively. Hydrocarbon-bearing sands were encountered in the correlative interval in one offset well. · The Arete Interval lies between 5316 and 5105 feet measured depth in the ARCO Bermuda #1 well. The boundaries are correlatable markers T4 and T6, respectively. Seismic data indicate that reservoir sands may be present in laterally equivalent strata. 3 ) Tarn Oil Pool Rules Testimony ) April 28, 1998 · The Iceberg Interval is encountered between 5105 and 4376 feet measured depth in the ARCO Bermuda #1 well. The boundaries are correlatable markers T6 and C37, respectively. Seismic data indicate that reservoir sands may be present in laterally equivalent strata. Stratiaraphic Description The Tarn Sands comprise a sequence of oil-bearing, very fine- to fine-grained marine sandstones and interbedded mudstones. The Bermuda and Cairn Intervals are best understood at this time. Initial injection operations will initially be restricted to these two intervals. As information is gained about the Iceberg, Arete and 'C30' Intervals, the Tarn Oil Pool definition may be modified. The Bermuda interval is bounded by the T2 and T3 surfaces. The T2 surface appears to be erosional; the nature of the T3 surface is uncertain at this time. Sand profiles vary from well to well. Sandbodies in the Bermuda interval are lobate in form (Exhibit 2). The Cairn interval is bounded by the T3 and T4 surfaces (Exhibit 1). The T4 surface may be a conformable contact. The Cairn sandbody is lobate to linear in form (Exhibit 2). The areal distribution of Tarn sandbodies is shown in Exhibit 2. Sandbodies are are distributed in an overlapping geometry within the proposed Tarn Oil Pool area. Aae of Sediments Based upon ARCO in-house micropaleontologic and palynologic data, the Tarn Sands sequence is late Cretaceous (Cenomanian-Turonian) in age. Proposed Pool Name The primary reservoir covered by this application was first encountered in 1991 in the ARCO Bermuda #1 well. The use of "Tarn" as the reservoir and pool names was based on the names of the confirmation wells (Le., ARCO Tarn #2, ARCO Tarn #3, ARCO Tarn #3A and ARCO Tarn #4). The zone was first flow tested during 1997 in the ARCO Tarn #2 well, where rates of approximately 2000 BOPD of 37 degree API oil were obtained. 4 ) Tarn Oil Pool Rules Testimony ) April 28, 1998 Proposed Vertical Pool Boundaries The Tarn Oil Pool is the hydrocarbon accumulations in the sequence of oil- bearing, very fine- to fine-grained sandstones and mudstones between 5990 and 4376 feet measured depth in the ARCO Bermuda #1 well and its lateral equivalents. This zone is bounded below by the C30 log marker and above by the C37 log marker. C30 is recognized on ARCO Bermuda #1 logs as the high gamma-ray spike at 5990 feet measured depth and its lateral equivalents. C37 is high gamma-ray log reading at the top of a fining-upward log motif at 4376 feet measured depth in the ARCO Bermuda #1 well and its lateral equivalents. Structure The Tarn Oil Pool has been mapped using 3D seismic data. Structural dip is generally to the east. The T3 surface, the top of the Bermuda Interval, dips to east-southeast; dip generally decreases eastward from 3-4 degrees near the ARCO Tarn #1 well to nearly flat in the vicinity of the ARCO West Sak #20 well (Exhibit 3). Complex faulting is seen along the west (updip) edge of the Tam Oil Pool and a north-south trend of echelon normal faults is found along the east edge of the northern Bermuda Interval lobe, but no faults are mapped within the main reservoir trends. Bermuda Interval depths range from approximately 4900 feet subsea in the west to 5600 feet subsea in the east (Exhibit 3). The Cairn Interval stratigraphically overlies the Bermuda Interval, and is offset to the east of the Bermuda Interval. The T3 surface, the top of the Cairn Interval, is shown in Exhibit 4. Faulting is similar to the pattern on T3. Structural depth of the Cairn Interval ranges from 5300 to 6000 feet subsea. Because of structural dip, the Cairn Interval is generally structurally level with or deeper than the Bermuda Interval Controls on Oil Distribution Trapping in the Bermuda and Cairn Intervals is stratigraphic, and hydrocarbon distribution is controlled by sand distribution. No water or gas cap has been encountered within the Bermuda Interval. Water was encountered in the Cairn Interval in the ARCO West Sak #20 well, which is downdip to the east. Gas may be present in the ARCO Tarn #4 well, where there is an apparent gas-oil contact (GOC) at 5481 feet measured depth. Uncertainty remains on whether the GOC actually exists, and, if so, whether it is structurally or stratigraphically controlled. Both the Bermuda and the Cairn Intervals dip east with updip stratigraphic seals to the west. 5 ) Tarn Oil Pool Rules Testimony ) April 28, 1998 III. RESERVOIR DESCRIPTION Introduction This section summarizes reservoir properties. Core data provides the foundation for much of the rock property information presented in this section. Whole cores were collected from the ARCO Tarn #1, ARCO Tarn #2, ARCO Tarn #3 and ARCO Tarn #4 wells. In addition, rotary side-wall cores were obtained from the ARCO Bermuda #1 well. A cased hole test of the ARCO Tarn #2 provides the basis for the fluid information. Porosity. Permeability and Water Saturation The Tarn Oil Pool sands are fine to very fine-grained and have common shale laminations and interbeds. Sands are compositionally heterogeneous. The major components are quartz, heterolithic rock fragments, plagioclase and zeolite. The heterolithic component consists of sedimentary, igneous and metamorphic rock fragments. Zeolites result from diagenetic alteration of volcanic glass. Dominant clays are chlorite, and Illite, with lesser amounts of kaolinite and 'stable-phase' mixed layer Illite/Smectite. While XRD analyses show clay content in the range of 15 to 25%, clay minerals are dominantly in the heterolithic grains rather than in the matrix. Core measured porosities Range from 18% to 27% and average 210/0. Corresponding air permeabilities range from 1 md to 45 md and average approximately 10 md. The average core based water saturation (after correcting for invasion) was measured at 40%. Porosity is dominantly secondary, and the rock fabric shows abundant dissolution rims, commonly with microporosity. In combination with the fine grain size, this results in high surface area and concomitantly high irreducible water saturation, as well as the observed low permeability. Net Pay Determination Petrographic observations were combined with laboratory analyses to determine the appropriate log model for the Tarn Reservoir. A key observation is that the clay component within these rocks is dominantly located in framework grains, not the matrix. It was concluded that, despite the superficial appearance of the rocks, a shaley-sand log model was not appropriate. Instead, core porosity, which is total porosity, was matched with porosity logs, and then saturation was calculated using the standard Archie approach with laboratory-measured "m" and 6 > Tarn Oil Pool Rules Testimony ) April 28, 1998 "n" values. Net pay is then determined by application of cut-offs on calculated total porosity and water saturation curves. The porosity cut-off is 18%, based on a cross-plot of core porosity and permeability where 18% porosity equates to 1 millidarcy rock. A water saturation cut-off of 60% is used. This value was determined by matching calculated net pay with pay counted from whole core. Reservoir Fluids and PVT Properties Reservoir fluid properties are estimated from fluids recovered during a cased- hole test of the ARCO Tarn #2 well. The well was on production for a total of 10 days. At the end of the test, the well was averaging 1900 BOPD (of 37° API gravity crude) and 1200 SCF/STB at a flowing tubing pressure of 550 psig. Separator gas and separator liquid were physically recombined to a GOR of 755 SCF/STB in a high-pressure cell at reservoir temperature (142° F). After establishing thermal equilibrium, the contents of the cell were lowered to 2290 psig (to better reflect reservoir pressure) and the equilibrium gas cap was removed. (Original reservoir pressure of at the ARCO Tarn #2 well was calculated at 2350 psig from a pressure build-up test immediately following the flow test.) A differential vaporization was performed on the cell contents at reservoir temperature. Results are summarized below. Values obtained at the ARCO Tarn #2 reservoir pressure of 2350 psig were extrapolated from existing trends assuming a gas saturated crude. Pressure Bo Rs uo (psig) (Rvb/STB) (SCF/BO) ÍÇQÌ 2350 1.38 710 0.55 2265 1.37 686 0.58 1950 1.34 601 0.64 1700 1.31 536 0.70 1450 1.28 473 0.76 A corresponding crude composition assay is shown in Exhibit 5. Original Oil-in-Place Original oil-in-place (OOIP) is determined using volumetrics with expected reservoir parameters. Porosity and water saturation values are calculated from the Tarn log model. The formation volume factor is based on results from the recombined fluid analysis performed on produced fluids from the ARCO Tam #2 well test. Net pay and areal extent estimates are prepared from seismic maps (in which various seismic attributes are calibrated to the calculated net pay values for the existing penetrations). The resultant Tarn Sand OOIP estimates range from 80 to 250 MMBO, with an expected value of 136 MMBO. The 7 ) Tarn Oil Pool Rules Testimony ) April 28, 1998 chance-weighted OOIP estimate for the Cairn Sand in the vicinity of the ARCO Tarn #4 well is 3 MMBO. 8 \ 1 , ) Tarn Oil Pool Rules Testimony April 28, 1998 IV. Reservoir Development Introduction This portion of the testimony includes a discussion the recovery process selection and the development and management strategies that are planned to address uncertainties associated with the Tarn Reservoir. Discussion is also presented on expected well performance. Recovery Process Selection One of the most critical aspects to the Tarn development plan is the selection of a recovery process. To assist in this decision, finite difference simulation was employed. Stochastic reservoir descriptions (based on geostatistical techniques) were prepared for the ARCO Tarn #2 and ARCO Tarn #3/3A areas. These descriptions were used to construct finely gridded 20 pattern models. Subsequent model runs suggested that providing sufficient pressure support may prove challenging due to low permeabilities, permeability distributions and transmissibility barriers. Gore permeabilities and pressure transient analysis testing from the ARGO Tarn #2 well both indicated that the average permeability in this vicinity was less than 10 md. Furthermore, out of the 32 layer description employed for the ARGO Tarn #2 area model, none of the layers had an average harmonic air permeability greater than 4 md and only three layers, representing a total of 9 feet of pay, had an average harmonic air permeability greater than 3 md. (Harmonic permeability averages are used to represent average permeability in series flow.) Harmonic averages for the ARCO Tarn #3/3A area were even lower. The model descriptions were also replete with transmissibility barriers, representing mud drapes and calcite cementation, which restricted vertical flow. In summary, modeling suggested that flow through the reservoir will follow a tortuous flow path and subsequently complicate pressure support planning. Initiating an EOR process from the start will achieve optimal recovery in a tight formation such as Tarn. Injection fluids are needed to sweep oil to the producers. Providing initial pressure support with immiscible fluids, such as water or lean gas, would have detrimental impacts on the initial development project and/or a future enriched gas injection project. Water is not a desirable initial injectant because of two principal reasons. First, laboratory core flood experiments indicate that water injection causes formation damage. Second, water is much more viscous than MI. Maintaining pressure support with water would require a relatively high number of injection wells 9 " l ") Tarn Oil Pool Rules Testimony April 28, 1998 because of the low permeabilities and tortuous flow paths associated with the Tarn Reservoir. This would act to either significantly reduce production rate and/or significantly increase the total number of wells required for development. Screening level simulation runs were performed to evaluate initially waterflooding Tarn. These runs were made using extremely optimistic assumptions (Le., no formation damage and a matrix injection pressure 1500 psi greater than the reservoir parting pressure). Even with these optimistic assumptions, water could not compete with MI as an initial injection fluid. Further model runs with more realistic water injection assumptions were therefore not performed. Lean gas is not a desirable initial injection fluid as it would strip light ends from the Tarn crude. This would make it more difficult to achieve miscibility with an enriched natural gas at a later date. It makes little sense (from a reservoir standpoint) to initiate a flood with lean gas injection when an enriched gas EOR project is eventually planned. Simulation results indicate that injecting a 20% hydrocarbon pore volume slug of MI followed by a lean gas flush would increase recovery by approximately 100/0 OOIP compared with straight lean gas injection. (The purpose of the lean gas flush will be to recover previously injected MI and help provide pressure support.) This equates to 14 MMBO based on an expected 136 MMBO of OOIP. Recovery Mechanisms Initially employing a miscible recovery process is integral to successfully developing the Tarn Reservoir. However, given that the reservoir distribution is stratigraphically controlled with localized sand accumulations, some isolated areas may experience primary depletion. Although remedial measures (i.e., additional drilling and well conversions) will be considered to help ensure pressure support is maintained, maintaining pressure support may not be justified in all situations. Development Approach The scope of the Tarn development project involves drilling approximately 40 wells to develop 42 MMBO associated with the 136 MMBO OOIP estimate for the Bermuda Interval. The wells will be drilled from two new drill sites. A phased development approach is planned to help minimize risk associated with the Tam Reservoir (e.g., reservoir extent, pay thickness, permeability, etc.) The first phase of the project involves drilling approximately 20 wells starting during the second quarter of this year. Production would be initiated by yearend. Initial injection support would commence no later than six months after first 10 '. ) Tarn Oil Pool Rules Testimony ) April 28, 1998 production. Wells drilled during the first phase are intended to develop the main portion of the reservoir and test the periphery. The second phase of the project involves drilling approximately 20 more wells starting during the second quarter of 1999. The second phase is intended to primarily develop the periphery. Well performance data and improved seismic calibrations acquired from the first phase should help guide drilling operations during the second phase. Exploratory drilling targeting other zones within the Tarn Reservoir will be conducted concurrently with development drilling operations. Successful exploratory drilling results could alter existing plans by (1) changing the location and target interval of the initial development wells and (2) expanding the scope of the project to include additional wells. An expanded project scope would likely involve additional development drilling phases and may include additional drill sites. An expanded project scope may also involve an areal and/or vertical expansion of the Tarn Oil Pool definition. Given the localized sand deposits associated with the Tarn accumulation, a relatively high number of wells will likely be sidetracked compared with other North Slope fields. The drilling order of the wells has therefore been optimized to test seismic anomalies along the periphery of the accumulation while maintaining safer "fallback" locations in the heart of the accumulation. Prior to spudding a well, sidetrack locations will be identified and included in the drilling application to help ensure that permitting issues do not interrupt drilling operations. Ongoing seismic interpretation will be a critical aspect when delineating the periphery. Relatively low risk well locations will be drilled near existing penetrations to provide time, when needed, for seismic reinterpretation. Optimization Optimizing field development will be an ongoing process requiring additional field data, laboratory studies and reservoir modeling. Work efforts currently in progress are designed to optimize total cumulative MI slug size, reservoir pressure, MI enrichment level and well spacing. For screening purposes, a cumulative MI slug size equal to 20% of the hydrocarbon pore volume (HCPV) was assumed. Simulation has not yet been performed to optimize slug size. Further work is also needed to determine the optimum reservoir pressure and MI enrichment level. For screening purposes, an average reservoir pressure near initial conditions was assumed. Work was done to investigate using a specialized MI blend for Tarn (by blending Tam produced gas with Kuparuk MI at one of the Tarn pads), however, additional work is needed to evaluate this option. 11 > ') Tarn Oil Pool Rules Testimony April 28, 1998 Slim tube experiments are currently in progress. These experiments demonstrate that Kuparuk MI is miscible at the 2350 psig reservoir pressure calculated from the ARCO Tarn #2 'penetration. Furthermore, this work suggests that Kuparuk MI is richer than needed to achieve a miscible flood in the Tarn Oil Pool. After slim tube experiments are complete, the fluid characterization employed for Tarn will be refined. Questions involving optimum MI slug size, reservoir pressure and MI enrichment level will then be addressed. Plans are to develop the reservoir on nominally 100-acre well spacings. Additional stochastic modeling work is in progress to confirm that a 10Q-acre average well spacing is optimum given the expected injector/producer tortuous flow paths and reservoir discontinuities. This work will also be used to help evaluate whether injectors should be preproduced to capture primary reserves from discontinuous zones. Regardless of the outcome from this work, some portions of the reservoir may require a relatively dense spacing to address permeability barriers (e.g., faults, mud drapes and calcite cement) or poorer than expected well (productivity/injectivity) performance. A 10-acre well spacing is therefore requested to allow a flexible well placement strategy that will maximize recovery. Unless optimization studies prove otherwise, plans are to are to inject approximately 20% HCPVI (45 BCF based on 136 MMBOOOIP and ARCO Tarn #2 reservoir conditions) of Kuparuk MI followed by lean gas injection. Reservoir pressure will be maintained to ensure miscibility while MI is being injected into the reservoir. Well spacings will average close to 100 acres although some areas may require much closer spacing for optimum recoveries. Well Conversion Strate~y Since Tarn Reservoir distribution is stratigraphically controlled and sand accumulations are localized, sand continuity is expected to be difficult to predict. Producer/Injector interactions will therefore be difficult to predict in the absence of field data. Development plans call for minimizing the number of injection wells until producer/injector interactions are better understood. Producers will be converted to injection service as necessary in order to provide pressure support and minimize gas cycling. Hence, to as large of an extent as possible, plans are to let reservoir performance be a guide in optimizing pattern configurations. Simulation work suggests that voidage can be maintained at a producer/injector ratio in the two to three range. Development plans are to therefore initially employ a producer/injector ratio of approximately three and adjust it as needed. As the flood matures (and more producers are converted to injection service), the producer/injector ratio is expected to decline to approximately two. During the MI injection phase of the project, reservoir pressure will be managed to ensure miscibility. 12 ) Tarn Oil Pool Rules Testimony ) April 28, 1998 Lonq-Term Injection Plans Injection plans are to employ a relatively large slug of MI followed by a lean gas flush. Conventional MWAG and IWAG are not planned because of the problems associated with injecting water into the Tarn Reservoir-potential formation damage, low water injection rates (due to a tortuous injector/producer flow path) and adverse relative permeabilities that stem from introducing three phase flow in a tight formation. Gas cycling is therefore expected during the flood. Once MI and/or gas cycling begins to occur, plans are to investigate a variety of remedial techniques. These include, but are not limited to foam, polymers and water. Furthermore, employing sustained water injection to help provide pressure support following the lean gas flush is still considered a possibility. Additional field data (i.e., reservoir permeabilities, injector/producer interactions, formation damage pilots, etc.) and simulation studies are needed to evaluate this possibility. Finite difference simulation shows that once appreciable gas cycling begins, reservoir withdrawals, if not manually constrained, will begin to exceed surface facility injection capacities. Voidage is therefore no longer maintained and reservoir pressure declines. Hence, unless remedial techniques to control gas cycling prove successful, reservoir pressures may decline during the lean gas flush. Stimulation Plans The tight nature of the Tarn Reservoir coupled with its potential sensitivity to damage necessitates that propped hydraulic fracture stimulations be performed on producers. (The ARCa Tarn #2 well flowed nothing without stimulation and approximately 1900 BOPD after its hydraulic fracture stimulation.) Wellbore trajectories, cement and tubulars will be designed to accommodate hydraulic fracture stimulation techniques. Initially potassium chloride water will be used as a carrier fluid, however, potentially less damaging carrier fluids will also be considered (e.g., "resid" from the Kuparuk topping plant). Plans are to not initially stimulate injection wells. However, if injectivities are poor or if injection logs indicate significant portions of the reservoir are not accepting injectant, injectors will be stimulated with high-pressure breakdowns. An attempt will be made to minimize propped hydraulic fracture stimulations on injectors as this would complicate future profile modification efforts. Of course, injectors that were previously produced would have existing propped fractures in place. 