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Home My WebLink AboutAIO 004 GAREA INJECTION ORDER 4G AIO-15-033 Prudhoe Bay Field Prudhoe Bay Unit Eastern Operating Area Prudhoe Oil Pool Put River Oil Pool Lisburne Oil Pool Pt. McIntyre Oil Pool West Beach Oil Pool Stump Island Oil Pool North Slope Borough, Alaska 1. July 17, 2015 BPXA’s request for amendment of Pool Rule 9 and modification of AIO 3A and AIO 4F (confidential appendix held in secure storage) 2. July 20, 2015 Notice of Public Hearing, Affidavit of Publication, Email list, bulk mail list 3. July 23, 2015 (Revised) Notice of Public Hearing, Affidavit of Publication, Email list, bulk mail list 4. August 19, 2015 CPA’s comments 5. August 25, 2015 BPXA’s written comments (confidential appendix held in secure storage) 6. August 27, 2015 Hearing transcript (held in CO 341F), hearing sign in sheet, public testimony, presentations (confidential presentation held in secure storage) 7. September 3, 2015 CPA supplemental submission 8. September 4, 2015 Email re: supplemental information on CO2 disposal 9. September 8, 2015 BPXA post hearing submissions (confidential appendix held in secure storage) 10. July 27, 2016 BPXA request to continue water injection operations into PBU 09-25 (AIO 4G-001) 11. August 8, 2016 BPXA request to continue water injection operations into PTM P2-09 (AIO 4G-002) 12. August 24, 2016 Email 13. August 22, 2016 BPXA request to continue water injection operations into PBU 13-31A (AIO 4G-003) 14. February 7, 2017 BPXA request to continue water injection operations into PBU 11-07 (AIO 4G-004) 15. February 2, 2017 BPXA request to continue water injection operations into PBU P1-21 (AIO 4G-005) 16. March 24, 2017 BPXA request to continue water injection operations into PBU 04-43 (AIO 4G-006) 17. August 28, 2017 BPXA request to continue water injection operations into PBU 16-14B (AIO 4G-007) 18. February 8, 2018 BPXA request to continue water injection operations into PBU R-22A (AIO 4G-008) 19. June 7, 2019 BPXA request to cancel AIO 4G.007 (aio4G.007 cancel) 20. December 9, 2019 BPXA request to cancel AIO 4G.004 (aio4G.004 cancel) 21. December 9, 2019 BPXA request to continue water injection operations into PBU R-22A (AIO 4G-009) 22. July 21, 2020 Hilcorp request to amend continue water injection operations into PBU R-22A (AIO 4G-008 amended) 23. July 31, 2020 Hilcorp request to amend continue water injection operations into PBU PSI-01 (AIO 4G-0010) 24. July 31, 2020 Hilcorp request to amend continue water injection operations into PBU 17-13A (AIO 4G-0011) 25. March 9, 2020 BPXA request to amend defined inner annulus normal operating limits on injectors operating under administrative approval 26. October 2, 2020 AOGCC approval of March 9, 2020 request 27. October 6, 2021 Investigation of Late Mechanical Integrity Test for PBU W-44 (PTD 189-100) 28. October 11, 2021 Additional data for late Mechanical Integrity Test for PBU W-44 (PTD 189-100) 29. October 21, 2021 Closeout of investigation of late MIT for PBU W-44 30. January 25, 2022 Request to continue WAG injection operations for P1-01 (PTD 190-0270) (AIO 4G.012) 31. February 2, 2022 Request to continue WAG injection operations for P2-34 (PTD 195-066) (AIO 4G.013) 32. February 21, 2022 Request to allow continued gas injection operations NGI-12, PTD 177-081 (AIO 4G.014) 33. March 14, 2022 Request to allow continued gas injection operations with a slow IA by OA communication (AIO 4G.015) 34. June 6, 2023 Request for admin approval PBU 04-11A (AIO 4G.016) 35. November 13, 2023 Request for amendment to AIO 4G.011 (AIO 4G.011 Amended) 36. March 12, 2024 Hilcorp request for admin approval for continued gas injections in Well 03-07B (PTD 219-182) (AIO 4G.017) 37. April 17, 2025 Hilcorp request for admin approval to allow Produce Water Injection Operations in Well PAVE 3-1 (PTD 224-140) (AIO 4G.018) 