13 ) ) Tarn Oil Pool Rules Testimony April 28, 1998 Secondary Targets The Bermuda Interval will be the 'primary target of initial development efforts. Current plans are to focus initial development efforts on that portion of the interval most likely have good reservoir characteristics. As previously shown on Exhibit 1, potentially productive secondary targets in the Iceberg Interval, Arete Interval and Cairn Interval may be encountered during these development efforts. Secondary targets in the Arete Interval and Cairn Interval are expected to generally be within 400 feet TVD of the Bermuda Interval, however, secondary targets in the Iceberg Interval may be higher. These thin, potentially productive zones contain insufficient reserves to merit separate wells or extensive completion design modifications. Although fracture stimulations are planned for Bermuda Interval producers, fracture modeling indicates these stimulations will only grow approximately 200 feet upwards. Potentially productive secondary pay zones can therefore only be developed if they can be inexpensively commingled with Bermuda production. Given the initial uncertainty of producer/injector interactions, most producers will be candidates for conversion to injection service. In order to maintain conversion flexibility, there are no casing design differences between production and injection wells. (Casing connections will be designed for gas or liquid service.) The flexibility to convert wells to injection service on an as needed basis is an integral part of the Tarn development strategy. This complicates secondary target development as these targets can only be pursued if they are not isolated by more than one casing string. Pursing secondary targets may result in exceeding the AOGCC guideline that injectors provide annular isolation within 200 feet measured depth of the highest perforated interval. Plans are to provide annular isolation within 200 feet measured depth of the perforated zone, unless secondary targets are encountered with a pay thickness approaching or exceeding 10 feet TVD. Based on current drilling and facility hook-up plans, the productive nature of these secondary targets can not be fully ascertained during initial drilling operations. If future evaluations indicate that developing secondary targets can not be justified, there is the potential of having either initial or future injectors with annular isolation located more than 200 feet measured depth above the perforated zone. Help from the Commission is therefore needed to ensure that well service conversion flexibility is not sacrificed by attempting to pursue thin secondary targets. 14 " I ') / Tarn Oil Pool Rules Testimony April 28, 1998 Well Performance There is considerable uncertainty in well performance projections. Large variations are expected in well productivities and injectivities. Tarn development plans therefore require flexibility to address uncertainties and performance variations. Typically, Tarn producers are expected to have initial production rates in 1500 to 2000 BOPD range. These rates are expected to gradually decline during the first year of production before stabilizing at approximately 900 BOPD/well. Artificial Lift No artificial lift is initially planned. Nodal Analysis calculations suggest that artificial lift will generally not be needed due to a variety of factors; namely, the absence of produced water, relatively high initial GORs (700 - 1700 SCF/B), light oil (370 API gravity crude), pressure support and the associated insitu gas lift resulting from MI and lean gas breakthrough. Nevertheless, Tarn completions will include a profile that will allow the use of artificial lift, such as hydraulic jet pump, lift gas, or plunger lift systems to be installed at a later date, if needed. Flowing tubing pressures of Tarn producers are initially expected to be in the 300 psig range. These high backpressures will restrict production. A variety of surface facility options are being considered to address this issue. These options are being worked in concert with Kuparuk facility de-bottlenecking studies. Current goals are to provide some form of backpressure relief to Tam producers within two years of initial production. 15 ) Tarn Oil Pool Rules Testimony ) April 28, 1998 v. Facilities Introduction This portion of the testimony summarizes the injectant sources that will initially be used at Tarn. Discussion of the pads, roads, drill site facilities and other infrastructure is presented. General Overview Tarn production will be commingled with Kuparuk production in surface facilities prior to final processing and ultimate custody transfer. Sharing existing production facilities is possible due to existing spare liquid capacity at Kuparuk's CPF-2 (central processing facility). Economical development is contingent upon utilization of these facilities. Tarn will make maximum use of the existing Kuparuk River Unit (KRU) infrastructure. This maximizes reserves and minimizes the environmental impacts. The Greater Kuparuk Area Alignment Agreement will govern the corresponding allocation of costs and production to the working interest owners. The miscible injectant employed at Tarn will initially be the same injectant as that currently used in the KRU Large Scale EOR Project. This injectant is manufactured at Kuparuk's CPF-1 and CPF-2 by blending lean gas from the KRU's production facilities with light hydrocarbon liquid streams from the Prudhoe Bay Unit (PBU) and KRU. The light liquid hydrocarbons from the PBU are NGLs from the CGF. The light liquid hydrocarbons from the KRU consist of scrubber liquids from artificial lift gas compression systems at CPF-1 and CPF-2, NGLs from CPF-1 and naphtha from the Topping Plant. During the flood, there is a possibility that Tarn produced gas may be blended with KRU MI to generate a lighter MI blend customized for the Tarn Reservoir pressure and oil properties. Lean gas will be injected into the Tarn Oil Pool after MI injection targets have been met. The source of the lean gas will likely be Kuparuk River Unit's CPF-2. However, other potential gas sources will also be considered. (The composition of CPF-2 MI and lean gas during late 1997 is shown in Exhibit 6.) Since Tarn injectant also has value at the KRU, work is currently in progress to investigate de-bottlenecking KRU facilities to provide higher MI injection capabilities. KRU de-bottlenecking studies are also in progress to investigate ways to help ensure that Tarn production has a minimal impact on KRU production. 16 Ì¡ ) Tarn Oil Pool Rules Testimony ) April 28, 1998 Pads and Roads Tarn development involves the addition of two new drill sites to the Greater Kuparuk Area (GKA), Drill Site 2L and Drill Site 2N, along with required ancillary and support facilities. Drill Site 2L will be just over six miles southwest of existing Drill Site 2M, with Drill Site 2N located three miles further south. The drill sites are designed to accommodate a total of 40 wells on 30-foot centers or 80 wells on 15-foot centers. A road connecting the new drill sites to the existing road system is routed from Drill Site 2M to Drill Site 2L then to Drill Site 2N. Two bridges are required along the roadway to cross Trouble Creek (just past Drill Site 2M) and the Miluveach River. Culvert batteries support drainage of two tributaries and individual culverts are installed for spring runoff and sheet flow. Pipelines Cross-country pipelines include a 16-inch common line from Drill Site 2N to Drill Site 2M, where it ties into the existing common line to CPF-2. An 8-inch MI injection line will run from Drill Site 2M to Drill Site 2N. Both pipelines are to be routed close to Drill Site 2L, where laterals will branch off to tie into Drill Site 2L. Pipelines are generally to be offset from gravel roads by at least 450 feet. Related construction activities will be done from an ice road during winter 1997- 1998. Powerlines Electrical power will be transmitted from Drill Site 2M to Drill Site 2L over new 34.5 kV power lines. This increased load presented by the Tarn project requires an upgrade of the existing overhead CPF-2/ Drill Site 2M transmission line from 13.8 kV to 34.5 kV along with requisite transformers and switch gear retrofits at Drill Site 2M, Drill Site 2K and Drill Site 2H. The new transmission line will be installed using two different techniques: overhead and buried. Overhead power transmission is a well-proven technique used throughout North Slope oil production areas. This technique will be used for the first and longest leg from Drill Site 2M to Drill Site 2L. The buried section from Drill Site 2L to Drill Site 2M is being installed to provide objective information to test the feasibility (Le., capital cost and operability) of this type of installation on the North Slope. Direct burial of power lines also allows for a relatively inexpensive installation of fiber optic communication lines, which can be buried along with the pipeline at a 17 ) Tarn Oil Pool Rules Testimony ) April 28, 1998 low incremental cost. Overhead power lines require the fiber optic line be installed pole to pole with the overhead lines. Drill Site Facilities The design premise for Tarn facilities is for daily operations to require minimal operator presence. All data gathering and routine operations are to be accomplished remotely from CPF 2 and/or a Tarn drill site control room. Data gathering is based on "field bus" technology, which offers two wire control and diagnostic capabilities for all field instruments. Facilities to be installed initially at both drill sites include: · Production, test, and MI injection lateral piping and headers · Three-phase metering skid for well testing · Instrumentation, control, and communication equipment Remote operations include: · Well testing using Accuflow metering · Emergency shutdown . Production choke control . Injection fluid metering · Production pressure metering · Annular pressure monitoring. On-site operations include injection choke valve actuation. Remote well control and testing functions will be performed using the field bus control system. Well production rate will be controlled using an automated choke valve. Testing can take place remotely through a divert valve system, which redirects the flow from the production header to the test. Emerqency Shutdown Emergency shutdown systems meet API-RP-14C requirements and ARCO specifications for safety systems. All production and test piping is designed to ANSI 1500 psi and will contain the wellhead shut-in pressure up to the pad emergency shut down (ESD) valves. The injection piping will be designed to ANSI 2500 psi in order to accommodate the injection pressures needed. (At an expected flowing tubing pressure of 100° F, ANSI 1500 psi and ANSI 2500 psi provide working pressure ratings of approximately 3750 psi and 6250 psi, respectively. ) 18 ) Tarn Oil Pool Rules Testimony ) April 28, 1998 Both production and injection wells can be shut in from over- and under-pressure through pressure switch signals which close the surface safety valves (SSVs). Wells can also be shut off remotely through the control system. 19 ., Tarn Oil Pool Rules Testimony ) " April 28, 1998 VI. Drilling & Well Design Introduction The Testimony below discusses activities related to drilling and completing Tarn Oil Pool wells. Discussion is also presented on safety systems, initial logging plans and completion design advantages. Casing & Cementing Casing and cementing plans for Tarn wells are consistent with AOGCC Regulation 20 ACC 25.030. As in KRU wells, conductor casing will be set below 75 feet to provide anchorage and support for the rig diverter assembly. Surface casing size may be 9-5/8" or 7-5/8", depending on casing setting depth and production tubing size. Surface casing will be set below the base of the West Sak interval, effectively casing off the permafrost, Ugnu, and West Sak formations. When possible, surface casing may be set as deep as 200 feet above the Tarn interval. To accomplish this deep setting depth, offset wells must indicate no shallow hazards and the top of the producing formation must be highly predictable. This deep setting of the surface casing will most likely occur later in the development plan. Tarn wells utilize a tapered casing string tied back to surface, that serves as the combination production casing / tubing string installation. The casing adjacent from the producing interval is the same size as the tubing is at the surface (monobore). The casing across the production interval is then tied back to surface with a string of 3Y2" or 4 Y2" tubing inserted into a seal bore or polished bore receptacle (positioned above the top pay zone perforation.) This provides a tubing annulus with isolation and pressure integrity (Exhibit 7). There are three casing programs proposed for the Tarn development: Case 1) 3Y2 and 4Y2 inch Tubingless Monobore completions. This casing program employs a single string of 7-5/8 inch (L-80, 29.7 pound) casing set to within 200 feet of the Tarn formation top. A 3Y2 inch (L- 80, 9.3 pound) or 4Y2 inch (L-80, 12.6 pound) liner would then be set across the Tarn formation and tied back to surface with either 3~ inch (L-80, 9.3 pound) or 4Y2 inch (L-80, 12.6 pound) production tubing. Case 2) 3Y2 inch Slim hole Monobore completions. If the 7-5/8 inch (L-80, 29.7 pound) casing string cannot be set deep enough, a production string of 5Y2 inch (L-80, 15.5 pound) casing crossed over to 3Y2 inch (L-80, 9.3 pound) casing will be set to isolate the Tarn interval. These monobore wells will be completed with 3Y2 inch (L-80, 9.3 pound) production tubing. 20 \ ) Tarn Oil Pool Rules Testimony ) April 28, 1998 Case 3) 4Y2 inch Monobore completions. This casing program employs 9- 5/8 inch (L-80, 40 pound) surface casing with 7 inch (L-80, 26 pound) production casing crossed over to 4Y2 inch (L-80, 12.6 pound) production casing. All three well types may be completed for either production or injection service. The service of the well will be determined after logging operations. Drilling and completion plans for future Tarn wells may vary with time as experience and knowledge are gained. AAI proposes that the Tarn casing and cementing rules be written as specified in 20 ACC 25.030 and in accordance with the current Kuparuk River Field rules as summarized below. 1) For proper anchorage and to divert an uncontrolled flow, a conductor casing shall be set at least 75 feet below the surface and sufficient cement will be pumped to fill the annulus behind the casing to surface. 2) For proper anchorage, to prevent an uncontrolled flow, and to protect the well from the effects of permafrost thaw-subsidence and freeze-back, a string of surface casing will be set at least 500 feet measured depth below the base of the permafrost section. Sufficient cement shall be pumped to fill the annulus behind the casing to surface (across the permafrost interval.) If the cement level in the annulus falls down-hole after the completion of the job, a top job will be performed. 3) The casing will be designed to withstand the maximum stresses imposed on it during the life of the well. Casing designs will employ the safety factors outlined below. Approved Casing Grades & Connections Tension design factor = 1.4 or higher Burst design factor = 1 .0 or higher Collapse design factor = 1.0 or higher To prevent well failure due to permafrost action, the operator shall install surface casing including connections, with sufficient strength and flexibility to prevent failure. The surface casing, including connections, will have minimum post-yield strain properties of 0.90/0 in tension and 1.26% in compression. To be approved for use as surface casing, the Commission shall require evidence that the proposed casing and connections meet the above requirement. Several types and grades of casing, with connections, have been shown to meet the strain properties mentioned above, and have previously been approved for use by the Commission (see partial list below). Other means for maintaining the integrity of the well from the effects of permafrost thaw-subsidence and freeze-back, based on sound engineering principles, may be approved by the Commission upon application. 21 ) ) Tarn Oil Pool Rules Testimony ) April 28, 1998 Approved Casing Grades & Connections 7-5/811 29.7 ppf L80 BTC 9-5/811, 36 ppf K55 BTC 9-5/811 40 ppf K55 BTC 9-5/811 47 ppf L80 BTC 4) Intermediate casing is not required and that the initial three proposed Tarn well designs (utilizing conductor, surface and production casing) be allowed. However, intermediate casing may be used where either dictated by hole problems or in preparation to drill an over-pressured zone. 5) In addition to conventional cased and perforated completions, the following alternative completion methods: a) Open hole completions provided that the casing is set not more than 200 feet above the uppermost oil bearing zone b) Slotted liners, wire-wrapped screen liners, or combination thereof, landed inside of cased or open hole c) Horizontal completion with liners, slotted liners, wire-wrapped screens, or combination thereof, landed inside the horizontal extension or open hole d) Multi-lateral type completions in which more than one well bore penetration is completed in a single well, with production gathered and routed back to a central well bore. 6) The Commission may approve other completion methods upon application and presentation of data showing the alternatives are based on sound engineering principles. Although the standard program incorporates maintaining a tubing annulus with isolation and pressure integrity within 200 feet of the initial producing interval, as previously discussed, exceptions to this design criterion will be required to optimize recovery from potentially productive secondary targets. Blowout Prevention AAI proposes that the rule for blowout prevention in the Tarn Oil Pool be written identically to the provisions established in Regulation 20 ACC 25.035 (Secondary Well Control: Blowout Prevention Equipment Requirements) of the AOGCC regulations. Except as modified by the AOGCC regulations, blowout prevention equipment and its use will be in accordance with API Recommended Practice 53 for blowout prevention systems. 22 ) Tarn Oil Pool Rules Testimony ) April 28, 1998 Drillina Fluids The drilling fluid program for Tarn Wells will be prepared and implemented in full compliance with 20 AAC 25.033 in the AOGCC regulations. Good engineering practices, offset well data and continuous monitoring of the mud system will be utilized to ensure well control during drilling operations. Formation pressure data for the strata to be penetrated is known and documented based on the five Tam reservoir penetrations during the exploration phase. Annular Disposal of Drillinq Wastes Tarn development will utilize the practice of annulus pumping of fluids incidental to well drilling activities. Fluids will be pumped down an adjacent annulus. Cuttings will either be ground and injected with the fluid, or separated and transported to a permitted disposal facility. Annulus pumping will be performed in accordance with 20 AAC 25.080. Fluids permitted for disposal include, but are not limited to: · Waste drilling fluids · Drill cuttings ground into slurry form . Excess rig washdown water · Excess cement returns from casing and cementing operations · Cement rinseate fluids generated from cementing operations incidental to drilling the wells · Cement contaminated drilling fluids . Completion fluids · Formation fluids · Reserve pit fluids · Drill rig domestic waste water · Other substances that the Commission determines are wastes associated with the drilling of a well. Disposal of such wastes in existing, or future, permitted North Slope Class II injection wells is also a possibility, and will be employed at operator discretion. Wellhead and Production Tree Design Tarn wellhead and production tree designs will be similar to those employed at Kuparuk. All wellhead and production tree equipment carries the API monogram and meets or exceeds API RP 14C. 23 ) Tarn Oil Pool Rules Testimony ) April 28, 1998 Directional Drilling MWD surveys will be used for directional drilling operations. Continuous MWD surveys have proven to be as reliable and accurate as gyro surveys on the North Slope and will be used as the definitive survey. Tubing I Casina Annulus Mechanicallnteqrity Both proposed Tarn injector and producing wells will have an annulus and seal bore / polished bore receptacle as part of their design, ARCO will have the capability to pressure test the tubing / casing annulus to periodically verify the well's mechanical integrity. The casing testing method for Tarn wells will comply with the requirements of 20 AAC 25.412 (c). Sufficient notice of pressure tests will be given so that a Commission representative may witness the test. Subsurface Safety Valves Consistent with statewide AOGCC regulations (20 AAC 25.265) and current KRU Field Practice (as modified by Conservation Order 348), there is no apparent need for surface controlled sub-surface safety valves (SSSVs) in Tarn wells. In keeping with Kuparuk guidelines, velocity sensitive subsurface valves (e.g., "K Valves") may be set wells with very high potential production rates. Surface Safety Valves Surface safety valves (SSVs) are included in the wellhead equipment. As previously mentioned, these devices can be activated by high and low pressure sensing equipment and are designed to isolate well fluids upstream of the SSV should pressure limits be exceeded. Testing of SSVs will be similar to the practice in Kuparuk formation producing wells. Loaaina Operations The minimum log suite planned for Tarn includes resistivity, gamma ray, density and neutron logs. These logs will be obtained from MWD/L WD tools positioned in the drilling bottom-hole assembly. 24 ) ,I ) Tarn Oil Pool Rules Testimony April 28, 1998 Well Design Profile modification and control of thief zones will be primarily managed by controlling fluid injection in offset injection wells. Profile modification in this reservoir management scenario is greatly facilitated by the monobore injector designs that allow mechanical patches to be run on wireline and selectively placed across discrete perforation sets. 25 'ì~ Tarn Oil Pool Rules Testimony ) April 28, 1998 VII. Reservoir Surveillance Introduction This section provides testimony regarding reservoir surveillance and operations during production anomalies. Reservoir Pressure Measurements Pressures will be reported at a common datum of 5200 feet true vertical depth subsea. An initial pressure survey will be acquired for each well prior to establishing regular production or injection. On an annual basis, a minimum of one bottom hole pressure measurement per producing governmental section is planned. Allowable pressure survey techniques should include wireline RFT measurements, pressure buildups with bottom-hole pressure measurement, injector surface pressure falloffs, static bottom-hole pressure surveys following extended shut in periods, or bottom-hole pressures calculated from well head pressure and fluid level in the tubing of an injector which has been shut in a minimum of 48 hours. Pressure survey data would be reported to the Commission quarterly. Surveillance Logs Hydraulic propped fracture stimulations will limit the usefulness of production and injection logs. Surveillance logging will be used to monitor injection in wells that have not previously stimulated with hydraulic propped fracture stimulations. In addition, surveillance logs may also be employed when more than one zone is open in a single wellbore (e.g., wells with secondary targets). Gas Sampling Gas sampling will be periodically conducted during well tests during the miscible injection period of the flood. Compositional analyses will be performed on the samples to help gauge the effectiveness of the miscible flood. GOR Determination Gas-oil ratios (GORs) will be routinely measured during well test operations. Despite concurrent production and injection, the tight nature of the Tarn reservoir will cause primary depletion effects to increase initial gas production. This may 26 ) ') Tarn Oil Pool Rules Testimony April 28, 1998 cause GORs to exceed limits set forth in 20 AAC 25.240(b). Moreover, gas breakthrough from enriched gas and/or lean gas injection will also cause GOR measurements to exceed these limits. An exception to 20 AAC 25.240(b) is therefore requested. Production Allocation and Well Testinq Reservoir management and surveillance requires accurate production data. An Accuflow metering system will be employed that should ensure these requirements are met. The manufacturer's anticipated accuracy for the Accuflow system is a fluid rate accuracy of 1 %, gas rate accuracy of 3% and water cut accuracy of 1 %. To help ensure that accuracy is maintained, operators will be trained in proper testing practice (test stabilization, comparison to previous tests, etc.) and event tracking for Tarn wells. They will also be capable of detecting problems with test equipment. With a low back pressure imposed by the metering equipment and minimal flush volume required to void the previous wells fluids, stabilization times are expected to be minimal. Since low flow rate variance is anticipated, relatively short well tests should be operationally practical and accurate. These factors, coupled with fact that Tarn production will be essentially water free, should cause Tarn well tests to be more accurate than Kuparuk well tests. A test frequency of at least two well tests per month for each Tarn producer is planned. Variance analyses techniques will be employed to identify wells that may benefit from a more frequent testing schedule. Additional testing will be conducted as needed to ensure that well tests accurately represent production rates. Hence, Tarn producers will generally be tested more frequently than Kuparuk producers (which are required to be tested at least once per month). For the reasons discussed above, Tarn well tests should generally be more accurate and frequent than those at Kuparuk. Assigning an allocation of 1.0 to Tarn well tests for revenue and accounting purposes is therefore recommended in lieu of using the Kuparuk allocation technique described in Exhibit 8. This should be as accurate as the Kuparuk allocation technique and serve to reduce operating costs. Production Anomalies Production prorations at or from Kuparuk facilities will affect all commingled reservoirs produced through the facilities by an equivalent percentage of oil production, unless this will result in either surface or subsurface equipment damage, or increased operating costs. One potential operating cost concern particular to Tarn is paraffin deposition. A severe reduction in production through 27 ') Tarn Oil Pool Rules Testimony ) April 28, 1998 the Tarn flow line could cause paraffin deposition if ambient temperatures are low. 28 ) Tarn Oil Pool Rules Testimony ) April 28, 1998 VIII. Summary of Testimony The Tarn working interest owners are first and foremost committed to a safe and environmentally sound operation. The proposed drilling program meets or exceeds all requirements specified in the Commission's rules and regulations. Tarn facilities are designed to operate safely and efficiently. All well and facility designs meet or exceed the standards specified by state or national codes, the recommended practices of the relevant advisory organizations, and/or the time- proven practices of prudent operators. Plans are to make maximum use of the existing KRU infrastructure, thus minimizing environmental impacts while maximizing reserves for the Greater Kuparuk Area. Developing the Tarn Oil Pool presents many challenges. The reservoir is relatively tight and injector/producer interactions are expected to be impeded by tortuous flow paths. The localized nature of the sand accumulations coupled with multiple Tarn Reservoir horizons will complicate development efforts. Develop plans, which include ongoing seismic reinterpretation, sidetrack planning, phased development and minimizing the initial number of injectors until well interactions are better understood, should help address these challenges. A key element of the development plan is initially employing a tertiary recovery process. Reservoir studies support initially injecting enriched gas to help mitigate tortuous injector/producer flow paths while maximizing recovery. The flood will be operated with the intent of exercising the majority of flood control at the injectors. To facilitate Tarn Oil Pool development, exceptions to state wide regulations are requested for well spacing (AAC 25.055{a}) and GaR production limits (AAC 25.240{b}). Initial development plans call for 100 acre well spacing, however, 10 acre well spacing is requested to allow for flexibility in adjusting for reservoir heterogeneities (Le., sand discontinuities, permeability barriers, etc.). No GOR production limits are requested because of plans to initially employ an enriched gas flood. Maximizing recovery from the Tarn Reservoir will require a collaborative effort between the Commission and the working interest owners. Pursuing potentially productive secondary pay zones within the reservoir may result in some injectors having annular isolation more than 200 feet above the top perforation. An ongoing reservoir surveillance program coupled with development drilling results and additional reservoir modeling studies will be used to help optimize the flood. As additional information is gained, fully developing this resource may involve an areal and/or vertical expansion of the Tarn Oil Pool definition. Special emphasis has been placed on well testing because Tarn production will be commingled with KRU production in surface facilities prior to final processing. A test system that operates as close to producing conditions as possible will be 29 ) ) Tarn Oil Pool Rules Testimony April 28, 1998 employed to ensure accurate well tests. Given the accuracy of the well testing equipment, the minimal change in producing versus testing conditions and the lack of water production, an allocati'on factor of 1.0 is requested for the Tarn Oil Pool. A minimum of two well tests per month will be obtained. All volumes and tests will be summarized and reported to the Commission on a monthly basis. The development of the Tarn resource is made possible through the sharing of the existing KRU infrastructure. The Greater Kuparuk Area alignment agreements will help govern associated business issues. AAI looks forward to working through the challenges of developing the Tarn Oil Pool. Successfully developing this accumulation will provide additional infrastructure and insight that will prove invaluable in developing these types of satellite fields in the future. Thank you for the opportunity to present this testimony. 30 \~ ,) Tarn Oil Pool Rules Testimony ) April 28, 1998 IX. Proposed Tarn Field Rules Rule 1. Field and Pool Name The field is the Kuparuk River Field and the pool is the Tarn Oil Pool. Rule 2. Pool Definition The Tarn Oil Pool is defined as the accumulation of hydrocarbons common to and correlating with the interval between measured depths 5990 and 4376 feet measured depth in the ARCO Bermuda #1 well. Rule 3. Spacing Units Nominal spacing units within the pool will be 10 acres. The pool shall not be opened in any well closer to 300 feet to an external boundary where ownership changes. Rule 4. Casinq and Cementing Practices (a) Conductor casing will be set at least 75 feet below ground level and cemented to surface. (b) Where required for annular disposal, surface casing will be set at least 500 feet below the permafrost and be cemented to surface. Rule 5. Injection Well Completion (a) Wells may be employed for injection service provided a sealbore, packer, or other isolation device is positioned not over 200 feet above the top perforated interval. (b) Exceptions to Rule 5(a) will be permitted in cases where the distance between annular isolation and the top perforated zone exceeds 200 feet measured depth due to pursuit of secondary targets within the Tam Reservoir. 31 ) Tarn Oil Pool Rules Testimony ') April 28, 1998 Rule 6. Automatic Shut-in Equipment (a) All wells capable of unassistèd flow of hydrocarbons will be equipped with a fail-safe automatic surface safety valve. (b) Injection wells will be equipped with a fail-safe automatic surface safety valve. (c) Surface safety valves will be tested at six-month intervals. Rule 7. Common Production Facilities and Surface Comminalinq (a) Production from the Tarn Oil Pool may be commingled with production from the Kuparuk River Oil Pool and/or other oil pools in the KRU in surface facilities prior to custody transfer. (b) The allocation factor for the Tarn Oil Pool will be 1.00 for the first year of production to evaluate the allocation method, testing frequency and quality. (c) Each producing Tarn well will be tested a minimum of two times per month during the first year of regular production. (d) The Commission may require more frequent or longer tests if the allocation quality deteriorates. The operator may elect to employ the same allocation factor technique employed at the Kuparuk River Oil Pool if these additional testing requirements are deemed burdensome. (e) The operator shall submit monthly file(s) containing daily allocation data and daily test data for agency surveillance and evaluation. Rule 8. Reservoir Pressure Monitorinq (a) An initial pressure survey shall be taken in each well prior to establishing regular production or injection. (b) A minimum of one bottom-hole pressure survey per producing or injecting governmental section shall be measured annually. Bottom-hole surveys in as outlined in Rule 8(a) may fulfill the minimum requirement. (c) The reservoir pressure datum will be 5200 feet subsea. (d) Pressure surveys may consist of stabilized static pressure measurements at bottom-hole or extrapolated from surface, pressure fall-off, pressure buildup, multi-rate tests, drill stem tests, and open-hole formation tests. (e) Data and results from pressure surveys shall be reported quarterly on Form 10-412, Reservoir Pressure Report. (f) Results and data from special reservoir pressure monitoring tests shall also be submitted in accordance with part (e) of this rule. 32 ) Tarn Oil Pool Rules Testimony ) April 28, 1998 Rule 9. Gas-Oil Ratio Exemption Wells producing from the Tarn Oil Pool are exempt from the gas-oil ratio limit set forth in 20 AAC 25.240(b). Rule 10. Pressure Maintenance Project Injection for pressure maintenance and enhanced oil recovery will commence within six months after the start of regular production from the Tarn Oil Pool. Rule 11. Reservoir Surveillance Report A surveillance report will be required after one year of regular production and annually thereafter. The report shall include but is not limited to the following: (a) Progress of enhanced recovery project(s) implementation and reservoir management summary including engineering and geotechnical parameters. (b) Summary of produced and injected fluids by producing interval. (c) Summary of reservoir pressure analyses within the pool. (d) Results from any production/injection logs when more than one interval is commingled within a single wellbore. (e) Results of well allocation and test evaluation for Rule 7 and any other special monitoring. (f) Future development plans. Rule 12. Production Anomalies In the event of oil production capacity proration at or from the Kuparuk facilities, all commingled reservoirs produced through the Kuparuk facilities will be prorated by an equivalent percentage of oil production, unless this will result in either surface or subsurface equipment damage, or increased operating costs. Rule 13. Administrative Action Upon proper application, the Commission may administratively waive the requirements of any rule stated above or administratively amend the order as long as the change does not promote waste, jeopardize correlative rights, and is based on sound engineering principles. 33 ) ) Tarn Oil Pool Rules Testimony April 28, 1998 x. Proposed Findings & Conclusions ARCO Alaska, Inc., as the Tarn Oil Pool operator, respectfully proposes that the Commission make the following findings. 1. Initial development plans include approximately 40 wells, with roughly half the wells being drilled during 1998 and the other half being drilled during 1999. 2. The total number of wells included in the project for full development will be better understood after initial development drilling and production/injection data help address some of the uncertainties associated with reservoir extent and sand continuity. 3. Pursuit of thin, potentially productive secondary targets within the Tarn Oil Pool may result in annular isolation occurring more than 200 feet measured depth above the top of the perforated interval. 4. Injection of MI into the Tarn Oil Pool is scheduled to commence during late 1998 as facilities and wells associated with the project are brought on-line. 5. Water is not a desirable initial injection fluid because of potential formation damage and injectivity issues. Recommended Conclusions ARCO Alaska, Inc., as the Tarn Oil Pool operator, respectfully requests that the Commission make the following conclusions. 1. The Tarn Development plan, which initially employs an enriched gas EOR process, involves the application of a tertiary enhanced oil recovery method in accordance with sound engineering principles. 2. The use of an enriched gas EOR process is reasonably expected to result in more than an insignificant increase in the amount of crude oil that ultimately will be recovered. Requested Decisions ARCO Alaska, Inc., as the Tarn Oil Pool operator, respectfully requests that the Commission endorse an initial enriched gas EOR process for field development. 34 ') ') Tarn Oil Pool Rules Testimony April 28, 1998 LIST OF EXHIBITS Exhibit 1 Type Section of the Tarn Reservoir Exhibit 2 Tarn Pool Area and Interval Trends Exhibit 3 Top of Bermuda (T3) Structure Map Exhibit 4 Top of Cairn (T4) Structure Map Exhibit 5 Crude Composition Assay Exhibit 6 Composition of CPF-2 MI & Lean Gas Exhibit 7 Possible Tarn Completion Designs Exhibit 8 Kuparuk Allocation Technique Exhibit 9 AAI/BPX Alignment Agreement Exhibit 10 AAI/BPXlUNOCAL Alignment Agreement Exhibit 11 AAl/BPXlChevron/Mobil Alignment Agreement 35 ARca Alaska, Inc. <> Exhibit 1 Bermuda #1 Well Log 4/981 0 Hastinqs I 98042304AOC w c o .- .... as E I- o U. CD CD -.c o ca o CD Q.CJ) c I- as I- ) C30 ~ ~ T4 . _ 1.: Cairn 1~' Inte ~....._;" T3 Berm::~ - - - I ~~~+~ T2 _ _ nterval J ¡ -.~ T1 , C35 ~ - ~~- .~ 2 ? ~ -6000- I ·C30· Interval Arete Interval Iceberg Interval T6 -4500· ~ 1. C37 -5000- ~M~Y ÆS~~~n o.J1'I_' (Uti) :!: 1lD..PTE...$ (o-MoIl .... II'.' ¡;; 1.0 LM..oTE..S (otMoI1100 0 ~'-'"-' v.t) ~ 1.0 S'L..DlE..S (Q-t.4I.4IIOO.0 ...... ·Ie.' ~ 1.0 100.0 Bermuda #) ) MI... 0 Kllomet.... 0 \:' ....':~ Æ~,i, J ..~: ~~I, 'or,':, ,'~ß: ..~~~, , of::: ,", ') ':' ~.: , :~',,,~ ' ·~~t ;~r ' ':'.',:' '-,,..' '.~I ,'" -.. Proposed Tarp' Pool . 2 MI... 5 I<llomet.... ) Kuparuk River Unit W Sak 20+ ARC a Alaska, Inc. <> Exhibit 2 Tarn Pool Area and Interval Trends ,4/981 0 HastinQs I 98031101A02 I WSa l ~ \-51~ ARCa Alaska, Inc. 0 Exhibit 3 Top Bermuda (T3) Structure Map C.I. = 50' 3/981 D Hastings I 98032405A01 - o ~ r-----/ ( - \ 5400' '---../ Attachment #9 o .2 .4 .6 .8 1.0 MILES I ~rl#1 0/,; \ I( ( / 1/ ~ n~f:¡ ~ ~ / ) (óv Tarn~2 I I \ 7 I / , af" #JA \ \ I ~ ~ ~ I fl, ~ ~ / ~ c::. \ ~ f , /1 ¡ !;l .053 / / Tarn #2 \ ) 4ar;'n~#:: #3 Ira / I I (" ¡ ( ( \ \ r-.... I \ \, \ }~~so~ ~~ ~, I /' )~ 5184 -9-J ' be,« uc.a # I / :/ 5Z5450 / /\ , ... \ c '-, 555?Q- ",/ West Sak 2/,,4> /' ARca Alaska, Inc. <> Exhibit 4 Top Cairn (T4) Structure Map Col. = 50' 3/9B I D HastinQs I 97112502A01(9803) 1'248119 K[LO"[1fIlS~. . . ..!>.. . .1,IIIIILO"ETfRS $TATUTf MILn" ..2 . .!I . . D . .11 . 1,9 3TATUTf HIlf3 ) ) Exhibit 5 Crude Composition Assay Tarn No.2 Well Composition of Stock Tank Oil ( From Chromatographic Technique) Component Mol Wt Density MW Vol % % (gmlcc) % Propane minus .83 .18 ,5065 44.1 0.30 Butanes 2.90 ,83 ,5834 58.1 1.19 iso-Pentane 1.52 ,54 ,6241 72.2 0.73 n-Pentane 2.84 1.01 ,6305 72.2 1.35 Hexanes 4.95 2.10 ,6632 86.2 2.67 Methylcyclopentane 2.17 ,90 ,7529 84.2 1.01 Benzene .18 ,07 ,8836 78.1 0.07 Cyclohexane 2.05 ,85 ,7826 84.2 0.92 Heptanes 5.43 2.68 ,6875 100.2 3.28 Methylcyclohexane 3.58 1,73 ,7732 98.2 1.88 Toluene .93 ,42 8710 92.1 0.40 Octanes 6.40 3,60 ,7063 114,2 4.29 Ethylbenzene .42 ,22 ,8708 106.2 0.21 Sample Characteristics meta & para Xylenes .82 .43 ,8664 106.2 0.42 ortho-Xylene .48 ,25 ,8838 106.2 0.24 Total Liquid Molecular Weight ................................... 203.0 Nonanes 5.92 3.74 ,7212 128.3 4.37 Total Liquid Density (gm/cc) ...................................... 0.8414 iso-Propylbenzene .35 .21 ,8656 120.2 0.20 Total Liquid API Gravity ............................................. 36.5 n-Propylbenzene .44 .26 ,8656 120.2 0.25 1,2.4- Trimethylbenzene .44 ,26 ,8798 120.2 0.25 Decanes 5.57 3.68 ,7780 134.0 3.98 Undecanes 5.25 3.80 ,7890 147.0 4.05 Dodecanes 4.46 3.54 ,8000 161.0 3.73 Trldecanes 4.43 3.80 ,8110 175.0 3.96 Tetradecanes 3.62 3.39 .8220 190.0 3.47 Pentadecanes 3.26 3.31 ,8320 206.0 3.35 Hexadecanes 2.62 2.86 ,8390 222.0 2.87 Heptadecanes 2.39 2.79 .8470 237.0 2.77 Octadecanes 2.39 2,96 .8520 251.0 2.92 Nonadecanes 2.15 2.79 ,8570 263.0 2.74 Elcosanes 1.78 2.41 .8620 275.0 2.35 Heneicosanes 1.55 2.22 ,8670 291.0 2.15 Properties of Heavy Fractions Docosanes 1.48 2.22 ,8720 305.0 2.14 Tricosanes 1.35 2.12 ,8770 318.0 2.04 Tetracosanes 1.23 2.00 ,8810 331.0 1.91 Plus Fractions Mol Wt Density °API MW Pentacosanes 1.11 1.89 ,8850 345.0 1.80 % % (gmlcc) Hexacosanes 1.01 1.79 .8890 359.0 1.69 Heptacosanes .88 1,63 ,8930 374.0 1.54 Hexanes plus 91.91 97.44 0.850 34.7 215.2 Octacosanes .84 1.60 ,8960 388.0 1.51 Methylcyclopentane plus 86.96 95.34 0.856 33.7 222.6 Nonacosanes ,75 1.48 .8990 402.0 1.39 iso-Propylbenzene plus 58.58 80.45 0.883 28.6 278.8 Triacontanes .69 1.41 .9020 416.0 1.31 Undecanes plus 51.78 76.04 0.889 27.5 298.1 Hentriacontanes .61 1.29 ,9060 430.0 1.19 Pentadecanes plus 34.02 61.51 0.911 23.6 366.9 Dotriacontanes .54 1.19 ,9090 444.0 1.10 Eicosanes plus 21.21 46.80 0.934 19.8 447.8 Tritriacontanes .50 1,12 ,9120 458.0 1.03 Pentacosanes plus 13.82 35.83 0.955 16.4 526.0 Tetratriacontanes .44 1.03 ,9140 472.0 0.95 Triacontanes plus 9.23 27.44 0.977 13.2 603.2 Pentatriacontanes .38 ,90 ,9170 486.0 0.82 Hexatriacontanes plus 6.07 20.50 1.002 9.6 684.9 Hexatriacontanes plus 6.07 20.50 1,0019 684.9 17.21 Totals ........... 1100.001100,00 I 1100.00 Component MI Lean Gas (Mole 0/0) (Mole 0/0) CO2 1.0 0.9 N2 0.2 0.2 C1 66.0 80.9 C2 7.9 10.0 C3 5.4 5.0 iC4 2.4 0.8 nC4 7.0 1.6 iC5 2.3 0.3 nCS 2.8 0.2 C6 2.2 0.1 C7 1.9 0.0 CS+ 0.9 0.0 Miscible Injectant & Lean Gas Composition Supplied by the Kuparuk River Unit's CPF-2 EXHIBIT 6 ) ) Completion 1 FMC Kuparuk Gen V 7-S/8 x 3% 16" Conductor Casing at 135' RKB ~ .... Base of permafrost anù stage collar at 1,250' MD :::::[' ] . , CAMCO 2.7S" DS nipple ~ 04/27/98 r--i~ "oE ~ 0:':': I .0. Base of I Exhibit 7 - Possible Tarn Completion Designs Comp.let~on 2 FMC Prudhoe Geo V ~ ~ 9-S/8x5%x3% r. ~ cross over I . ~ ~ I 9-5/8/7-5/8 ---~';J I I r' .:¡j::¡ ::¡¡i:. 2.875" CAMCO~ I . mr DS nipple for .::: Possible K-Valve ~{:~ ., , .0. o. . 9-7/8" Hole ... . ;:::::; West Sak lilllll at 1.800' TVD 7-5/~:'2~;~~c;~ng ::!:::: 3W' or 4W' tubing r .~ BakerCMUSliding~ ~, I .. ::::::: '----' Sleeve wl2.813" DS- ~ ì ¡¡¡I -- Cameo profile _ ,~ Camco3W'x1" ~ ~ . Jkíg I¡¡¡ side pocket GLM ¡¡¡H: I~: ::::::: ::::::: SV2" Casing :::: ::: ::::::: ~*'- Baker Liner Hgr Seal Receptacle :::: ::: ::::::: ...:...... "F, ::::::: wILlner Top Pkr (CSR) :::: ::: '-5/8" Surface Casing :::~:::::: ::::::~::: ::;" .:':'. at 5,000' TVD ~{~~ ~:::::~~ Cr~~s,~d °b~er to ~~~I {~~~ ....... ....... ,;,-/2 tu lng ....... ....... ..':'.':'.':'.' ~.::~; at 5,000' TVD ::::::: ....... .. :~ 6W' How U 3W' or 4th. Prod. Csg U 3W' Production Casing at 5,200' TVD at 5,200' TVD :1-1/2" Slimhole TnhinfJless '1 1 ,"'" C"':.._I_ ,.',1\'" ..- 1 o. . " 6-%" Hole 31/2" tubing ~ Completion 3 ~ ~ ~ ~ "'E ~ ::::::: 3.875" C",-,O ::::::: DB nipple for :~:}PosSible K Valv FMC Prudhoe Gen V L-, 9-5/8x7x4% r ~ .... 12lJ4" Hole Base of permafrost at 1 ,250' MD ... . Base of West Sak at 1,800' TVD a 9-5/8" Surf. Csg. at 2.500' TVD 81h" Hole CAMCO 2.7S" DS nipple / , " I 31/2" or 41/2" tubing ~aker CMU Sliding Sler I w/3.812" Ca,,_/ ~~{ prof9. '.:.:.: profi e ÌL. }~ ,~& Cameo 4W' x 1" }~:~ side pocket GLM 7" Casing Seal Receptacle (CSR) Crossed over to 4th" casing at 5,000' TVD ...... . .:-:.:.:_.:.:.:' '.:.:.:.:.:.:. 31/." or 41/." Csg :.:.:.:.:.:.' '.:.:.:.:-: y2 y2 ::::::::.' '.:::::: at 5,200' TVD 4-111." Mnnohorp rnmnlptinn Exhibit 8 Simplified Kuparuk - Tarn Well Test Allocation Methodology General Allocation Factor = Actual Produced Volume Theoretical Volume Tarn Allocation Factor = 1.0 (Applicable to oil, gas and water test rates) ~ Kuparuk Oil Factor = CT Dry Vol. + KRUTP Net Dry Vol. - KRUTP SO tank - L Kuparuk NGL's - L Load Crude/Diesel - L Satellite Well Test Oil Vol. L Kuparuk Well Test Oil Vol. Kuparuk Water Factor = L Injected Water Vol. - L Satellite Well Test Water Vol. L Kuparuk Well Test Water Vol. ..~ Kuparuk Gas Factor = L Injected Gas Vol. + L Kuparuk NGL's + L Fuel + L Flare - L Satellite Well Test Gas Vol. L Kuparuk Well Test Formation Gas Vol. Notes: 1) Satellite well tests would initially include West Sak and Tarn. 2) Kuparuk well test rates are multiplied by the above factors to obtain allocated rates. .' ~~Gt!U (2"@$'t; r..,., &£111J2.l.1gr 1.'"(;[ -LiT ,"-c ng Heari Tarn Area Injection Order '-' 1998 28, Apri I Tarn Area Injection Order Hearing Application Requirements . ~Lu\!~@'@~'L; i!!IfI!Iil!.::- L l2LíS1~ '1r5n~tü 20 AAC 25.402(c) "----/ - 14 Requirements 4 Covered During Pool Hearings 10 Covered with Additional Testimony April 28, 1998 Tarn Area Injection Order Hearing Pool Rule Hearing Reference . ~L(2\1tt€t~ljJ·~g ~&.. LéHfS' '1/r5LN..LÜ Area Injection Order ._-~/ Proposed Operation Depth & Name of Affected Pool Casing & Testing Methods for Injectors Incremental Increase in Ultimate Recovery -~ April 28, 1998 Tarn Area Injection Order Hearing Discussion Topics . .l5iI::I Lu l'l G'@$'ßç i!!!IfIØ S:.. L uni.'@! lPGb~ntÜ Area Injection Order - Existing Penetrations within One-Quarter Mile - Operators & Surface Owners within One-Quarter Mile - Affidavit of Notification - Type Well Log (Injection Wells) '-.' - Formation Proffered for Injection & Confining Zones . --' \ 700 - '8 Ð ê) (,jl...c...Qe-s - ~~ I - Water Analysis '- JbV - ~J..OO '- '1J91.. - Applicable Freshwater Exemption -J}!J b .[3PI'1; Injection Fluid Data ,- )1 ~\'y.:>,,"Q , l ( B6'¡ð _8'J-oD '-3<JDt' .s~\ -Lv~~ wc"-. -y I Estimated Pressures -1 q;;., ~s:-~,~f ) 1/ ' ( sL,..Q. ~ _s,/oo I - r¡r¡o~ (j ~ F-'·HJ~;" ~ Evidence of Injection tonfinement Ý ---. I April 28, 1998 ) :) Tarn Area Injection Order Attachment 1 A ~<v ~ " ,~ ",\ 1 :3.~·:'· . ... .:~~ .' ',. ':, . " _ f,l . . ~ .... . ".. .{ .< ,,',~: , ,"..,' ""-. '/ \ 1'~ .',','.. . ..·';ó: 3e " 31 e "':,'H', ,'." ~ -! , ~ )":, I ~;~. .~.~, : .'i I ~,t~ ",'., .r" '..... ~ ~( I T e 0 W !4;rk $'('1 ~. ;1>. . ~l 3& , ~~ '::',: g,. ~r ~~ :¡~F ,,:,':/, / "~"'O';', ~~ t?' -::~t,/ 3\ ,.~y,( :~~;. -.' ,. .1 .:1·, ',; '" ,'!/L3,!~,., >}f " ßl":',;, ....... ·\,~.l · ;..~..~~~~J;(~?r;:,~~:~~.; , :::? .;,' . ' '. . ~ . .. , I·~.·.. ... ..~'. \ ..... .." ... ,..,.... ...~'i;'~~tf;~:~;~;!!~r. ··'~I ,~;{. ",' '.':; Pro oSEd'Tar~ -00-:1:" ' ,;,'..: :q:-, '"",,",',", ,'.: ':"""" P" . " ,..:::'. .,"""-:;,,,,:;~~:,..~::.,, ' ',:::'." ::~¡"~' . _,:~, '".: .. "'- '_:'.~,,~,>',': '.~: ~ :~..:>." :-.7.....'.~:·'\\~..\:.::~,:::·.,:.:.-;;·':::\....::',~,~...':..: ...:\"< 4,'-' ~ " ,~ ",\ C'ò'v ~ " -~~ "'... ~p3r~l( Ri'/er Unit . Planned 1998-99 Producers .. Planned 1998-99 Injectors . Planned 1998 Exploration Penetrations o Pre-1998 Exploration Wells I I I ARCa Alaska, Inc. <> Plat of Wells Penetrating Injection Zone uu.o KlIomeWI 0 2 .... SKI...... 3/98 I D HastinQs \ 98031103801 Bermuda #1 ) ) Attachment 7 GANMARA Y RESlSITIVITY .....ft , '0_1 LD..ÞTI!_S (OHNM) .... - ..... F= '.0 UI...DTI!_S (OtINMjIOO 0 ".Dft.' (MIll R, '.0 ~~_S (Q1MMjIOO.O ., .... ..... 15 '.0 100.0 Tarn Pool Type Log (Bermuda #1) C37 " -4500- ,~ . .. \ f Iceberg Interval ""- - -}- c 0 .- ( .... ca -saaa- ...:. E : ... 0 u. Arete CD CD Interval -.c o ca T4 o CD t- Cai rn D.cn c Interval ... ~ T3 ca J -..... Bermuda I- Interval ~ - T2- - - -~ T1 1 C35 ·C30· ARC a Alaska, Inc. <> ~ ~ . Interval ")Jr -..... Bermuda #1 C30 w Well Log 4/981 D HastinQs I 98042304AOO " ~ 4/98 ì D HastinQs I 98042303AOO Bermuda #1 Well Log ARca Alaska, Inc. <> Attachment 11A Tarn Pool Type Log (Bermuda #1) C30- \II T t II:- --?~ : 1- -....-~ ~¿~~~~-~-s~ ,¡¡I=-- f-()UU u..J - o o ~ c - ca I- -4500- ') ) Bermuda #1 GAMMARAY Rest SITIVlTY GR..oTE_S (GAPlI ::r: R.DJ)'11LS (OH~) 50.0 uo.o b: 1.0 IUIJ-D1"E-S (OH~) 100.0 ::;P.,DTE_S (MV, ~ 1.0 SFLD1E_S (a-tMN)IOO.o -150.0 -50.0 1.0 100.0 -2500- ~ ~ C80- ~ ~ ~ 'T ABASeO' - :~ - .,. ~ ~ -3000- ~ r- ei) eI) -I - 0 eI) ...... u ~ c :,- .,¿ .- ~ - -3500- \ j.~ - - ~ ~ :~...: ~ - - ca 3: eI) - ca .c en C37- " ARca Alaska, I nc. ~> Sinclair Colville #1 Well Log I 4/98 I 0 Hastinqs I 98042305AOO Log of Tarn Type Well (Sinclair Colville #1) Attachment 11 C ) ~ ~ 0- - --- , --- .c ?~ ~ .c ~ en m ca ß en - (1) m c: 0 -:~ en N ~ ~ c: co 0 J: o- m .... '-'----- CJ ~ os: Q) - 0- c: - --- Q) c o N .... c Q) E Q) c ;: c o (.) I CD - as .c tn ~ as C) c S2 I~ \1 ~~ -~~ ~~ .~-.. -,," -e 5 00- ~_ :--.-c:-- -r;_,". _._. ~-==r = - -C--: =-. I - -~ ~;.~~ = , ..,....;r 1,.---~~ :::;- ~~ ~ ~ -::ë -:: ~ ~' -Jt ~- ~ ~ ":.- ~ ::..s .~1 .--.--.,-..~" --------- ~5 ocr ~~ ~ ·'·S -~ ...;;::¡,,¡.- ~~ ~ .~ ~ ~ .3- i :-~- i ...~ ~ r .i== ~. ~- :...~ ~ ..... ~ ~~dc~~-=----- --;.~ - ~ .~-_.~ :-- .~.-'_._.,-- =-~ - -::~~~- ~=_-: -8000- ct- ·~-~~==:1~ -~~~._- -=7500- ..:ro 00- -6000- ~""""'" ..-.--._-~ ~:::~ .GAMMARAY RES ST'¥ TY R ID OHMM ) G R :'GA P n 1 0 , 00 0 o 0 1 50 C R 1M PHv'lM} G R ~.c:iA p n :J: 1 0 1 00 0 ,-.----~.-- " -,-,..:,..----".... Ll.B PHv'lM ) 1500 3000 o..w C 1 0 1 00 0 ) ) ) Tarn Area Injection Order Attachment 13A .....~ ...--.-...................- or·: -.. -... '._ . ~, ._,,,,,,_.~ ............,."...'... ....,.. ,,' . .' - n;-..-·'.....--·-·· -- --,;. -,~ i ~, '~ ~ l' '.__w__,~ ,- -- , " II . , ...."""··~,.......,._._..M-.-____6~_._.._.'......_... ..f'" ..-.. ........ ....... ",... . ............... . ..,~.,.fH,'.__.-... ......- .~.._--.....- .~.........~ , ~.....,"""" ~ - - ,... . ...." " ..,.,..-- ........- ....,.........--..-.,¡ -....... '" . -, :',~ --- ~- - -;--1""-"·--' -.-----" - """"- - -, - .......-.. ~ .... .-, .. ...-.-...--...-... - ..... ...-....----.., '--'-.-. .. -...".,"'-"-.-..,----.. Kuparuk River Unit -.-..-....--... -...-, --\.'-. -'- .--"'JII r". i i i ! '\- , -...----- ~-"'-- f r~ .- ..~-_. ,..............----~ .. -" -. -- ~..'" - ¡ ..~.---- ~.. .......___...__...1.._...__-.-_ . _, _a _.................. ......... ..-----.--...--'-"',......... .-----............... ~ __ "'....... ~......_'OI.._..---. . u....................... . -...-.-""...~. ,,~..~.......... --'-"-- -----.....- --'~""""""'" '..~-- ;UIC Exemption Area ,~,-....,,_.. ... 0 2 ..... KIIOm.'" 0 . - J K~Ø_._IU. ... . .-I~~· ","". - -- ..-'~'."-,"- ....-............ -.. -,_.......~.-.._.~_:..,..-..__....._. Tarn Proposed r/ /I Injection Area ARca Alaska, Inc. <> ule Exemption Area: Tarn Proposed Injection Area 3/98 0 Hastinas I 98031102AOO April 28, 1998 .~ Component MI Lean Gas (Mole %) (Mole %) CO2 1.0 0.9 N2 0.2 0.2 C1 66.0 80.9 C2 7.9 10.0 C3 5.4 5.0 iC4 2.4 0.8 nC4 7.0 1.6 iCs 2.3 0.3 nCs 2.8 0.2 Cs 2.2 0.1 C7 1.9 0.0 Cs+ 0.9 0.0 --" MI and Lean Gas Compositions ·.¡1':£~~~Gý~b Injection Fluid Data Tarn Area Injection Order Hearing #5 ') ) ARca Alaska, Inc. Kuparuk Development Post Office Box 100360 700 G Street Anchorage, Alaska 99510 Telephone 907 265-6806 ~~ ~~ Ryan Stramp, Tarn Coordinator April 27, 1998 Mr. David Johnston Alaska Oil and Gas Conservation Commission 3001 Porcupine Road Anchorage, AK 99501 Re: Tarn Area Injection Order 20 AAC 25.402 Dear Sir: ARCO Alaska, Inc. (AAI) is pursing development of the Tarn Reservoir through an expansion of the Kuparuk River Unit. (Parallel efforts to expand the Kuparuk River Unit and formulate pool rules to facilitate Tarn Reservoir development are in progress.) AAI briefed the Commission on Tarn during a February 3, 1998 meeting. AAI in its capacity as operator submits this letter as an application for Alaska Oil and Gas Conservation Commission approval to conduct an enhanced recovery operation involving initial miscible gas injection, consistent with 20 AAC 25.402 (a). Approval of this application would permit these operations to be conducted in the Tarn Pool within the initial area targeted for development. The following attachments are submitted pursuant to 20 AAC 25.402 (c): 1. Plat with location of all existing wells that penetrate the injection zone within one- quarter mile of the area covered by this application 2. List of operators and surface owners within one-quarter mile of the proffered injection operations 3. Affidavit showing the operators and surface owners within one-quarter mile of the area affected by the Tarn Area Injection Order have been provided a copy of this application 4. Full description of the proposed operation 5. Description, depth, and name of the pool to be affected 6. Description of the formation into which fluids are to be injected and the associated confining zones 7. Type well log 8. Casing description and proposed method for testing injection well casing 9. Injection fluid data 10. Estimated pressures ARCO Alaska, Inc. is a Subsidiary of AtlanticRichfieldCompany ) '.) 11. Evidence and data to support a commission finding that injection wells will not initiate or propagate fractures through the overlying strata 12. Analysis of the water within the formation 13. Reference to applicable freshwater exemption issued under 20 AAC 25.440 14. Incremental increase in ultimate hydrocarbon recovery. I appreciate your work on this application and would be happy to answer any related questions. I can be reached at 265-6268 or rstramp@ mail.arco.com via the internet. Sincerely, ? ~ <;;~ ~n Stramp Tarn Coordinator Cc: Mike Kotowski ) ) Tarn Area Injection Order Attachment 1 20 AAC 25.402 (c)(1) Plat of Wells Penetratina Injection Zone The attached map (Attachment 1 A) shows all existing wells that penetrate the injection zone in the proposed injection area. The map also shows Tarn Reservoir seismic anomalies and the proposed Kuparuk River Unit expansion area. Although the exact acreage of the expansion has not yet been finalized, this map shows its largest possible extent based on current expansion efforts. In addition, the map shows Tarn development wells (with their expected service) planned to be drilled during 1998 and 1999 and Tarn exploratory well penetrations planned for 1998. Initial well location and service plans will likely change as net pay and well performance data are gathered. The total number, type and locations of wells ultimately drilled into the Tarn Pool will also be a function of net pay and well performance data. Since Tarn Reservoir distribution is stratigraphically controlled and sand accumulations are localized, sand continuity is expected to be difficult to predict. Producer/Injector interactions will likely be difficult to predict in the absence of field data. Development plans call for minimizing the number of injection wells until producer/injector interactions are better understood. Producers will be converted to injection service as necessary in order to provide pressure support and minimize injectant cycling. Hence, to as large of an extent as possible, plans are to let reservoir performance be a guide in optimizing pattern configurations. Although initial development plans do not include a Class II disposal well, future needs may eventually require one. The Ivishak Sandstone of the Sadlerochit Group has been selected, if needed. This zone is expected to have at least 60 feet of sandstone with porosities greater than 15% in the vicinity of the Tarn Participating Area. The Ivishak depth is expected to be approximately 8500 feet subsea. Several exploration wells have been drilled to this horizon in the vicinity of the Tarn Participating Area, in particular, the Union Kookpuk, Union Itkillik River and Sinclair Colville wells. The Ivishak Sandstone was wet in each of these wells and is therefore also expected to be wet in the vicinity of the Tarn Participating Area wells (see Sinclair Colville log section, Attachment 11 c). The Ivishak Sandstone, as well as the overlying Shublik Formation and Sag R. Sandstone, was wet in each of these wells. This zone is therefore also expected to be wet in the vicinity of the Tarn Participating Area. The Ivishak Sandstone is separated from the overlying Kuparuk River Formation by approximately 1800 feet of shales of the Kingak Formation, as well as approximately 400 feet of Shublik and Sag River Sandstone. ) , ) Tarn Area Injection Order Attachment 1A t{tv ~ ~<r ~ ;' ;' ,~ ,,-'- , ~.\~::,:' ":,,. 11:' .... ...9 . ...... . ........ ,.;.::¡ :"'" ..\ d~"'¡'~' .' ~\', ;i¡~· .I'Y· ,~ ~\ 36 31 6 I ' . 'v, :::,',""1,:,.':',::0:> ',',':.1,1."', ·'"r·: :1.:1 ; ~~.::: ::' ~ ~::. :.', :I>'·~"I.·,,·:·:~ ' 't. ,"J\ro~ô ;.' '&, ,.', 36 ...... ~ ::::,1'" ' .: I (v ~Cò ;' :.:l :~~ ,I, . Planned 1998-99 Producers ~91"X .~ÿ~/~. I',: '9: ,.r' ?f. ;:, ( ;' ... Planned 1998-99 Injectors . Planned 1998 Exploration Penetrations 36 91 31 o Pre-1998 Exploration Wells I I I ARCa Alaska, Inc. <> Plat of Wells Penetrating Injection Zone :)~~;:í. ' .?~~~"-::: : ".:;.'.1 I'í . ..:,.'.'.'..':.'......'......... '''.-:~. :~~~ .<1',' , , }t~;·!·· ' "':,~\~,~~ ,..:~:(.:¡. : , , . . -' . .. , , , . . , , " ,'. '. P~opOSEdT~r'P()()! .1 . , , . .' MU..O KI~O . 2 MIIH 6 KllOIIIItera 3/98 10 HastinQs I 98031103801 ì ) Tarn Area Injection Order Attachment 2 20 AAC 25.402 (c )(2) Operators and Surface Owners within One Quarter Mile of Injection Operations Operator: ARCO Alaska, Inc. Attention: Scott Jepsen A TO-1220 P.O. Box 100360 Anchorage, AK 99510-0360 Surface Owner: State of Alaska Department of Natural Resources Attention: Mike Kotowski P.O. Box 107034 Anchorage, AK 99510 ') ) Tarn Area Injection Order Attachment 3 20 AAC 25.402 (c )(3) Affidavit of Ryan L. Stramp Regarding Notice to Surface Owners Ryan L. Stramp, on oath, deposes and says: 1. I am the Tarn Coordinator at ARCO Alaska, Inc., the designated operator of the Kuparuk River Unit (which will include the Tarn Pool). 2. On April 27, 1998, I caused copies of the Area Injection Order Application to be provided to the surface owner and operator of all land within a quarter mile of the unit as listed below: State of Alaska Department of Natural Resources Attention: Mike Kotowski P.O. Box 107034 Anchorage, AK 99510 ARCO Alaska, Inc. Attention: Scott Jepsen A TO-1220 P.O. Box 100360 Anchorage, AK 99510-0360 STATE OF ALASKA ) ) ss. THIRD JUDICIAL DISTRICT ) ~CN)(.S~ ( Ryan L. Stramp J SWORN to before me this 2th day of April, 1998. ~~~ III :i/llJ~ . t.· PUBUC ..~ ~ NOTARY PUBLIC IN AND FOR ALASKA . ~¡lrr¡:(~ My Commission Expires: 10 -( <¡ - r-r·· ~/Jt"'flm\\\'\~ ') ) Tarn Area Injection Order Attachment 4 20 AAC 25.402 (c)(4) Description of the Proposed Operation The Tarn Area Injection Order is needed to develop the Tarn Reservoir. The expected scope of the current development project involves drilling approximately 40 wells to develop 42 MMBO associated with an estimated 136 MMBO original oil in place (OOIP) seen by existing exploratory wells in the Bermuda Interval of the Tarn Reservoir. Although Attachment 1 A shows 48 penetrations, this is considered an upside case. Field Development Development wells will be drilled from two new drill sites. A phased development approach is planned to help minimize risk associated with the Tarn Reservoir (e.g., reservoir extent, pay thickness, permeability, etc.). The first phase of the project involves drilling approximately 20 wells starting during the second quarter of this year. Production would be initiated by yearend. Wells drilled during the first phase are intended to develop the main portion of the reservoir and test the periphery. The second phase of the project involves drilling approximately 20 more wells starting during the second quarter of 1999. The second phase is intended to primarily develop the periphery. Well performance data and improved seismic calibrations acquired from the first phase should help guide drilling operations during the second phase. Exploratory drilling targeting other zones within the Tarn Reservoir will be conducted concurrently with development drilling operations. Successful exploratory drilling results could alter existing plans by (1) changing the location and target interval of the initial development wells and (2) expanding the scope of the project to include additional wells. An expanded project scope would likely involve additional development drilling phases and may include additional drill sites. An expanded project scope may require an areal expansion of the proffered Tarn Area Injection Order. Recovery Mechanism The tight nature of the Tarn Reservoir (with an average air permeability measured at 9 md from core in the ARCO Tarn #2) coupled with expected sand discontinuities and permeability barriers will complicate pressure support efforts. Injection plans are to employ a relatively large slug of miscible injectant (MI) followed by a lean gas flush. Initial injection support is planned to commence no later than six months after first production. Initiating an enhanced oil recovery process from the start will achieve optimal recovery in a tight formation such as Tarn. Injection fluids are needed to sweep oil to the producers. Providing initial pressure support with immiscible fluids, such as water or lean gas, would , ) have detrimental impacts on the initial development project and/or a future enriched gas injection project. Water is not a desirable initial injectant because of two principal reasons. First, laboratory core flood experiments suggest that water injection may cause formation damage. Second, water is much more viscous than MI. Maintaining pressure support with water would require a relatively high number of injection· wells because of the low permeabilities and tortuous flow paths associated with the Tarn Reservoir. This would act to either significantly reduce production rate and/or significantly increase the total number of wells required for development. Screening level simulation runs were performed to evaluate initially waterflooding Tarn. These runs were made using extremely optimistic assumptions (Le., no formation damage and a matrix injection pressure 1500 psi greater than the reservoir parting pressure). Even with these optimistic assumptions, water could not compete with MI as an initial injection fluid. Further model runs with more realistic water injection assumptions were therefore not performed. Lean gas is not a desirable initial injection fluid as it would strip light ends from the Tarn crude. This would make it more difficult to achieve miscibility with an enriched natural gas at a later date. It makes little sense (from a reservoir standpoint) to initiate a flood with lean gas injection when an enriched gas EOR project is eventually planned. Once MI and/or gas cycling begins to occur, plans are to investigate a variety of remedial techniques. These include, but are not limited to, foam, polymers and water. Furthermore, employing sustained water injection to help provide pressure support following the lean gas flush is still considered a possibility. Additional field data (Le., reservoir permeabilities, injector/producer interactions, formation damage pilots, etc.) and simulation studies are needed to evaluate this possibility. Injectant Sources The miscible injectant employed at Tarn will initially be the same injectant as that currently used in the Kuparuk River Unit Large Scale EOR Project. This injectant is manufactured at Kuparuk's CPF-1 and CPF-2 by blending lean gas from the Kuparuk River Unit's production facilities with light hydrocarbon liquid streams from the Prudhoe Bay Unit and Kuparuk River Unit. The light liquid hydrocarbons from the Prudhoe Bay Unit are NGLs from the CGF. The light liquid hydrocarbons from the Kuparuk River Unit consist of scrubber liquids from artificial lift gas compression systems at CPF-1 and CPF-2, NGLs from CPF-1 and naphtha from the Topping Plant. During the flood, there is a possibility that Tarn produced gas may be blended with Kuparuk River Unit MI to generate a lighter MI blend customized for the Tarn Reservoir pressure and oil properties. Slim tube experiments and compositional modeling both demonstrate that MI from the Kuparuk River Unit is richer than needed to maintain miscibility with Tarn oil at reservoir pressure (2350 psig in the ARCO Tarn #2 well). ) ) Lean gas will be injected into the Tarn Formation after MI injection targets have been met. The purpose of the lean gas will be to recover previously injected MI and help provide pressure support. The source of the lean gas will be Kuparuk River Unit's CPF- 2. Potential gas accumulations in the area will also be considered as possible supplemental sources. Fluid and Cost Allocation Tarn production will be commingled with Kuparuk production in surface facilities prior to final processing and ultimate custody transfer in accordance with the Tarn Pool Rules (currently being developed). The Greater Kuparuk Area Alignment Agreement, which set new tract ownership and facility sharing terms in the Tarn area, will help govern business issues associated with sharing infrastructure. The Tarn production interests are as follows: ARCO Alaska, Inc. BPX UNOCAL MOBIL CHEVRON 0.552937 0.392823 0.049506 0.003648 0.001086 Total 1 .000000 ) ) Tarn Area Injection Order Attachment 5 20 AAC 25.402 (c){5) Description and Depth of Pool to be Affected The Tarn Reservoir is the sequence of reservoir sandstones and associated mudstones found in the interval between 4376 and 5990 feet measured depth in the ARCO Bermuda #1 well, and in its lateral equivalents (see log section shown in Attachment 7). The Tarn Reservoir is late Cretaceous in age and stratigraphically within the Seabee Formation. The reservoir is approximately 1600 feet thick and is composed of five intervals. The initial Tarn Oil Pool includes the entire Tarn Reservoir, however, the pool definition may change as additional information from development and exploratory activities becomes available. Two Tarn Reservoir intervals, the Bermuda Interval and Cairn Interval, are sufficiently understood for development operations. Initial injection will be restricted to these two intervals. An expansion of injection operations (both vertically and areally) may be sought in the future depending on results from upcoming drilling activities. All five Tarn Reservoir intervals are shown in the wireline log from the ARCO Bermuda #1 well. Brief summaries of these intervals are given below in ascending order. · The 'C30' Interval was encountered between 5990 and 5716 feet measured depth in the ARCO Bermuda #1 well. The boundaries are correlatable markers C30 and C35, respectively. Potential reservoir sands here were wet but may be hydrocarbon-bearing laterally. · The Bermuda Interval was encountered between 5608 and 5542 feet measured depth in the ARCO Bermuda #1 well. The boundaries are correlatable markers T2 and T3, respectively. Hydrocarbon-bearing sands in this interval were encountered in the ARCO Bermuda #1 and in four offset wells. · The Cairn Interval was encountered between 5452 and 5316 feet measured depth in the ARCO Bermuda #1 well. The boundaries are correlatable markers T3 and T 4, respectively. Hydrocarbon-bearing sands were encountered in the correlative interval in one offset well. · The Arete Interval lies between 5316 and 5105 feet measured depth in the ARCO Bermuda #1 well. The boundaries are correlatable markers T4 and T6, respectively. Seismic data indicate that reservoir sands may be present in laterally equivalent strata. ) ) . The Iceberg Interval is encountered between 5105 and 4376 feet measured depth in the ARCO Bermuda #1 well. The boundaries are correlatable markers T6 and C37, respectively. Seismic data indicate that reservoir sands may be present in laterally equivalent strata. ) l Tarn Area Injection Order Attachment 6 20 AAC 25.402 (c)(6) Description of the Formation The proposed injection zone includes the Cairn Interval and the upper portion of the Bermuda Interval within the Tarn Pool. This zone lies between 5316 and 5608 feet measured depth in the ARCO Bermuda #1 well (see Attachment 7). The Cairn Interval lies between reservoir markers T3 and T4 while the Upper portion of the Bermuda Interval lies between reservoir markers T2 and T3. The Tarn Pool sands are fine- to very fine-grained and have common shale laminations and interbeds. Sands are compositionally heterogeneous: the major components include quartz, heterolithic rock fragments, plagioclase and zeolite. Shale laminations are common. Reservoir sands, which are locally developed within each interval, are lobate to linear in form, and are separated from adjacent reservoirs by mudstones and shales. The top of the Tarn Reservoir is separated from the Tabasco Sandstone equivalent, the first overlying potential reservoir zone, by a confining layer of approximately 1500 feet of impermeable shale (Attachment 11 a). The base of the Tarn Reservoir is separated from the underlying Kuparuk River Formation by approximately 500 feet of shale. 4/98 I D Hastinqs I 98042304AOO Bermuda #1 Well Log ARca Alaska, Inc. <> Tarn Pool Type Log (Bermuda #1) Attachment 7 \tI c o .- .... ca E a- o LL CD CD -..a o as o CD D..cn C a- ca I- /I ) ·C30· Interval C30 Cairn T3 Interval Bermuda Interval T2 . - - - - - - - T1 C35 Arete Interval T4 ~ - -===:- ~ J -'10'- ---~ 1 ~ f- ~ 1 Iceberg ~ }- Interval f -5000- ~ ~ C37 GAMMARA Y RESlSITIVITY 01 DTI . (0"'11 ::J: ILD~S (011...) .... - - ,.... F 1.0 LNJ)Te.S(OH...)100 0 ~'_DTII_' (MY) R1'.0 SPL.,D1I!.S (0111414)100.0 ·n... .,... ~ 1.0 100.0 ) Bermuda #1 ') ) Tarn Area Injection Order Attachment 8 20 AAC 25.402 (c){8) Casing Description and Proposed Method for Testing Casing The proposed casing programs for a typical Tarn well resembles the casing programs employed in the Kuparuk River Unit (KRU). Although the standard program incorporates maintaining a tubing annulus with isolation and pressure integrity within 200 feet of the initial producing interval, exceptions to this design criterion will be required to optimize recovery from potentially productive secondary targets. Standard Casing Program As in KRU wells, conductor casing will be set below 75 feet to provide anchorage and support for the rig diverter assembly. The surface casing size may be 9-5/8 or 7-5/8 inch, depending on casing setting depth and production tubing size. Surface casing will be set below the base of the West Sak interval, effectively casing off the permafrost, Ugnu, and West Sak formations. When possible, surface casing may be set as deep as 200 feet above the Tarn interval. To accomplish this deep setting depth, offset wells must indicate no shallow hazards and the top of the producing formation must be highly predictable. This deep setting of the surface casing will most likely occur later in the development plan. Tarn wells utilize a tapered casing string tied back to surface, that serves as the combination production casing / tubing string installation. The casing adjacent from the producing interval is the same size as the tubing is at the surface (monobore). The casing across the production interval is then tied back to surface with a string of 3Y2 or 4Y2 inch tubing inserted into a seal bore or polished bore receptacle (positioned above the top pay zone perforation.) This provides a tubing annulus with isolation and pressure integrity (see diagrams shown in Attachment 8A). There are three casing programs proposed for the Tarn development: Case 1) 3Y2 and 4Y2 inch Tubin91ess Monobore completions. This casing program employs a single string of 7-5/8 inch (L-80, 29.7 pound) casing set to within 200 feet of the Tarn formation top. A 3~ inch (L-80, 9.3 pound) or 4Y2 inch (L-80, 12.6 pound) liner would then be set across the Tarn formation and tied back to surface with either 3Y2 inch (L-80, 9.3 pound) or 4Y2 inch (L-80, 12.6 pound) production tubing. Case 2) 3Y2 inch Slimhole Monobore completions. If the 7-5/8 inch (L-80, 29.7 pound) casing string cannot be set deep enough, a production string of 5Y2 inch (L-80, 15.5 pound) casing crossed over to 3Y2 inch (L-80, 9.3 pound) casing will be set to isolate the Tarn interval. These monobore wells will be completed with 3Y2 inch (L-80, 9.3 pound) production tubing. ) ,) Case 3) 4Y2 inch Monobore completions. This casing program employs 9-5/8 inch (L-80, 40 pound) surface casing with 7 inch (L-80, 26 pound) production casing crossed over to 4% inch (L-80, 12.6 pound) production casing. All three well types may be completed for either production or injection service. The service of the well will be determined after logging operations. Drilling and completion plans for future Tarn wells may vary with time as experience and knowledge are gained. The proposed method casing testing method for Tarn injectors is to follow the requirements of 20 AAC 25.412 (c). Sufficient notice of pressure tests will be given so that a Commission representative may witness the test. Secondary Targets The Bermuda Interval will be the primary target of initial development efforts. Current plans are to focus initial development efforts on that portion of the interval most likely have good reservoir characteristics. As previously shown on Attachment 7, potentially productive secondary targets in the Iceberg Interval, Arete Interval and Cairn Interval may be encountered during these development efforts. Secondary targets in the Arete Interval and Cairn Interval are expected to generally be within 400 feet TVD of the Bermuda Interval, however, secondary targets in the Iceberg Interval may be higher. These thin, potentially productive zones contain insufficient reserves to merit separate wells or extensive completion design modifications. Although fracture stimulations are planned for Bermuda Interval producers, fracture modeling indicates these stimulations will only grow approximately 200 feet upwards. Potentially productive secondary pay zones can therefore only be developed if they can be inexpensively commingled with Bermuda production. Given the initial uncertainty of producer/injector interactions, most producers will be candidates for conversion to injection service. In order to maintain conversion flexibility, there are no casing design differences between production and injection wells. (Casing connections will be designed for gas or liquid service.) The flexibility to convert wells to injection service on an as needed basis is an integral part of the Tarn development strategy. This complicates secondary target development as these targets can only be pursued if they are not isolated by more than one casing string. Pursing secondary targets may result in exceeding the AOGCC guideline that injectors provide annular isolation within 200 feet measured depth of the highest perforated interval. Plans are to provide annular isolation within 200 feet measured depth of the perforated zone, unless secondary targets are encountered with a pay thickness approaching or exceeding 10 feet TVD. Based on current drilling and facility hook-up plans, the productive nature of these secondary targets can not be fully ascertained during initial drilling operations. If future evaluations indicate that developing secondary targets can not be justified, there is the potential of having either current or future injectors with annular isolation located more than 200 feet measured depth above the ) ) perforated zone. Tarn Oil Pool Rules are written to help ensure that well service flexibility is not sacrificed by attempting to pursue thin secondary targets. Attachment SA - Possible Tarn Completion Designs Completion 1 Completion 2 ¡-; I cross over I r 9-5/8/7-5/8 ~I "'E .... ~ 2.875':CAMCO~~ DS mpple for ..... Ó:':·: ::::::: West Sak ::::::: at 1 800' TVD II!.I/I ' 7 -S/~:~~;~~C;!ing ::::::: 31h" or 4th" tubing ~ I ~ Baker CMU Sliding ~ ~. I ::::::: ~ Sleevew/2.813" DS- ~ r :::r Cameo profile ¡ ~ .::.::: Cameo 3W' x 1" ___ ~ ~ . I"~ .,:'. C~~~P~'1~5" :.:Jo ~ I .... ~ : ./ J?-í ~~~} -:-:-:. -:.:-:. 5th" Casing :::: ::: 7" Casing }~:~ ~~ Baker Liner Hgr Seal Receptacle ::::H;' · 1_. Seal Rcceprncle ::::::: ' ..::::::: w/Liner Top Pkr (CSR) :::: ::.: (CSR) 7 -5/8" Surface Casing :::::'.':::-' ..':':",-:,,: ::.::.::.~:::. ~ ~ Crossed over to ::::::: .:::::: Crossed over to at 5,000' TVD .:.:.:::.:::.':' ~:':"""::" 3th" tubing ::::::: ::::::: 4th" casing -:-:-:. ;.;..:-: at 5,000' TVD ::::::: ....... at 5,000' TVD 6-1<" Hole I 13th'. or 4'h' Prod. Csg ----.1M' Production Casing at 5,200' TVD at 5,200' TVD 3-1/2" Slimhole Tubingless 3-112" Slimhole Monobore Monobore Completion rntnnløtinn FMC Kuparuk Gen V 7-5/8 x 31h 16" Conductor Casing at 135' RKB L, .... "'0 . . Base of permafrost and stage collar at 1,250' MD CAMCO 2.75" DS nipple ~ 04/27/98 FMC Prudhoe Gen V 9-5/8 x 51h x 31h I 9-7/8" Hole Base of 6-%" Hole I ! k I ~ II' "'E . ( 31h" tubing ~ Completion 3 I-i~ ~ "'E ---th ::::::: 3.875" C 0 ::::::: DB nipÞ.........or 11'lfOM'b,e K Valv . FMC Prudhoe Gen V L., 9-5/8x7x41h r ~ Base of permafrost at 1,250' MD .... a 121/4" Hole Base of West Sak at 1,800' TVD 9-5/8" Surf. Csg. at 2,500' TVD 81h" Hole I I 31h" or 4th" tubing ~ Baker CMU Sliding Sleeve I w/3.812" Car ,:~ profge" / l/~ - ~¿ Cameo 4W' x 1" }~:~ side pocket GLM ...... . .:.:.:.:_-:.:.:. .-:.:.:-:-:.:. 311." or 411." Csg ............. ........... 72 72 :::::::::.' "::::::: at 5,200' TVD 4-112" Monobore Completion ) ) Tarn Area Injection Order Attachment 9 20 AAC 25.402 (c){9) Injection Fluid Analysis The vast majority of the MI initially employed at Tarn will originate from Kuparuk River Unit's CPF-2. After the second phase of development drilling, injection rates are expected to be in the 30 - 50 MMSCFPD range. Lean gas employed to displace the MI will likely originate from either Kuparuk River Unit's CPF-2 or Tarn produced gas. Current plans are to obtain the gas from Kuparuk River Unit's CPF-2. The average MI and lean gas composition produced at the Kuparuk CPF-2 facility during late 1997 is presented below. There is no evidence from laboratory core flood experiments or compositional studies that indicate the hydrocarbons proffered for injection would pose compatibility problems for either the Tarn Formation or its confining zones. Miscible Injectant & Lean Gas Composition Supplied by the Kuparuk River Unit's CPF-2 Component MI Lean Gas (Mole 0/0) (Mole 0/0) CO2 1.0 0.9 N2 0.2 0.2 C1 66.0 80.9 C2 7.9 10.0 C3 5.4 5.0 iC4 2.4 0.8 nC4 7.0 1.6 iCs 2.3 0.3 nCs 2.8 0.2 Cs 2.2 0.1 C7 1.9 0.0 Cs+ 0.9 0.0 ) ) Tarn Area Injection Order Attachment 10 20 AAC 25.402 (c){10) Estimated Pressures The maximum MI injection pressures available at the plant will be 4,400 psL Due to pressure losses in the distribution system, actual maximum wellhead pressures will vary. Injection wells may also be choked to avoid exceeding injection targets. Wellhead injection pressures are expected to range from 2,700 psi to 3,700 psi. ) ') Tarn Area Injection Order Attachment 11 20 AAC 25.402 (c)(11) Fracture Information Injection into the Tarn Formation will not breach the reservoir's confining zones. Neither injection nor formation fluids will be able to enter any freshwater strata. Although bottom-hole pressures may exceed the formation parting pressure during enhanced recovery operations (Le., MI and lean gas injection), the Tarn producing sands are separated by over 1500 feet of confining shales and mudstones which act as an impermeable barrier (see Attachment 11 A). These confining layers provide a substantially greater barrier than necessary to contain fractures within the Tarn interval. The high leakoff coefficients and low viscosities associated with MI and lean gas make it very difficult for these fluids to propagate fractures. Fracture modeling using Stimplan (Le., Nolte/Smith's quasi 3-D model) confirms this as predicted fracture heights are entirely contained within the perforated interval for an injection rate of 10 MMSCFPD at a surface injection pressure of 3500 psL This is a conservative approach as the model assumes an incompressible fluid. Compressible fluids, such as MI and lean gas, would actually provide less fracture growth. Hydraulically propped fracture stimulations are planned for Tarn producers. The 1500 feet of confining shales and mudstones also provide a substantially greater barrier than necessary to contain these fracture stimulations. Fracture modeling using Stimplan suggests that typical fracture stimulations will grow upward approximately 200 feet. Model runs with worst case assumptions (which cause the most upward growth) suggest the stimulations will not exceed 500 feet of upward growth. For example, a fracture stimulation with 200,000 pounds of proppant with only 70 feet of gross interval is forecasted to result in a maximum upward fracture height of 337 feet (see Attachment 11 B). Current hydraulic fracture models assume single, planar, vertical fractures that result from relatively short duration injection. These models were developed for "hard rock" and assume brittle failure. Since dentritic fractures, disaggregation (Le., destruction of the rock matrix) and particle invasion into the rock matrix are not captured by these models, they may not provide an accurate representation of long-term disposal injection into shallow, "soft rock" intervals. Employing these models to represent disposal injection, however, is a conservative approach as not capturing the above-mentioned complexities causes height growth calculations to be too high. As previously mentioned, no disposal injection is initially planned in the Tarn Participating Area. However, the Ivishak sandstone is being permitted for Class II ) ) disposal to address potential future needs. Approximately 2000 feet TVD of confining rock separate this zone from Tarn Reservoir strata. In addition, there are no potential fresh water strata within several thousand feet TVD of the zone (see Attachment 11 C). If the Ivishak is used for disposal injection in the future, modeling will be conducted at that time using the best available tools to help ensure that the planned disposal volumes pose no risk to either potential freshwater strata or hydrocarbon recoveries. Both the Ivishak and Tarn sandstones are considered "hard rock" and should therefore be less susceptible to the modeling complexities associated with long-term disposal injection into shallow, "soft rock" intervals. 4/981 0 HastinÇJs I 98042303AOO Bermuda #1 Well Log ARca Alaska, Inc. <> Attachment 11A Tarn Pool Type Log (Bermuda #1) o o c. c ... ca t- - - - ca == Q) - ca .c en -- \ ~ Q) Q) ... o Q) u c ') \l C30- -'~.'~~----c3-S--::::: 'II C37- C80- 'TABASCQ' :~ - - ~ -4500- ~ T -5000: -f- ~ ,r ~ ~ L -2500- ~ ~ -t ....... -+ -- -4000- ~~ --t -3500- -3000- > ~ RESISITIVITY ::I: ILDJ)~S (OHþM) 150.0 b: 1.0 ILM~S (OHþM) 100.0 Y.I 1.0 SFlJ)1E_S (a-I....)100.0 -50.0 C 1.0 100.0 -150.0 SP_O'IE_S (MV 50.0 GR"p'IE_S (GAP!) GAMMARAY ') Bermuda #1 Tarn Area Injection Order 0 20 50 00 200 Time (min) Attachment 11 B 500 1000 2000 5000 Page (ñ .e:: Q) :; en en Q) à: ã.í z 5.0 200 o 50 00 pay; 1 50 psi Contra.st _ _ _ _ · . . . . . · . . . . . · . . . . . · . . . . . · . . . . . · . . . . . · . . . . . . .. . . . . . . ·1··········~·······t·······i··········~ .···t·······i··········~·······t·······1··········~····· · . . .. ..... · . . .. ..... · . . .. . . . . · . . .. . . . . · . . .. . . . . · . . .. ..... · . . . . . . . . . . ............~..........................~..................... .~..........................~.....I · . . . . . . . . . . · . . . . .. ... · . . . . .. ... · . . . . .. ... · . . . . .. ... · . . . . .. ... · . . . . . . . . . . ........................................~.............................................................. · . . . . . . . . . . · . . . . . . . . . . · . . . . . . . . . . · . . . . . . . . . . · . . . . . . . . . . · . . . . . . . . . . · . . . . . . . . . . · . . . . . . . . . . · . . . . . . . . . . · . . . . . . . . . . 20'.......~..........~.......:.......~..........~.......:.......~..........~.......:.......~..........~.....4 · . . . . . . . . . . · . . . . . . . . . . · . . . . . . . . . . · . . . . . . . . . . · . . . . . . . . . . · . . . . . . . . . . ·1·0········~·······t·······i··········~·······t·······1··········~·······t·······~··········~·····1 · . . . . . . . . . . · . . . . . . . . . . · . . . . . . . . . . · . . . . . . . . . . · . . . . . . . . . . · . . . . . . . . . . · . . . . . . . . . . ............~..........................~..........................~..........................~....., · . . . . . . . . . . · . . . . . . . . . . · . . . . . . . . . . · . . . . . . . . . . · . . . . . . . . . . · . . . . . . . . . . · . . . . . . . . . . · . . . . . . . . . . · . . . . . . . . . . · . . . . . . . . . . 2.0 5.0 · $trp",~~ (r~i) . · . . . . . · . . . . . · . . . . . · . . . . . · . . . . . · . . . . . · . . . . . · . . . . . · . . . . . · . . . . . · . . . . . · . . . . . · . . . . . ..... ...~.......~..... · .... · .... · .... · .... · .... · .... · .... · .... · .... · .... · .... · .... · . . . . . .....~. .~.......~..... · . . . . . · . . . . . · . . . . . · . . . . . · . . . . . · . . . . . · . . . . . · . . . . . · . . . . . .. ... .. ... · . . . . . · . . . . . · . . . . Þ ....... ................ . .. .. · . . . . . · . . . . . · . . . . . · . . . . . · . . . . . · . . . . . · . . . . . · . . . . . · . . . . . · . . . . . · . . . . . · . . . . . .........~.. ....~..... · . . . . . · . . . . . · .. .. · .. . 0 · .. .. · .. .. · .. .. · .. .. · .. .. · .. .. · .. .. · .. .. · . . . . . .I.......~..... .~..... 3000 3400 3800 Max Width 0.83 in ...... . ...... . ...... . ...... . ...... . ...... . ...... . ...... . ...... . ...... . ...... . ...... . ~'. ) Tarn Area Injection Order ) Attachment 11 B 20 AAC 25.402 (c){11) f\ST' M PLAN\STI M PLAN. pp ~ Frac Sununary 71 'l'arn 70' gross pay¡ 150 psi Contrast Filename: Nsk-koc-svr03. ..tarncase1.STP¡ 3-Apr-1998 Design Data ------------------------------------------------------------------- FLUID LOSS LAYERS: Top (ft) 3640.0 5150.0 6200.0 Bottom (ft) 3650.0 5200.0 6220.0 Thick (ft) 10.0 50.0 20.0 Loss Coef. Spurt (ft/sqrt (min)) (Gal/100 ft^2) 0.00600 0.00 0.00150 0.00 0.00600 0.00 ------------------------------------------------------------------- FORMATION: Modulus (e6-psi) . ........ ........ ..... Perforated Height (ft) ................ Permeability (md) .................... TEMPERATURE: Bottom Hole (deg_F) ...... .... ...... ... PRESSURE: Reservoir Pressure (psi) . .... ...... ... Closure Pressure (psi) ................ DEPTH: Well Depth (ft) ....................... 1.72 70.0 20.000 140 3000.0 3261.0 5150.0 ------------------------------------------------------------------- FORMATION LAYER DATA - Multi-Layer Height Growth -----Depth{ft)------ -Stress (psi)-- Gradient Modulus Toughness Top Botm Thick Top Botm (psi/ft) (e6-psi) (psiûin) 3000.0 3640.0 640.0 2100.0 2484.0 0.600 1.00 100.0 3640.0 3650.0 10.0 2334.0 2340.0 0.600 0.25 100.0 3650.0 5150.0 1500.0 2490.0 3390.0 0.600 1.00 100.0 5150.0 5220.0 70.0 3240.0 3282.0 0.600 1.72 100.0 5220.0 6200.0 980.0 3432.0 4118.0 0.700 1.00 100.0 6200.0 6220.0 20.0 3968.0 3982.0 0.700 1.00 100.0 6220.0 4132.0 0.700 1.40 100.0 Fluid Pressure Gradient (psi/ft) .................... 0.437 Perforations - Top (ft). .......................... 5150 1 - Bo t ( f t ) ........................... 522 0 I I Initial Fracture Top (ft) . .......................... 5150 I 1 Fracture Bottom (ft) . ....................... 5220 I 1-------------------------------------------------------------------1 I 3-D SIMULATOR Step Size (ft) ..................... 10.8 I PROGRAM CONTROL Time Step (min) .................... 7.0 1 I Flow Model ....................... 2 -D 1 I I Calculated Results 1 I from 3-D Simulator I I STIMPLAN (TM) , NSI , Tulsa,OK I I Licensed To: ARCO Exploration and production Technology I 1----------------------------------------------------------1 I 1/2 LENGTH: 'Hydraulic' length (ft) ........... 323.8 I I Propped length (ft) ................ 323.7 I I PRESSURE: Max Net Pressure (psi) ............. 293.9 I I Surface Pres-End of Pad (psi) ..... 3953.2 I I Surface Pres-Start of Flush (psi) . 5081.7 I I Surface Pres-End of Job (psi) . .... 3913.4 I I Maximum Hydraulic Horsepower.. ..... 2541 I I TIME: Max Exposure to Form. Temp. (min) 47.0 I I Time to Close (min) ......... ..... 553.5 I I RATE: Fluid Loss Rate during pad (_BPM) .. 3.41 I I EFFICIENCY: at end of pumping schedule.... ..... 0.85 I I PROPPANT: Average In Situ Cone. (#/sq ft) .... 1.0 I I Average Conductivity (md-ft) . ...... 11586 I I HEIGHT: Max Fracture Height (ft) ........... 584.6 I I WIDTH: Avg width at end of pumping (in) ... 0.29 I I I Tarn Area Injection Order Attachment 118 Page 2 ) C:\STIMPLAN\STIMPLAN.PP~ I (TM). NSI Technologies, Tulsa, OK I I Licensed To: ARCO Exploration and Production Technology I 1------------------------------------------------------------1 IWELL ID: 1 ¡Tarn 70' gross pay; 150 psi Contrast I ¡DEPTH: Well Depth (ft) ...,..................... 5150 1 PRESSURE: Reservoir Pressure (psi) ...... ........ 3000 1 Closure Pressure (psi) ................ 3261 I 1 TEMPERATURE: Bottom Hole Temperature (deg_F) . ...... 140 I I I ** Pumping Schedule ** 1 Sl Vol Fl Vol Conc (_PPG_) Rate Fluid Prop Cum Prop Pump Time 1 (_BBL) (_BBL) Start End (_BPM) Type Type (MLbs) (min) I -------------------------------------------------------------------------1 150.0 150.0 0.0 0.0 20.00 1 1 0.0 7.5 I 100.0 91.9 2.0 2.0 20.00 1 1 7.7 5.0 I 400.0 340.6 2.0 6.0 20.00 1 3 64.2 20.0 I 400.0 296.0 6.0 10.0 20.00 1 3 163.2 20.0 I 100.0 64.5 10.0 15.0 20.00 1 3 196.9 5.0 I -------------------------------------------------------------------------1 Total Slurry... 1150.0 Total Fluid... 943.1 I Total Proppant ... 196.9 Avg. Conc . ..... 5.0 I Total Pump Time 57.5 min Pad % ....... ... 13.0 I Pump Schedule Assumes Prop Conc Increases Linearly With SLURRY Volume 1 Proppant ID No. 1 20- 40 Carbo-Lite 1 1------------------------------------------------------------1 I Specific Gravity............................ 2.72 1 I 'Damage Factor' ............................. 0.70 1 I Proppant Stress (Mpsi) 0 2 4 8 16 1 I KfW @ 2 #/sq ft (md-ft) 17132 8566 7159 2938 735 1 1 I I--~:~~~-:~-~~~--=--------------------~~~-~~-~~~:-~~:~==-------------------1 1 Specific Gravity............................ 1.01 I 1 @Welbore @FormTmp 1.0 hr 2.0 hr 4.0 hr 8.0 hr 1 vis(cp @ 170 l/sec) 723 723 397 235 59 10 I I non-Newtonian n' 0.45 0.45 0.48 0.80 1.00 1.00 I I K(lb/sec/ft^2)x1000 249.73 249.73 117.54 13.45 1.21 0.20 I I I Q (bpm) P/dL (psi/100 ft) 10.0 21.0 15.0 34.0 20.0 49.0 25.0 63.0 30.0 80.0 Measured Depth (ft) 5488.0 Tarn Area Injection Order Attachment 11 B Page 3 ".. C:\STIMPLAN\STIMPLAN.Pr'\N ,) ) I Proppant ID No. 3 12- 18 LDC I 1------------------------------------------------------------1 I Specific Gravity............................ 2.72 I I ' Damage Factor / ............................. 1.00 I I Proppant Stress (Mpsi) 0 2 4 8 16 I I KfW @ 2 #/sq ft (rod-ft) 63533~31766 21410 5635 1409 I I I Tarn Area Injection Order Attachment 11 B Page 4 ) C:\STIMPLAN\STIMPLAN.P.....~ I Time History * NSI STIMPLAN 3-D Fracture Simulation I I Tarn 70' gross pay; 150 psi Contrast 1----------------------------------------------------------------------- I Time Pen Pres Rate Prop Sl Vol Eff- Loss Hght W-Avg I (min) (ft) (psi) (_BPM) (_PPG_) (_BBL) ciency (_BPM) (ft) (in) I-------------------------------------~--------------------------------- I 0.3 22.5 229 20.00 0.0 5.0 0.74 5.7 72 0.08 I 0.6 33.3 260 20.00 0.0 11.2 0.77 3.8 73 0.12 I 0.8 44.0 294 20.00 0.0 16.7 0.76 4.3 92 0.12 I 1.3 54.8 282 20.00 0.0 25.5 0.77 4.2 115 0.12 I 2.0 65.7 270 20.00 0.0 39.8 0.78 3.9 143 0.13 I 3.0 76.4 262 20.00 0.0 59.0 0.79 3.6 168 0.15 I 3.9 87.3 268 20.00 0.0 78.6 0.80 3.6 192 0.16 I 5.3 98.1 254 20.00 0.0 106.7 0.80 3.4 216 0.17 I 7.5 111.6 255 20.00 0.0 150.2 0.81 3.4 245 0.19 I 9.5 122.4 243 20.00 2.0 190.0 0.82 3.0 269 0.20 I 12.1 133.2 233 20.00 2.0 243.1 0.83 3.0 293 0.21 I 14.9 144.0 230 20.00 2.2 297.6 0.83 2.9 317 0.22 18.0 154.8 227 20.00 2.8 360.5 0.84 2.9 341 0.23 20.8 165.6 229 20.00 3.4 416.2 0.84 2.9 362 0.24 23.6 176.4 228 20.00 3.9 472.6 0.84 3.0 384 0.25 26.8 187.2 226 20.00 4.5 535.0 0.84 3.0 409 0.25 30.3 198.0 222 20.00 5.2 606.0 0.84 2.9 428 0.26 33.7 208.8 224 20.00 5.9 673.6 0.84 3.0 447 0.27 37.4 219.6 222 20.00 6.6 747.4 0.85 3.0 466 0.27 41.0 230.4 222 20.00 7.3 820.5 0.85 3.0 487 0.28 44.9 241.2 221 20.00 8.1 897.6 0.85 3.0 509 0.28 49.0 252.0 221 20.00 8.9 979.8 0.85 3.0 534 0.28 53.4 262.8 219 20.00 9.8 1068.8 0.85 3.0 561 0.29 57.5 272.2 216 20.00 12.9 1150.2 0.85 2.9 585 0.29 64.6 283.0 192 0.00 0.0 1150.2 0.83 2.9 585 0.28 71.0 293.8 185 0.00 0.0 1150.2 0.81 2.8 585 0.27 76.5 299.2 181 0.00 0.0 1150.2 0.80 2.6 585 0.26 82.0 304.6 177 0.00 0.0 1150.2 0.79 2.5 585 0.25 87.1 310.0 174 0.00 0.0 1150.2 0.78 2.5 585 0.24 93.2 315.4 171 0.00 0.0 1150.2 0.76 2.4 585 0.23 97.2 318.1 170 0.00 0.0 1150.2 0.76 2.3 585 0.22 101.2 320.8 168 0.00 0.0 1150.2 0.75 2.3 585 0.21 108.2 323.5 165 0.00 0.0 1150.2 0.74 2.1 585 0.20 113.4 323.8 163 0.00 0.0 1150.2 0.73 2.0 585 0.20 151.5 323.8 150 0.00 0.0 1150.2 0.67 1.7 585 0.18 Screen Out in Stage 2 at Time = 151.5 min at 296.5 (ft) 197.9 323.8 137 0.00 0.0 1150.2 0.61 1.4 585 0.18 252.1 323.8 124 0.00 0.0 1150.2 0.56 1.2 585 0.17 313.5 323.8 111 0.00 0.0 1150.2 0.50 1.1 585 0.16 346.9 323.8 104 0.00 0.0 1150.2 0.47 1.0 585 0.15 381.7 323.8 98 0.00 0.0 1150.2 0.45 0.9 585 0.14 418.0 323.8 91 0.00 0.0 1150.2 0.42 0.9 585 0.14 455.6 323.8 85 0.00 0.0 1150.2 0.39 0.8 585 0.13 493.9 323.8 78 0.00 0.0 1150.2 0.36 0.8 585 0.12 533.3 323.8 72 0.00 0.0 1150.2 0.34 0.8 585 0.12 572.0 323.8 65 0.00 0.0 1150.2 0.31 0.7 585 0.11 611.0 323.8 59 0.00 0.0 1150.2 0.29 0.7 585 0.11 Tarn Area Injection Order Attachment 11 B Page 5 C:\STIM PLAN\STI MPLAN .pn1 ) GEOMETRY SUMMARY * At End of Pumping Schedule I Tarn 70' gross pay; 150 psi Contrast I -------------------------------------------------------------------------1 Dstnce Press W-Avg Q Sh-Rate ------Hght (ft)------- Bank Prop I (ft) (psi) (in) (_BPM) (l/sec) Total Up Dn Prop Fraction (PSF) I ---------------------------------------~~--------------------------------1 6 214 0.50 10.0 2 585 337 178 581 0.00 2.51 I 17 211 0.48 9.1 3 559 319 170 556 0.00 2.02 I 28 208 0.46 8.4 3 534 303 162 531 0.00 1.83 I 39 205 0.44 7.7 3 510 286 154 507 0.00 1.65 49 202 0.42 7.1 3 485 269 146 482 0.00 1.48 60 199 0.39 6.6 3 461 252 139 457 0.00 1.31 71 196 0.38 6.1 3 436 235 131 433 0.00 1.19 82 193 0.37 5.7 3 427 229 128 424 0.00 1.07 93 190 0.36 5.4 4 418 224 125 415 0.00 0.98 105 186 0.35 5.1 4 408 217 121 405 0.00 0.87 117 183 0.33 4.8 4 399 211 118 395 0.00 0.77 128 180 0.32 4.5 4 390 206 114 386 0.00 0.66 139 177 0.31 4.3 4 379 199 111 375 0.00 0.56 149 174 0.29 4.0 5 360 185 105 356 0.00 0.50 160 171 0.28 3.7 5 341 172 100 337 0.00 0.41 171 167 0.26 3.4 6 322 158 94 317 0.00 0.37 182 164 0.24 3.1 6 303 145 88 298 0.00 0.34 193 160 0.22 2.8 7 284 131 83 278 0.00 0.33 203 155 0.20 2.4 8 263 117 76 257 0.00 0.28 214 149 0.18 2.0 10 231 97 63 220 0.00 0.00 225 142 0.15 1.6 13 198 78 51 183 0.00 0.00 236 132 0.12 --, 1.2 18 166 58 38 146 0.00 0.00 247 116 0.08 0.8 33 133 38 25 109 0.00 0.00 257 91 0.04 0.5 94 101 18 12 72 0.00 0.00 267 36 0.03 0.3 166 70 0 0 67 0.00 0.00 Tarn Area Injection Order Attachment 11 B Page 6 .) C:\STIMPLAN\STIMPLAN.P~~ I FLUID SUMMARY * At End of Pumping Schedule I I Tarn 70' gross pay; 150 psi Contrast I 1---------------------------------------------------------------------------1 I Stage Fluid Prop pos Concentration FI vol Ex Tim Temp Visc Fall No Gone ID ID (ft) In Now Desgn (_BBL) (min) (deg_F) (cp) Frac ----------------------------------------~~---------------------------------1 1 1 1 1 272 0.0 0.0 0.0 5.0 8.3 140 604 0.001 1 1 1 1 272 0.0 0.0 0.0 11.2 10.1 140 598 0.001 1 1 1 1 272 0.0 0.0 0.0 16.7 15.4 140 562 0.001 1 1 1 1 272 0.0 0.0 0.0 25.5 20.6 140 538 0.001 1 1 1 1 272 0.0 0.0 0.0 39.8 32.1 140 474 0.00 1 1 1 1 272 0.0 0.0 0.0 59.0 42.3 140 430 0.00 1 1 1 1 272 0.0 0.0 0.0 78.6 44.8 140 258 0.00 1 0 1 1 254 0.0 0.0 2.6 103.8 47.0 140 562 0.00 1 0 1 1 223 0.0 0.0 8.0 135.7 42.0 140 1152 0.00 2 0 1 1 199 2.0 2.7 10.0 163.3 42.0 140 1401 0.00 2 0 1 1 180 2.0 2.5 11.0 199.0 36.1 140 1660 0.00 2 0 1 1 169 2.0 2.4 11.6 203.8 36.1 140 1733 0.00 3 0 1 3 161 2.2 1.5 29.5 224.5 30.3 140 1937 0.01 3 0 1 3 145 2.8 2.3 20.7 257.1 23.5 140 2233 0.01 3 0 1 3 129 3.4 3.3 15.9 290.0 20.0 140 2445 0.01 3 0 1 3 116 3.9 4.3 13.1 325.7 16.3 140 2621 0.01 3 0 1 3 103 4.5 5.7 11.2 367.4 8.5 140 2898 0.01 3 0 1 3 88 5.2 7.5 9.7 417.1 4.3 140 3102 0.00 3 0 1 3 77 5.8 9.3 8.7 449.0 0.0 140 3287 0.00 4 0 1 3 70 6.1 5.0 19.8 461.7 0.0 140 3303 0.00 4 0 1 3 61 6.6 5.8 18.0 502.6 0.0 113 3412 0.00 4 0 1 3 48 7.3 7.0 15.9 545.7 0.0 107 3435 0.00 4 0 1 3 37 8.1 8.4 14.2 593.1 0.0 105 3435 0.00 4 0 1 3 26 8.9 10.1 12.9 645.5 0.0 104 3435 0.00 4 0 1 3 16 9.6 12.0 11.9 691.4 0.0 102 3435 0.00 5 0 1 3 10 10.5 9.0 18.0 701.9 0.0 101 3435 0.00 5 0 1 3 5 12.9 13.6 14.3 751.7 0.0 101 3435 0.00 Tarn Area Injection Order Attachment 11 B Page 7 C., :\STIMPLAN\STIMPLAN.PP~. ) ) PROPPANT SUMMARY * At End of Pumping Schedule Tarn 70' gross pay; 150 psi Contrast -------------------------------------------------------- Lb/Sq-Ft Lost to Embedment. ...... ........ .... 0.100 -------------------------------------------------------- Distance KfW Prop Concentration(Total Ib/sq foot) (ft) (rod-ft) Prop ID--> 1 3 -------------------------------------------------------- 5.8 33377 0.00 2.36 17.0 29450 0.00 2.09 27.8 25613 0.00 1.83 38.6 22950 0.00 1.65 49.4 20385 0.00 1.48 60.2 18056 0.00 1.32 71.0 16089 0.00 1.19 81.8 14440 0.00 1.08 92.6 12935 0.00 0.98 104.8 11377 0.00 0.87 117.0 9811 0.00 0.76 127.8 8303 0.00 0.66 138.6 6957 0.00 0.57 149.4 5790 0.00 0.49 160.2 4114 0.07 0.35 171.0 2051 0.23 0.14 181.8 887 0.32 0.02 192.6 640 0.32 0.00 203.4 432 0.22 0.00 214.2 133 0.07 0.00 225.0 0 0.00 0.00 235.8 0 0.00 0.00 246.6 0 0.00 0.00 257.4 0 0.00 0.00 267.5 0 0.00 0.00 1-------------------------------------------------------- I Average Conductivity (rod-ft) ....... .......... 12922 I Tarn Area Injection Order Attachment 11 B Page 8 C:\STIM PLAN\STI M PLAN. P8 ~J ) I PROPPANT SUMMARY * At Fracture Closure I Tarn 70' gross pay; 150 psi Contrast 1-------------------------------------------------------- I Lb/Sq-Ft Lost to Embedment ... ....... ... ...... 0.100 1-------------------------------------------------------- I Distance KfW Prop Concentration(Total Ib/sq foot) I (ft) (rod-ft) Prop ID--> 1 3 -------------------------------------------------------- 5.8 18460 0.00 1.34 17.0 17015 0.00 1.24 27.8 15220 0.00 1.12 38.6 14170 0.00 1.05 49.4 13552 0.00 1.01 60.2 13013 0.00 0.97 71.0 12644 0.00 0.95 81.8 12489 0.00 0.94 92.6 12482 0.00 0.94 104.8 12494 0.00 0.94 117.0 12543 0.00 0.94 127.8 12437 0.00 0.93 138.6 11948 0.00 0.90 149.4 11402 0.00 0.86 160.2 11036 0.00 0.84 171.0 11343 0.00 0.86 181.8 11916 0.00 0.90 192.6 11909 0.00 0.90 203.4 12267 0.00 0.92 214.2 12590 0.00 0.94 225.0 12950 0.00 0.97 235.8 14525 0.00 1.07 246.6 15552 0.01 1.14 257.4 14368 0.18 1.02 267.5 12465 0.48 0.81 277.6 12465 0.48 0.81 288.4 12465 0.48 0.81 296.5 12465 0.48 0.81 301.9 12465 0.48 0.81 307.3 12465 0.48 0.81 312.7 12465 0.48 0.81 316.7 12465 0.48 0.81 319.4 12465 0.48 0.81 322.1 12465 0.48 0.81 323.7 12465 0.48 0.81 -------------------------------------------------------- Average Conductivity (rod-ft) ................. 11586 Tarn Area Injection Order Attachment 118 Page 9 ,_,,-r ,~~ ~l=-- .. ~ ! ..~, ~ ..~ .... 4.. ~~ -~~: -~:~ ,;;;, ~~;;. ___.___,___....dt __U'h""_'__.'_""._"'~_."_h". -"., _",_"_,,.,n_"_ -6 500- .:s ==*-'1:, . "..,~,. <~~ -~ '''- "'~ ~ .., '\~ t ,::t ~- '~_:' '1 . ...,,, ~ ~ ....4:" -1 ~::;'::=JC='-' -75 00- -··-'~r- - :~$~ ~~=~ . .~;,~~~-= ~~-='.. .~~:~~ ---."'=-.:.::-...:-----_.. -e 000- -Jr.--~- -""!Iæ. :;~d· ~::~~;-~Î~,,_,,=_~~ - -.~~" : ...:f~~ ~~ ~~~..:= .~j~~ -""'- GAMMARAY GR ~~_~_~!_.. 0" E)- '1 5 0 0 G H ... ":~~~~~,, 9 ...' ,'''5- 'õ - 0 3 0 0 0 ~:::..~:: ··...·----:·-~·;:,:¡~f ~;~~,i,,~~ ~:..~ ;:;.,. -~:'.~- ~ -- -..- - ~ .c ê~ ::::;, .c , en æ ~ m en - Q) en s::: 0 ~~ en N ~- ~ ~ s::: -. ~ as 0 J: -- en ..... ~ .S: (.) Q) - -- s::: --- ) ~ES S T \V TY R LD P HMM ) 1 0 1 00 0 R 1M PHv1M) :J: 1 0 , 00 0 I- LL..8 P HMM ) a.. w , 0 , 00 0 C -_...;:,¡ :~ _ :t.~ -6000- - .~~ 1: rf ~ - ~ -70 00- -8500- I~ \1 ~ as .c: CJ) ~ as C) c ~ Q) s::: o N ..... s::: Q) E Q) s::: ;: s::: o o ) Attachment 11 C Log of Tarn Type Well (Sinclair Colville #1) ARca Alaska, Inc. <> Sinclair Colville #1 Well Log 4/98 I 0 HastinQs I 98042305AOO ) ) Tarn Area Injection Order Attachment 12 AAC 25.402 (c)(12) Formation Fluid No oil-water or gas-water contacts within the Tarn formation have been encountered. Average salinity estimates from immobile connate water were estimated from low invasion cores. Connate water was obtained from core plugs using a miscible (CHCls / CHsOH) extraction process. Subsequent water volumes were estimated using Karl Fisher analysis and chlorides were measured using ion chromatography. The resultant estimated connate water NaCI concentration was 30,000 ppm. ) ) Tarn Area Injection Order Attachment 13 20 AAC 25.402 (c)(13) Aquifer Exemption The EP A established an aquifer exemption for the Kuparuk River Unit on May 11, 1984. This exemption includes the proposed injection area requested in this application (see Attachment 13A). Aquifers covered in the exemption include those associated with the West Sak and Ugnu formation. ) ) Tarn Area Injection Order Attachment 13A ....__....,.............,.,....,.,.~ ..."...,...,.,j.."....o:J.-.........._..¡.I'I:_,~,~...\o...........W"}',r;.,........."....__.._.'..........,. ....... ._". ....'",.;,.,...... ,...._ . .....'""..........._..." . .'..~,...,....",~ ; ......,......"'("'1/,'............"...-..,.."1:.. ·''''''11.... ,,'V, -,_ .,.,..._,-..w............_....._........... I~"."""'~" .,., ..... '._.. ,.. ",'" , ¡¡.. ......, . _ -'ION... . , . ....~......"'~.......-....v.......... , , n·' ....."...._:.,'.._'~-,'"............_.......,-:.'...--. \ 1 ',: ,; f, ~:: ¡ f -----:--:---'1' -. T-l .. ," -""~"""'r" ..:... - r ;, "7'-:' ) ( ~ ·f ~ . _..:.e,.,.""'__.¥I:....__ 'V'Itf!".~-~,,~ , , ' , .~",.."..._.~_~.,__..." l.~ ......'...., +~.~_...,.~ ...~.~.._,_~__, t ..""'~ , .. ;, , . J . '-·-----'---t..·......·-·· ....._-.. -,:; -~...- , , . , , . :...................,-,¡.......~... ~ '.'......~IIo.'.''--':....'''''I''~~...I,)I''......_.. Kuparuk River Unit L'-~ ..r. ~.__. "~ I" :: ~ ...." ,~-, , " ,: .. ~,..·..."*'""'.._--~·..,\-·~.w.tL...._~..........._.._...._·..~·1I ~ ~..~~ 'J'~"",,-,,_. .....-n..n ._~~, '~'l.""'~· . . ._^_,~ w'\....."J.~"~.,,_.._ I...,.".__.....~. . - ..~._.~-. __"...,..,".~~_...oI'..,.....,.._....",....__........._..~~~..~,...._."..-..,II., - ....lh.·....'....."'*,:w.-..:"'""'....U'llo..~.~--...1I4 .__..-......:-&....".".....""'",.,.._...,.___.....wo;r.-..,.-.o..;:;o,," .......'.I_'I\..~...._____ .·r".___.._-........._._I ..."II,...........~'4I~_.. ·__·_""'·/f'l. .___-..........._..,......_....._.0 . __~_.L"':II~_.....-"C.. --............1":'- _..r...~....,..o.I'!'''''''''''''''' ...'-..'....... ;UIC Exemption Area MIIee 0 KIIom.t.... 0 I 2...... 5 KIb...r. . ~...II._--..-.v'...._.."""'-_._.... ........._..~.,. '_,' ,_. ... ._......_....... _ ~ __._...........-:.._.._.........:.....,-¡_ ...___....,-..,..-.. Tarn Proposed r/ /J Injection Area ARca Alaska, Inc. <> UIC Exemption Area: Tarn Proposed Injection Area 3/98 D Hastinas I 98031102AOO ) ) Tarn Area Injection Order Attachment 14 20 AAC 25.402 (c)(14) Incremental Hydrocarbon Recovery The Tarn Sand was tested in the ARCO Tarn #2 exploration well. Fluids recovered from the test indicated the interval contains 370 API gravity crude with a solution GOR of approximately 700 SCF/B. There is no evidence that this zone is in contact with either an aquifer or gas cap to provide pressure support. Although there is some evidence that the ARCO Tarn #4 exploration well may have penetrated a gas cap in the Cairn Sand, current mapping suggests that the gas cap, if it exists, would be too small to provide appreciable pressure support. Simulation results indicate that injecting a 200/0 hydrocarbon pore volume slug of MI followed by a lean gas flush would recover 31 % OOIP. This recovery factor is approximately 10% 001 P higher than that obtained from straight lean gas injection and approximately 20% OOIP higher than that obtained from primary depletion. Mr. David Johnston April 27, 1998 ) Re: Tarn Area Injection Order 20 AAC 25.402 Bee: Hans Erickson, Cathy Foerster Lamont Frazer, Steve Kranker, Doug Hastings, Lisa Pekich, George Phillips, Dora Soria, Jack Walker, Mike Zanghi, NSK-14 ATO-1270 ATO-1246 ATO-1252 ATO-1264 ATO-1134 ATO-1550 ATO-1370 ATO-1248 ATO-1276 ARCO Alaska, Inc. Post Office Box 100360 Anchorage, Alaska 99510-0360 Telephone: (907) 276-1215 Ìi. ) '~ ~~ ~~ Doug Hastings Kuparuk Development ATO 1264 Phone 265-6967 Fax 263-4566 April 8, 1998 David Johnsbn State of Alaska Alaska Oil and Gas Conservation Commission 3001 Porcupine Drive Anchorage, Alaska 99501 Mr. Johnson: Arco Alaska, Inc. recently submitted Applications for Area Injection Order and Pool rules for the Tarn Reservoir on behalf of the Kuparuk River Unit. Those documents contain formation log displays of wells which have not been released to the public, and won't be released until Spring, 1999. Arco Alaska, inc; respectfully requests that these log data be treated as confidential information by the the AOGCC until after upcoming State Lease Sale #87, which will occur in late June, 1998. The displays in question are as follows" Pool Rules Application Exhibits 1 ,2 and 4 Area Injection Order Attachments 7 and 11 A SinC[.IY, . ~ {j ¿ I. t I < /~ ./,.. ~::) ~./ ' OUgl~HastingS 9CJ Cc Robert Crandall,A.O.&G.C.C. Ryan Stramp, Arco Alaska, Inc. Dora Soria, Arco Alaska, Inc. ARca Alaska, Inc. is a Subsidiary of AtlanticRlchfleldCompany ) ) \j~D-~~ ARca Alaska, Inc. ~~ ~~ Kuparuk Development Post Office Box 100360 700 G Street Anchorage, Alaska 99510 Telephone 907 265-6806 Ryan Stramp, Tarn Coordinator March 31, 1998 Mr. David Johnston Alaska Oil and Gas Conservation Commission 3001 Porcupine Road Anchorage, AK 99501 Re: Tarn Area Injection Order 20 AAC 25.402 ~~fCEJ\/:cr) ~ L =to' r '} '¡QCH~! .I" J 1,.1 ::;'70 Dear Sir: J\Iaska OìJ ~{ Gas Cons. Commission ARCO Alaska, Inc. (AAI) is pursing development of the Tarn Reservê~phWtlQ9ugh an' expansion of the Kuparuk River Unit. (Parallel efforts to expand the Kuparuk River Unit and formulate pool rules to facilitate Tarn Reservoir development are in progress.) AAI briefed the Commission on Tarn during a February 3, 1998 meeting. AAI in its capacity as operator submits this letter as an application for Alaska Oil and Gas Conservatio~ Commission approval to conduct an enhanced recovery operation involving initial miscible gas injection, consistent with 20 AAC 25.402 (a). Approval of this application would permit these operations to be conducted in the Tarn Pool within the initial area targeted for development. The following attachments are submitted pursuant to 20 AAC 5.402 (c): 1. Plat with location of all existing wells that penetrate the injection zone within one- quarter mile of the area covered by this application 2. List of operators and surface owners within one-quarter mile of the proffered injection operations 3. Affidavit showing the operators and surface owners within one-quarter mile of the area affected by the Tarn Area Injection Order have been provided a copy of this application 4. Full description of the proposed operation 5. Description, depth, and name of the pool to be affected 6. Description of the formation into which fluids are to be injected and the associated' confining zones 7. Type well log 8. Casing description and proposed method for testing injection well casing 9. Injection fluid data 10. Estimated pressures ARCO Alaska, Inc. is a Subsidiary of AtlanticRichfieldCompany ) J 11. Evidence and data to support a commission finding that injection wells will not initiate or propagate fractures through the overlying strata 12. Analysis of the water within the formation 13. Reference to applicable freshwater exemption issued under 20 AAC 25.440 14. Incremental increase in ultimate hydrocarbon recovery. I appreciate your work on this application and would be happy to answer any related questions. I can be reached at 265-6268 or rstramp@ mail.arco.com via the internet. Sincerely, Ryan Stramp Tarn Coordinator Cc: Mike Kotowski ) ) Tarn Area Injection Order Attachment 1 20 AAC 25.402 (c)(1) Plat of Wells Penetrating Injection Zone The attached map (Attachment 1 A) shows all existing wells that penetrate the injection zone in the proposed injection area. The map also shows Tarn Reservoir seismic anomalies and the proposed Kuparuk River Unit expansion area. Although the exact acreage of the expansion has not yet been finalized, this map shows its largest possible extent based on current expansion efforts. In addition, the map shows Tarn development wells (with their expected service) planned to be drilled during 1998 and 1999 and Tarn exploratory well penetrations planned for 1998. Initial well location and service plans will likely change as net pay and well performance data are gathered. The total number, type and locations of wells ultimately drilled into the Tarn Pool will also be a function of net pay and well performance data. Since Tarn Reservoir distribution is stratigraphically controlled and sand accumulations are localized, sand continuity is expected to be difficult to predict. Producer/Injector interactions will likely be difficult to predict in the absence of field data. Development plans call for minimizing the number of injection wells until producer/injector interactions are better understood. Producers will be converted to injection service as necessary in order to provide pressure support and minimize injectant cycling. Hence, to as large of an extent as possible, plans are to let reservoir performance be a guide in optimizing pattern configurations. Although initial development plans do not include a Class II disposal well, future needs may eventually require one. The Ivishak Sandstone of the Sadlerochit Group has been selected, if needed. This zone is expected to have at least 60 feet of sandstone with porosities greater than 15% in the vicinity of the Tarn Participating Area. The Ivishak depth is expected to be approximately 8500 feet subsea. Several exploration wells have been drilled to this horizon in the vicinity of the Tarn Participating Area, in particular, the Union Kookpuk, Union Itkillik River and Sinclair Colville wells. The Ivishak Sandstone was wet in each of these wells. This zone is therefore also expected to be wet in the vicinity of the Tarn Participating Area. 3/981D HastinQs I 98031103800 6 KIomeIIn MIIMO KIIoInICIn 0 'I 2 M'" o Pre-1998 Exploration Wells I I I ARCa Alaska, Inc. <> Plat of Wells Penetrating Injection Zone . Planned 1998 Exploration Penetrations . Planned 1998-99 Injectors . Planned 1998-99 Producers ~~ " , ~ t{,(, Ktlhlrlpl( River Onit ,\'~ ~ ~q;,~ s ';L~,t~ ., IIJJ.'íl~Ci":'HK~.~t~~I!_"~lt111t~b.~¡;¡~; 1¡;~~~'t~~Ut~i~;I:t,:-';,¡,- - 31 H 31 3. ^rc~o 31 31 ~ ;, "J S .f.: I ,~ '\' ~ ~~ ) , Tarn Area Injection Order Attachment 1 A ) ,) Tarn Area Injection Order Attachment 2 20 AAC 25.402 (c)(2) Operators and Surface Owners within One Quarter Mile of Injection Operations Operator: ARCO Alaska, Inc. Attention: Scott Jepsen A TO-1220 P.O. Box 100360 Anchorage, AK 99510-0360 Surface Owner: State of Alaska Department of Natural Resources Attention: Mike Kotowski P.O. Box 107034 Anchorage, AK 99510 F<, t)"~: [ ~ \/ EC$ " ., .'; ,', ~~., ~'~ ~~.:] S" ;::~ ,'. " " " /,., , 'c P "r\~~r.!h't~ ¡·\lasl\íi ,¡)!¡ o~ \:';d~ . ,,ems. WCÎÌI~¡.6\'Wg,~~ Anchorage ') ) Tarn Area Injection Order Attachment 3 20 AAC 25.402 (c)(3) Affidavit of Ryan L. Stramp Regardina Notice to Surface Owners Ryan L. Stramp, on oath, deposes and says: 1. I am the Tarn Coordinator at ARCO Alaska, Inc., the designated operator of the Kuparuk River Unit (which will include the Tarn Pool). 2. On March 31, 1998, I caused copies of the Area Injection Order Application to be provided to the surface owner and operator of all land within a quarter mile of the unit as listed below: State of Alaska Department of Natural Resources Attention: Mike Kotowski P.O. Box 107034 Anchorage, AK 99510 ARCO Alaska, Inc. Attention: Scott Jepsen A TO-1220 P.O. Box 100360 Anchorage, AK 99510-0360 Ryan L. Stramp STATE OF ALASKA ) ) ss. THIRD JUDICIAL DISTRICT ) SUBSCRIBED AND SWORN to before me this 31th day of March, 1998. NOTARY PUBLIC IN AND FOR ALASKA My Commission Expires: ) ) Tarn Area Injection Order Attachment 4 20 AAC 25.402 {c}{4} Description of the Proposed Operation The Tarn Area Injection Order is needed to develop the Tarn Reservoir. The expected scope of the current development project involves drilling approximately 40 wells to develop 42 MMBO associated with an estimated 136 MMBO original oil in place (OOIP) seen by existing exploratory wells in the Bermuda Interval of the Tarn Reservoir. Although Attachment 1 A shows 48 penetrations, this is considered an upside case. Field Development Development wells will be drilled from two new drill sites. A phased development approach is planned to help minimize risk associated with the Tarn Reservoir (e.g., reservoir extent, pay thickness, permeability, etc.). The first phase of the project involves drilling approximately 20 wells starting during the second quarter of this year. Production would be initiated by yearend. Wells drilled during the first phase are intended to develop the main portion of the reservoir and test the periphery. The second phase of the project involves drilling approximately 20 more wells starting during the second quarter of 1999. The second phase is intended to primarily develop the periphery. Well performance data and improved seismic calibrations acquired from the first phase should help guide drilling operations during the second phase. Exploratory drilling targeting other zones within the Tarn Reservoir will be conducted concurrently with development drilling operations. Successful exploratory drilling results could alter existing plans by (1) changing the location and target interval of the initial development wells and (2) expanding the scope of the project to include additional wells. An expanded project scope would likely involve additional development drilling phases and may include additional drill sites. An expanded project scope may require an areal expansion of the proffered Tarn Area Injection Order. Recovery Mechanism The tight nature of the Tarn Reservoir (with an average air permeability measured at 9 md from core in the ARCO Tarn #2) coupled with expected sand discontinuities and permeability barriers will complicate pressure support efforts. Injection plans are to employ a relatively large slug of miscible injectant (MI) followed by a lean gas flush. Initial injection support is planned to commence no later than six months after first production. Initiating an enhanced oil recovery process from the start will achieve optimal recovery in a tight formation such as Tarn. Injection fluids are needed to sweep oil to the producers. Providing initial pressure support with immiscible fluids, such as water or lean gas, would ) ) have detrimental impacts on the initial development project and/or a future enriched gas injection project. Water is not a desirable initial injectant because of two principal reasons. First, laboratory core flood experiments suggest that water injection may cause formation damage. Second, water is much more viscous than MI. Maintaining pressure support with water would require a relatively high number of injection wells because of the low permeabilities and tortuous flow paths associated with the Tarn Reservoir. This would act to either significantly reduce production rate and/or significantly increase the total number of wells required for development. Screening level simulation runs were performed to evaluate initially waterflooding Tarn. These runs were made using extremely optimistic assumptions (Le., no formation damage and a matrix injection pressure 1500 psi greater than the reservoir parting pressure). Even with these optimistic assumptions, water could not compete with MI as an initial injection fluid. Further model runs with more realistic water injection assumptions were therefore not performed. Lean gas is not a desirable initial injection fluid as it would strip light ends from the Tarn crude. This would make it more difficult to achieve miscibility with an enriched natural gas at a later date. It makes little sense (from a reservoir standpoint) to initiate a flood with lean gas injection when an enriched gas EOR project is eventually planned. Once MI and/or gas cycling begins to occur, plans are to investigate a variety of remedial techniques. These include, but are not limited to, foam, polymers and water. Furthermore, employing sustained water injection to help provide pressure support following the lean gas flush is still considered a possibility. Additional field data (Le., reservoir permeabilities, injector/producer interactions, formation damage pilots, etc.) and simulation studies are needed to evaluate this possibility. Injectant Sources The miscible injectant employed at Tarn will initially be the same injectant as that currently used in the Kuparuk River Unit Large Scale EOR Project. This injectant is manufactured at Kuparuk's CPF-1 and CPF-2 by blending lean gas from the Kuparuk River Unit's production facilities with light hydrocarbon liquid streams from the Prudhoe Bay Unit and Kuparuk River Unit. The light liquid hydrocarbons from the Prudhoe Bay Unit are NGLs from the CGF. The light liquid hydrocarbons from the Kuparuk River Unit consist of scrubber liquids from artificial lift gas compression systems at CPF-1 and CPF-2, NGLs from CPF-1 and naphtha from the Topping Plant. During the flood, there is a possibility that Tarn produced gas may be blended with Kuparuk River Unit MI to generate a lighter MI blend customized for the Tarn Reservoir pressure and oil properties. Slim tube experiments and compositional modeling both demonstrate that MI from the Kuparuk River Unit is richer than needed to maintain miscibility with Tarn oil at reservoir pressure (2350 psig in the ARCO Tarn #2 well). ') ) Lean gas will be injected into the Tarn Formation after MI injection targets have been met., The purpose of the lean gas will be to recover previously injected MI and help provide pressure support. The source of the lean gas will be Kuparuk River Unit's CPF- 2. Potential gas accumulations in the area will also be considered as possible supplemental sources. Fluid and Cost Allocation Tarn production will be commingled with Kuparuk production in surface facilities prior to final processing and ultimate custody transfer in accordance with the Tarn Pool Rules (currently being developed). The Greater Kuparuk Area Alignment Agreement, which set new tract ownership and facility sharing terms in the Tarn area, will help govern business issues associated with sharing infrastructure. The Tarn production interests are as follows: ARCO Alaska, Inc. BPX UNOCAL MOBIL CHEVRON 0.552937 0.392823 0.049506 0.003648 0.001086 Total 1.000000 ) ) Tarn Area Injection Order Attachment 5 20 AAC 25.402 (c )(5) Description and Depth of Pool to be Affected The Tarn Reservoir is the informal name applied to the sequence of reservoir sandstones and associated mudstones found in the interval between 4331' and 6005', measured depth in the Area Tarn #2 well, and in its lateral equivalents. The Tarn Reservoir is late Cretaceous in age and stratigraphically within the Seabee Formation. The reservoir is approximately 1700' thick and is composed of up to five intervals. Two Tarn Reservoir intervals, the Cairn Interval and the Bermuda Interval, are sufficiently understood for development operations and are subsequently being included in the initial Tarn Oil Pool definition. Brief summaries of all five potential Tarn Reservoir intervals are summarized below in ascending order. · The C30 Interval was encountered between 6005' and 5696' measured depth in the ARCO Tarn #2 well; potential reservoir sands here appear wet on logs but had weak shows. · The Bermuda Interval was encountered between 5696' and 5460' measured depth in the ARCO Tarn #2 well, where it tested hydrocarbons. Hydrocarbon-bearing sands in this interval were encountered in four additional wells. · The Cairn Interval was encountered between 5460' and 5346' measured depth in the ARCO Tarn #2 well and between 5511' and 5332' measured depth in the ARCO Tarn #4 well (where log and core indicate hydrocarbons). · The Arete Interval lies between 5346' and 5108' measured depth in the ARCO Tarn #2 well. Seismic data indicate that reservoir sands may be present in laterally equivalent strata. · The Iceberg Interval is encountered between 5108' and 4331' measured depth in the ARCO Tarn #2 well. Seismic data indicate that reservoir sands may be present in laterally equivalent strata. The initial Tarn Oil Pool will be restricted to the Cairn interval and the Upper portion of the Bermuda Interval. Four correlatable horizon markers, T1 through T 4, have been identified on logs and tied to seismic data in these two intervals (Attachment 7). T2 and T3 bound the upper portion of the Bermuda Interval, wherein reservoir sands have been encountered, while T3 and T4 bound the reservoir-bearing Cairn Interval. Initial ) ) injection operations will be limited to this pool. An expansion of the pool definition may be sought in the future as additional information from development and exploratory drilling activities becomes available. ) ) Tarn Area Injection Order Attachment 6 20 AAC 25.402 (c)(6) Description of the Formation The proposed injection zone includes the Cairn Interval and the upper portion of the Bermuda Interval within the Tarn Reservoir. These zones lie between 5346' and 5608' measured depth in the Arco Tarn #2 well (see Attachment 7). The Cairn Interval lies between reservoir markers T3 and T 4 while the Upper portion of the Bermuda Interval lies between reservoir markers T2 and T3. The initial Tarn Pool definition has been limited to these two intervals. The Tarn Reservoir sands are fine- to very fine-grained and have common shale laminations and interbeds. Sands are compositionally heterogeneous: the major components include quartz, heterolithic rock fragments, plagioclase and zeolite. Shale laminations are common. Reservoir sands, which are locally developed within each interval, are lobate to linear in form, and are separated from adjacent reservoirs by mudstones and shales. The top of the Tarn Reservoir is separated from the Tabasco Sandstone equivalent, the first overlying potential reservoir zone, by a confining layer of approximately 1500' of impermeable shale. The base of the Tarn Reservoir is separated from the underlying Kuparuk River Formation by approximately 500 feet of shale. Gamma Ray SP..Bs foIIV) -90.0 GR (GAPI) SOD ) Resistivity PSR (Ol-Mll) 10 D 0.5 ATR (Ot-NM) SO D 150.0 MD õ:i------SÕ:õ ~ -4400- - 4500 . -4600· -4700 . - 4800 . -4900· -5000' -5100 . - 5200 . -5300- -5400· - 5500 . 5600 . -5(00 . - 5800 . -5900· ".. 6000 "' ~ · t61OO. ( , .J.. C37 14 13 - · T2 - - T1 C35 Iceberg Interval '" c o ¡ E .. o .. I.L ·õ G) ~ ! G) as (I) G) G) en a: c .. Cairn r ~ o Interval ~ Bermuda E IS Interval 1. A rete Interval C30 Interval C30 \II 'W ) '" Tarn Area Injection Order Attachment 7 20 AAC 25.402 (C) (7) Log of Tarn Type Well (ARCO Tarn #2) ~~.~~ :/:'"1 ~:~~:~ ~ 'L. :;f ',:,': ~:~ \t.1~ t.~ ~ ~ t~ .. '-,,', ,,' \'~(';' -I - ! I _ \ , ': ,I '0. . ~- ", .' - .¡''1 ~ fli ","''''',''' ~.",,~¡,.."I;¡,\, :"¡"~¡""Jj : ,I¡·'i. '~:;¡:3,tJDn~ì. \"¡m!tI,lbv¡U,~ .e''''\J''¡'\-J~\Q. "'" '... ....'. ......"" , Ac Ik:¡'O¡ane, ~ ...~ ARC a Alaska, Inc. ~,.. Tarn Reservoir Type Log 3/98 I 0 HastinQs I 98031 003AO 1 \) ,I ') Attachment 8 I Q J"~'> go ..t,; ~ ~ ;;L. ::::s ..... f'.:;' ~~ ~ I ii ,.. n C' n - < " o Tarn Area Injection Order 20 AAC 25.402 (c)(8) Casing Description and Proposed Method for Testina Casing The proposed casing programs for a typical Tarn well resembles the casing programs employed in the Kuparuk River Unit (KRU). Although the standard program incorporates maintaining a tubing annulus with isolation and pressure integrity within 200' of the initial producing interval, exceptions to this design criterion will be required to optimize recovery from potentially productive secondary targets. Standard Casing Program As in KRU wells, conductor casing will be set below 75' to provide anchorage and support for the rig diverter assembly. The surface casing size may be 9-5/8" or 7-5/8", depending on casing setting depth and production tubing size. Surface casing will be set below the base of the West Sak interval, effectively casing off the permafrost, Ugnu, and West Sak formations. When possible, surface casing may be set as deep as 200' above the Tarn interval. To accomplish this deep setting depth, offset wells must indicate no shallow hazards and the top of the producing formation must be highly predictable. This deep setting of the surface casing will most likely occur later in the development plan. Tarn wells utilize a tapered casing string tied back to surface, that serves as the combination production casing / tubing string installation. The casing adjacent from the producing interval is the same size as the tubing is at the surface (monobore). The casing across the production interval is then tied back to surface with a string of 3Y2" or 4Y2" tubing inserted into a seal bore or polished bore receptacle (positioned above the top pay zone perforation.) This provides a tubing annulus with isolation and pressure integrity (see diagrams below). There are three casing programs proposed for the Tarn development: Case 1) 4Y2" Slim-hole Monobore completions. This casing program employs 9- 5/8" (L-80, 40#) surface casing with 7" (L-80, 26#) production casing crossed over to 4Y2" (L-80, 12.6#) production casing. Case 2) 3Y2" and 4Y2" Monobore completions. This casing program employs a single string of 7-5/8" (L-80, 29.7#) casing set to within 200' of the Tarn formation top. A 3Y2" (L-80, 9.3#) or 4Y2" (L-80, 12.6#) liner would then be set across the Tarn formation and tied back to surface with either 3Y2" (L-80, 9.3#) or 4Y2" (L-80, 12.6#) production tubing. Case 3) 3Y2" Slim-hole Monobore completions. If the 7-5/8" (L-80, 29.7#) casing string cannot be set deep enough, a production string of 5Y2" (L-80, 15.5#) casing crossed over to 3Y2" (L-80, 9.3#) casing will be set to isolate the Tarn ') ) interval. These monobore wells will be completed with 3~" (L-80, 9.3#) production tubing. Case 1 Case 2 1m..... TIff·· .. .. .., .... . ...... ... .. . I .., .... . .,...' ... .. . I ... .... . ..... I ... .. .. .., .... . .....' ... "' .. .., .... . ....., ... .. .... .... ... I .... .... .... "'''' .... .... "" ... .... .... "" ... .... .... "" ... .... .... "" ... .... .... "" ... .... .... .... ::::::::;::: Z ~ :::::::~::: S 9-5/8" Csg '" . . . ::::::~J -{::::::: 2m: W@ }) ::}~: 7 -5/8" Csg ::::::: .~ :::::::: m:: y '< i:¡:?~ y::::: ¡::¡::0 m::::: I.' _. _, _'.'.' ....)) V Case 3 1m z . '-'-1' . ....... ,', S 7 -5/8" Csg , . -:':~J:-: .. . "' .. .. " .. .. .. " .. .. .. . .. .. .. I. .. .. .. " "' .. .. " .. .. .. " .. .. }~ ~{:': ..., .... .... ..... ..., .... .... .... ..., .... .... .... ..., .... .... .... ..., .... ......., ,... .... "" ... I .... ....... ,~ .... "" .:.:.:. ~""" :7':':':' ,":':':' ... ... ... .. .. .. .. . . . All three well types may be completed for either production or injection service. The service of the well will be determined after logging operations. Drilling and completion plans for future Tarn wells may vary with time as experience and knowledge are gained. The proposed method casing testing method for Tarn injectors is to follow the requirements of 20 AAC 25.412 (c). Sufficient notice of pressure tests will be given so that a Commission representative may witness the test. Secondary Targets The Bermuda Interval will be the primary target of initial development efforts. Current plans are to focus initial development efforts on that portion of the interval most likely have good reservoir characteristics. As previously shown on Attachment 7, potentially productive secondary targets in the Iceberg Interval, Arete Interval and Cairn Interval may be encountered during these development efforts. Secondary targets in the Arete Interval and Cairn Interval are expected to generally be within 400 feet TVD of the Bermuda Interval, however, secondary targets in the Iceberg Interval may be higher. These thin, potentially productive zones contain insufficient reserves to merit separate wells or extensive completion design modifications. Although fracture stimulations are planned for Bermuda Interval producers, fracture modeling indicates these stimulations ) ) will only grow approximately 200 feet upwards. Potentially productive secondary pay zones can therefore only be developed if they can be inexpensively commingled with Bermuda production. Given the initial uncertainty of producer/injector interactions, most producers will be candidates for conversion to injection service. In order to maintain conversion flexibility, there are no casing design differences between production and injection wells. (Casing connections will be designed for gas or liquid service.) The flexibility to convert wells to injection service on an as needed basis is an integral part of the Tarn development strategy. This complicates secondary target development as these targets can only be pursued if they are not isolated by more than one casing string. Pursing secondary targets may result in exceeding the AOGCC guideline that injectors provide annular isolation within 200 feet measured depth of the highest perforated interval. Plans are to provide annular isolation within 200 feet measured depth of the perforated zone, unless secondary targets are encountered with a pay thickness approaching or exceeding 10 feet TVD. Based on current drilling and facility hook-up plans, the productive nature of these secondary targets can not be fully ascertained during initial drilling operations. If future evaluations indicate that developing secondary targets can not be justified, there is the potential of having future injectors with annular isolation located more than 200 feet measured depth above the perforated zone. Tarn Oil Pool Rules are written to help ensure that well service flexibility is not sacrificed by attempting to pursue thin secondary targets. ) ') Tarn Area Injection Order Attachment 9 20 AAC 25.402 (c)(9) Injection Fluid Analysis The vast majority of the MI initially employed at Tarn will originate from Kuparuk River Unit's CPF-2. After the second phase of development drilling, injection rates are expected to be in the 30 - 50 MMSCFPD range. Lean gas employed to displace the MI will likely originate from either Kuparuk River Unit's CPF-2 or Tarn produced gas. Current plans are to obtain the gas from Kuparuk River Unit's CPF-2. The average MI and lean gas composition produced at the Kuparuk CPF-2 facility during late 1997 is presented below. There is no evidence from laboratory core flood experiments or compositional studies that indicate the hydrocarbons proffered for injection would pose compatibility problems for either the Tarn Formation or its confining zones. Miscible Injectant & Lean Gas Composition Supplied by the Kuparuk River Unit's CPF-2 Component MI Lean Gas (Mole %) (Mole %) CO2 1.0 0.9 N2 0.2 0.2 C1 66.0 80.9 C2 7.9 10.0 C3 5.4 5.0 iC4 2.4 0.8 nC4 7.0 1.6 iC5 2.3 0.3 nC5 2.8 0.2 C6 2.2 0.1 C7 1.9 0.0 Cs+ 0.9 0.0 ) ) Tarn Area Injection Order Attachment 10 20 AAC 25.402 (c)(10) Estimated Pressures The maximum MI injection pressures available at the plant will be 4,400 psi. Due to pressure losses in the distribution system, actual maximum wellhead pressures will vary. Injection wells may also be choked to avoid exceeding injection targets. Wellhead injection pressures are expected to range from 2,700 psi to 3,700 psL ) Tarn Area Injection Order Attachment 11 20 AAC 25.402 (c){11) Fracture Information Injection into the Tarn Formation will not breach the reservoir's confining zones. Neither injection nor formation fluids will be able to enter any freshwater strata. Although bottom-hole pressures may exceed the formation parting pressure, the Tarn producing sands are separated by over 1500 feet of confining shales and mudstones which act as an impermeable barrier (see Attachment 11 A). These confining layers provide a substantially greater barrier than necessary to contain fractures within the Tarn interval. Hydraulically propped fracture stimulations are planned for Tarn producers. The 1500 feet of confining shales and mudstones also provide a substantially greater barrier than necessary to contain these fracture stimulations. Fracture modeling suggests that typical fracture stimulations will grow upward approximately 200 feet. Model runs with worst case assumptions (which cause the most upward growth) suggest the stimulations will not exceed 500 feet of upward growth. ) '} Resistivity P.:R ~1fM ) Tarn Area Injection Order Gamma Ray SP_BS ~v ) eo 0 100 GR 4»\ P 0 so 0 1500 MD ~ - 2400 - - 2600 - f -2800- t - l -3000- ( OS; :'" - 3200 - - 3400 - ~ -3600- ~( :3800- ......- ....a ~ \' - 4000 - '; .21 l4200: - 4400 - - 4600 - - 4800 - ~ ~5000~ ~~ -5200- - 5400 - _ "fi(\O - - 5800 - ~ ßOOO ~ "- o S so 0 A TR PI-NM ) o-Š-------SÕo- f ~ i a- ~ -::S- ~ c ... ceo Tabasco Interval C37 Á C30 y Attachment 11A Log of Tarn Type Well (ARCO Tarn #2) ARca Alaska, Inc. <> Tarn Reservoir Type Log 3/981 0 Hastinqs I 98031004A01 ) J Tarn Area Injection Order Attachment 12 AAC 25.402 (c)(12) Formation Fluid No oil-water or gas-water contacts within the Tarn formation have been encountered. Average salinity estimates from immobile connate water were estimated from low invasion cores. Connate water was obtained from core plugs using a miscible (CHCI3 / CH30H) extraction process. Subsequent water volumes were estimated using Karl Fisher analysis and chlorides were measured using ion chromatography. The resultant estimated connate water NaCI concentration was 30,000 ppm. p r: \ ~\, ;~" ¡ ~ . ~ t'~ \ .,) (' " "\0,::; \.,../"Þ \ U"J1\~\\}n n;; .1~. ~-:1(" Ct\\ì.s.I.;U i\ .~" ì\~f'ska Vl' \,:, \:;~\) b~9.c.','·· .' " ~cb~,~~e ) , Tarn Area Injection Order Attachment 13 20 AAC 25.402 (c){13) Aquifer Exemption The EP A established an aquifer exemption for the Kuparuk River Unit in the early 1980's. This exemption includes the proposed injection area requested in this application (see Attachment 13A). Aquifers covered in the exemption include those associated with the West Sak and Ugnu formation. ) ) Tarn Area Injection Order Attachment 13A .."'._IIC'__:w-....t...~ ····__·........·....~.....,'I"a;6IIWOOO .~ : "'''""h''I''I'''_''¡~",,,_,,_, .'r.:.-...'''........M....'''''~r,'=-..~IIO'''........_.,........'.._,. '....... "_", .......'...¡......~..._.;~ , _...............~....... .....".....'f(¥."...................-,,_"IAi- ~ ~. ~ . 1,'"'.,.........~.............:.;,""'-"'I.t'........-......,..~....._· .,...""_.......,.,......~........,. , '1 f'" --." ,,-__L_...;;~~_~~ ,._."._..~.~ .~.....~. < ~:N!.U........"'P.ofI-..a~...""'-,_"'.. ...1.-. i ~,.-, ,,,-...; ........._,.,....~,... ·....',........·--....~I , , . 'I --~-~- "...-." ..-..-.... ~..~........ II:..·.·...,,·,~,,~'."....··.~'... ','" ..·.'.'..,.......n.......'. .. .t' ..n 11\ ~ \ . , : ;. ~ I '",.~''''..w..:.~~,.''''''.._~.......-~..''M.,...UU.r............~~~"'''': { , , v:·- ",,,-,,~-,,,,,,__.,,,~"I.~: : ) ¡ , r-''''! ~ .- \ !: - . , ,..~. . ¡.. ,...............(,,~ L--'..'...., ~um.~ ¡ ~ " I ,i ~ : . .~~,...,.,;.."...;.....- ...."-,,...-.-....~-':.~ LL" '~';---':'.._- , . , , , . :_,....._N'~__.. . '.............,_.....",·.'~t .......,...~~..~.,.__.. Kuparuk River Unit I ' I.' . ~,..·...~......._..._¡·..·\-~~""""-~.................,..¡··..._..-..-a.····1 ~ ¡ ! ~...~;~ . J I ~ ~ :.'··'~........T.,I···'.......~T- ..:.....,.IO!!"'~..""""~.........,_. ! ~ ; ~~ , , , ...,~_'.~.J'..."'~ ¡ . I~-..--.n..o""""'. .--,-..-"...' .-_-......__ .1·'_......- . ..~._.~-. ;,~..,Ioo_......_........... L'-" ..d. 1.--... :, . ·i"..... .' '~N__ . · -~~---"'1''''-'''''~ .''":-.._" - "","",. ...'....<Þ--....'~............_....__'._... _I..~i.--_~..._.,...... ....~... - Mo4lr.··... .._~._tI~IIII.II.n..~,~.~...... .__~_........¡.I.__...."qo¢,__.....____........_.........~"~ ,...,.~...,_...._.....-_.-. ·rl"~_'_.".,.., .,...............--'...~...~. .... ... ___...;.r..._r-::' .'IIIOIoo\i.~_.\."'I.....~.-c.. ....,*~..Qo......~ ;UIC Exemption Area . ......,..-.--.-"....---...""""-"-...-..... ..·....·-~'.I.·....,··_'... .-."".......... - ...--........-¡,.-..-.........:-o")- .........._.....,....'_. v / /J Tarn Proposed I~ Injection Area MUee 0 Kllom.t.... 0 . ¡¡¡¡¡¡¡ 2 III'" S KIIom..... ARCO Alaska, Inc. <> UIC Exemption Area: Tarn Proposed Injection Area 3/98 I 0 Hastinqs I 98031102AOO ) ) Tarn Area Injection Order Attachment 14 20 AAC 25.402 (c){14) Incremental Hydrocarbon Recovery The Tarn Sand was tested in the ARCO Tarn #2 exploration well. Fluids recovered from the test indicated the interval contains 370 API gravity crude with a solution GaR of approximately 700 SCF/B. There is no evidence that this zone is in contact with either an aquifer or gas cap to provide pressure support. Although there is some evidence that the ARGO Tarn #4 exploration well may have penetrated a gas cap in the Cairn Sand, current mapping suggests that the gas cap, if it exists, would be too small to provide appreciable pressure support. Simulation results indicate that injecting a 20% hydrocarbon pore volume slug of MI followed by a lean gas flush would recover 310/0 OOIP. This recovery factor is approximately 10% OOIP higher than that obtained from straight lean gas injection and approximately 20% OOIP higher than that obtained from primary depletion. Mr. David Johnston March 31, 1998 ) ) Re: Tarn Area Injection Order 20 AAC 25.402 Bcc: Hans Erickson, Cathy Foerster Lamont Frazer, Steve Kranker, Doug Hastings, Lisa Pekich, George Phillips, Dora Soria, Jack Walker, Mike Zanghi, \ NSK-14 ATO-1270 ATO-1246 ATO-1252 ATO-1264 ATO-1134 ATO-1550 ATO-1370 ATO-1248 ATO-1276 #4 ) ~ ) Notice of Public Hearing STATE OF ALASKA Oil and Gas Conservation Commission Re: The application of ARCO Alaska, Inc. for a public hearing to define the Tarn Oil Pool. An Area Injection Order is also requested for Class II injection for the purposes of enhanced oil recovery operations. Notice is hereby given that ARCO Alaska, Inc. has petitioned the Alaska Oil and Gas Conservation Commission under 20 AAC 25.520 to hold a public hearing to present testimony to establish pool rules for the Tarn Oil Pool in order to facilitate initial development of the reservoir, and to allow Class II injection to enable enhanced recovery. The proposed development area is located in the Kuparuk River Unit on the North Slope of Alaska. A hearing will be held at the Alaska Oil and Gas Conservation Commission, 3001 Porcupine Drive, Anchorage, Alaska 99501, at 9:00 am on . April 28, 1998 in conformance with 20 AAC 25.540. All interested persons and parties are invited to present testimony. If you are a person with a disability who may need a speciallTIodification in order to comment or to attend the public hearing, please contact Diana Fleck at 279-1433 no later than April 21, 1998. c Published March 28, 1998 ADN AO 02814034 ORIGINAL 1/14460 STOF0330 AO-02814034 $58.50 STATE OF ALASKA, THIRD JUDICIAL DISTRICT. Eva H. Kaufmann ") ) AFFIDAVIT OF PUBLICATION 3/28/98 "Notice~t PUlllic',Heår!~!I':"::I' , , ',', """ ',:1\,: ',:-',~'/ STATE OF AI,;AslKA" ,'y.Lf ',Alaska Oil and Gas.' I" CClnservation Com~I~$IO~'., ,: Rr.> The'CDDlicat1òn of" ,':" toRro ':'Ia;~a In, tÜ~,a'p~þlic' r,...a;,ng to (etln& Trle'"J1q~öl:t,,,IP'!\1 P-"I ton "'1:'0 In,,,,'tiqn' 'r~~r I I ¡su~aISo reQUesTeo lor ClOss' ,. II , Iniec:tlon\for the ~urDos~~O,f, ; enhonc,ed 011 rec~very I oP~gn~~s"s hereby giver¡ 'thQt" ARCa Alaska.' Inc. has peti- tioned the Aloska Oil and Gas, Conservation Commission ,un· der 20 AAC' 25,520 to, hold a public hearing to present, "\ testimony to 'establish 'pqol' rules for, the 'Tarn· Oll.pool ,n order to facilitate Inltlol devElb , opmehto~'thé'(èsêrvW;tJnèl\',ta,1 alh;¡w C, lass II In,lectI9,p, ':tQ':,e,~,~\,: abte' enhon,ced re~êo~VllrY. ~~T~~ I p(6,osed' de\j'elopm ''':' 'I ar_ ;,:, located in the K~Pp.ruk ~¡'iler" U'~I"I'I:ol" ,tt:le NP'~thll/,?I(Pf¡":Î9fl( Aløsko:ï', ",<, ",;,:::¡¡li~~ir:'::S, .. .,1,,; "~~ ':~",h'ébrln~:'wiH ,l!)ê"tfJld dtJ '&~" Alo,k.O 011 ',QQd, Ga~,,(¡ol)~e~va'l tloli'\: Commls$t9n. 3ØOl "pørcµ- plì\e Drrve, An"tì9r'Þ~t; ..' ~I¡al '~2k8a, 995()1"at,...9:00 "am '011" AP,r . 1998 in conformance with 20 AAC 25.540, All Interested per- sons andPort,)e~ .are 'Invited to presenr,f~&t,.\rTionx.: , , . -If ,Yø~'L.'Q~Lë'..,:.ø'~enSl:~,,~I'~,Ai1'.,I/t:: dlsâbllltv'~~~! '!;rI¢lY' 'ree.., ' "I speC:l,dl' QC,FOI't!.. '~Ði:I, om., n,:"~!1lL~rd"'..,I, der to' c'oMm~!1t' òr;tOII'Q1Te~, the public 'heClr,inq,jlt.'",.)I!p,.~e., C.o"n-\.; tact Diana FleCk:'ot"~rr-143~ ,~?': latefthan AÞ~lr.21, il9~9·,;'.{":,,,"::1;'~,!: Js/DavidW.JohOsto~, ' ,'. . , '." "<::hdlrn'lM .1' .',: :"",,"" ,I ADN AO 02814034 , 'Þ~b.;: Márt~,_ 28;'; 1998 ..,..-. ............................................ being first duly sworn on oath deposes and says that he/she is an advertising representative of the Anchorage Daily News, a daily newspaper. That said newspaper has been approved by the Third Judicial Court, Anchorage, Alaska, and it now and has, been published in the English language continually as a daily newspaper in Anchorage. Alaska. and it is now and during all said time was printed in an office maintained at the aforesaid place of pUblication of said newspaper. That the annexed is a copy of an advertisement as it was published in regular issues (and not in supplemental form) of said newspaper on and that such newspaper was regu larly distributed to its subscribers during all of said period. That the full amount of the fee charged for the foregoing publ ¡cation is not in excess of the rate charged private ~:~~ m~s;~ k.__ slgneu Subscribed and sworn to befor ' . 3/' 7líæ-1c--Æ.) me this :";... . day of .................... 9~ t 9...~,.!? -1 /. ") (/ /j , /J/~~. ..... .... ....:......./!j(lj L,7~'·!." Notary- ~IC in and for the State of Alaska. Third Division. Anchorage. Alaska MY COMMISSION EXPIRES ¡; ( ~ .............Cb.....2::..........F1:õ ú #3 ) ) ARCO Alaska, Inc. Post Office Box 100360 Anchorage, Alaska 99510-0360 Telephone: (907) 276-1215 Douglas S. Hastings Kuparuk Development ATO 1264 Phone 265-6967 Fax 263-4566 .£~~ ~~". Cv ~~' " ". to March 25, 1998 Grover Partee OW-137 USEPA Region 10 1200 6th Avenue Seattle, Washington 98101 Mr. Partee: Enclosed are the maps of the Kuparuk River Unit, Alaska, which were requested for consideration of the Tarn Pool Area Injection Order. The enclosed maps are: 1. 1981 Kuparuk River Unit Boundary, overlain on current leases/ownership 2. Current Kuparuk River Unit Boundary, overlain on current leases/ownership 3. Current Kuparuk River Unit Boundary and proposed Expanded Current Kuparuk River Unit Boundary, overlain on current leases/ownership. Please let me know if you need any additional information. Sincerely, ~.~~iJøk-p Douglas S. Hastings RECEtVED ~~ ,"? .;~ 1 1998 !'i¡r;,¡ \ >".' Enclosures Cc Ryan Stramp, Arco Alaska, Inc. Dora Soria, Arco Alaska, Inc. David Johnson, Alaska Oil and Gas Conservation Commission 'SSiOfl ka Oì~ & Gas Cons. Comfit.. Alas Anchorage ARCO Alaska, Inc. Is a Subsidiary of AtlantlcRlchfleldCompany #2 "'" 6-23-58 5:07PM ) ARCO ALASt<A~ "-" .-) \ ", '. '. ,..J...... ... "_, . ; °0 C '. .- ' 907 276 7542;# 2/ 3 SENT BY: ._.....,.. . .- '.'-. --...-. -- ARca Alaska, Inc. ~~ ~~ Kuparuk Development Post Office Box 100360 700 G Street Anchorage, Alaska 99510 Telephone 907 265~6a06 Ryan Stramp, Tarn Coordinator March 9, 1998 ht:l.,t:1 Vt:D dUN 2 ",' 1998 IÛaska Oi/ & Gas.f'A- \lUllS. Commictð' Anchorsge ""'~'On Mr. David Johnston Alaska Oil and Gas Conservation Commission 3001 Porcupine Road Anchorage, AK 99501 Re: Tam Area Injection Order 20 AAC 25.402 Dear Sir: ARCa Alaska. Inc. (AAI) is pursing development of the Tarn Reservoir through an expansion of the Kuparuk River Unit. (Parallel efforts to expand the Kuparuk River Unit and formulate pool rules to facilitate Tarn Reservoir development are in progress.) AAI briefed the Commission on Tarn during a February 3, 1998 meeting. AAI in its capacity as operator submits this letter as an application for Alaska Oil and Gas Conservation Commission approval to conduct an enhanced recovery operation involving initial miscible gas injection, consistent with 20 AAC 25.402 (a). Approval of this application would permit these operations to be conducted in the Tam Reservoir anywhere within the expanded Kuparuk River Unit. The following attachments are submitted pursuant to 20 AAC 5.402 (c): 1. Plat with location of all existing wells that penetrate the injection zone within one.. quarter mile of the planned Kuparuk River Unit expansion 2. Ust of operators and surface owners within one-quarter mile of the expanded Kuparuk River Unit 3. Affidavit showing the operators and surface owners within one-quarter mile of the area affected by the Tarn Area Injection Order have been provided a copy of this application 4. Full description of the proposed operation 5. Description, depth, and name of the pool to be affected 6. Description of the formation into which fluids are to be injected and the associated confining zones 7. Type well log 8. Casing description and proposed method for testing injection well casing 9, Injection fluid data 10. Estimated pressures ARCO AI....., Inc. Is iii SubslcHary of AtlantlcFUchfleldCompen., '). 6-23-58 5:07PM ) ARCO ALASJ<A~ ) 907 276 7542;# 3/ 3 SENT BY: 11. Evidence and data to support a commission finding that injections wells will not initiate or propagate fractures through the overlying strata 12. Analysis of the water within the formation 13. Reference to applicable freshwater exemption issued under 20 AAC 25.440 14. Incremental increase in ultimate hydrocarbon recovery. I appreciate your work on this application and wouJd be happy to answer any related questions. I can be reached at 265-6268 or ~stramp @ mª.ìI.arco.col11 via the internet. Sincerely, Ryan Stramp Tam Coordinator Cc= Mike Kotowski ~·"c:c,r:1 Vt:Û JUN 2,+ 1998 Alaska Oil & Gas Cons. Commis.,ioo AnchOfSge #1 ARCO Alaska, Inc. Post Office Box 100360 Anchorage Alaska 99510-0360 Telephone 907 276 1215 ) ) ~~ ~~ t . '\,"'" 1."" I'''' [... i '" " E"- D.', h "1' ,I ~v I "",,~. 1"1.' -j \;,. :," - , , ',\";" !,:..~ \,'" ,.,' 'i.'~' ;,"t:[32,0 February 18, 1998 l\1;:!,:;/,;(¿¡ 011 :~, Gas Cüns. Commission l-\rlGhcnage Mr. Bob Crandall Alaska Oil and Gas Conservation Commission 3001 Porcupine Road Anchorage, AK 99501 Re: Greater Kuparuk Area (GKA) Area Injection Order and Aquifer Exemption Dear Mr. Crandall: O~ GtNA~ As we discussed on February 10, 1998, ARCO Alaska, Inc. (AAI) is' preparing to develop two satellite reservoirs in the Greater Kuparuk Area (GKA). We met with the Commission on February 3, 1998 to discuss the Tarn Project and on February 12, 1998 to discuss the Tabasco Project. These two projects involve enhanced oil recovery from the beginning of development. Neither of these reservoir depths are authorized in the Kuparuk Area Injection Order (AOGCC AIO #2) for enhanced oil recovery injection. AAI is seeking guidance about the possibility of amending the existing Kuparuk aquifer exemption and area injection order to cover injection activities at Tarn and Tabasco. The Tarn Project is located southwest of Kuparuk Drillsite 2M and consists of two new Drillsites, 2L and 2N, which are outside the current Kuparuk River Unit (KRU) boundaries. However, the surface location of these drillsites is within the original KRU boundaries (Orillsite 2N is right on the boundary) prior to contraction (Attachments 1 and 2). In fact, AIO #2 contains an area description that includes the surface location of Drillsites 2L and 2N, but the development plan includes drilling deviated wells from Orillsite 2N that will have bottom hole locations outside the old unit boundaries. AAI is preparing an application to AONR to extend the unit boundaries to include the Tarn Project and form the Tarn Participating Area. A preliminary map of this unit expansion application is included in Attachment 3. AAI anticipates that the unit expansion will be completed prior to commencement of injection activities; however, we cannot guarantee this. The unit expansion does not have to be completed prior to production activities. Production and injection activities are scheduled to begin as soon as July 1998. The Tabasco Project is currently planned from existing Kuparuk Drillsite 2T (Attachment 4). All bottom hole locations for this project will be inside the current ARCO Alaska, Inc, is a Subsidiary of Atlantic Richfield Company AR3B·6003-C \ , ) Mr. Bob Cranoall Page 2 February 17, 1998 ) Re: Greater Kuparuk Area (GKA) Area Injection Order and Aquifer Exemption KRU boundaries. AAI would like to begin a pilot project that includes water injection around April 15, 1998. This pilot project would include one water injection well. Due to lack of information available at this time, AAI is preparing an application for single injection well for this pilot project. Depending on the results of the pilot project, AAI will apply for an area injection order to cover waterflood activities in the entire reservior. Development drilling may commence as soon as September 1998. The Kuparuk River Unit received an aquifer exemption from EP A in the early 1980's. This exemption includes all aquifers below and within a quarter mile of the Kuparuk River Unit. The aquifers requiring the exemption are West Sak and Ugnu. When the exemption was obtained, the application described the original unit boundaries as the area of injection. This is the same area described in AIO #2. Once again, this description includes the surface location of Drillsites 2L and 2N; however, it does not capture all the bottom hole targets from Drillsite 2N. The West Sak and Ugnu formations are present in the Tarn area and from the limited data obtained appear to contain water. Since the West Sak and Ugnu water in the Kuparuk area contain <10,000 TDS, AAI is assuming the water in the Tarn area would also require an aquifer exemption or an extension of the existing Kuparuk aquifer exemption. Since the aquifer exemption is separate from the area injection order, AAI is requesting guidance from the Commission on what is required for Tarn injection activities. Based on discussions with the Commission, AAI is currently preparing an application for an area injection order to cover the Tarn reservoir and a single injection well permit for the Tabasco pilot project. It is our understanding that upon receipt of the applications, the Commission will determine if the Kuparuk A10#2 can be amended to include enhanced oil recovery injection activities in the Tarn and Tabasco reservoirs or if a new area injection order is required. This determination does not change the information required in the applications. ) Mr. Bob Crandall Page 3 February 17,1998 .J Re: Greater Kuparuk Area (GKA) Area Injection Order and Aquifer Exemption In our discussion on February 10, you asked that we include information on disposal needs for these projects. The Kuparuk AI0#2, Rule 2 already authorizes two disposal zones within the unit. Currently, there are four year-round active Class II disposal wells in the unit, one of which is located at Drillsite 2M which is the closest drillsite to the Tarn and Tabasco projects. Therefore, at this time, AAI does not anticipate the need for an additional disposal well to support Tarn and Tabasco development. However, based on advice from the Commission, we are planning on including a request for a disposal zone in the Tarn area in the application. Any guidance on this process, especially in regard to the aquifer exemption, would be appreciated prior to submittal of our application. If you have any questions, please contact me at 265-1173 or by email atlpekich@mail.arco.com. JcerelY, ~Jp~j, L~a L. Pekich Environmental Coordinator Attachments 925/005.04/lIp o ~/le"7 CK APP AR JWS ~ ) DESCRIPTION ISSUE FOR PERIIT REV DA TE 8.... " A· ff,t Gh VY) e ¡;J. ( JCK APP DESCRIPTION \ ~ c.s.~ J! . , '-¢" ' REV, ~ATE '8Y ~ \K ~Q C\ C>\ )([,! I. 0 ~36 \~ q t ~'» ~~ ~ 31 ~ Q !0~ ~ ----- /\jo \) ð. C> Q~ , T 11 NtJ c:: ~ 1\ '! \\ t> ,..." T 10 N....... \. V..../ " O ~ - n..f) 0 Q ............... j } 1. ~ q ,///::ST°\) W~ t:;) ~ ~ ~$\~~--R.9!:'te_____/.Pii/'6' Q: ~~K 15 "a ~ c~ q'~J' ~~ ~ v~ ~QPY§!1.d_~!Jj!I$-_J~, /) ~ ~ ~ Q ,.é"o, ....~ <I'~~~ J Q:: ol?~ C?~ \\r C) ') 1\ '<~ ~ V\ \ ~ </<1' </<1,-0 tÇ¡ 6 ~ rJ~ Î\ \.) Ut) SCALE: ~ - ? '8 ~ _ ì Ð 11· ö ~! ~Oo?j~~.n:~_. ~t ~tß~ ~ D.c2 ¿ 8 ~ ~ J This map is based on U.S.G.S. quod Harrison Boy A-1 & B-1 c:( ~ - and on the Unit Operator's Facility Mops. 8 0 $ ~ Q C) PROJECT LOCATIONS: f ~ CL ~" <:: D.S. 2-L D.S. 2-N ~(-" ~ ~ \10 LA T. = 70· 12' 47.979" LA T. = 70· 10' 12.032" . ~Ch~~~k ?'_.... LONG. = 150· 19' 05.470" LONG. = 150· 19' 07.652" F eu Y = 5,927,666.19 Y = 5,911,928.26 /"- . #. X = 460,930.71 X = 460,772.75 - / ~ ~ 36 DATUM: BRITISH PETROLEUM MEAN SEA LEVEL. ~ () ALASKA STATE PLANE ZONE 4, NAD 27. (' O~ I '" Q PURPOSE: ROAD AND PAD CONSTRUCTION. ;.,¡; ~ ~ ~ TT 1~ ~ ADJACENT PROPERTY OWNER: STATE OF ALASKA. ~ " PROPOSED ~ D.S. 2-N ,..----~--- ,," G cr fi a - 6 ~ LOUNSBURY & ASSOCIATES, INC. ·E~~ŒERS PLANNERS SURVEYORS AREA 00 MODULE XXXX KUP ARUK RIVER UNIT TARN PROJECT PROJECT MAP CEA-R1 XX-3936 SHEET: 1 OF 1 UNIT R1 ww ~ \ "'-~ ARCO Alaska, Inc. <> Subsidiary of Atlantic Richfield Company "'co ~~ CADD FILE NO. 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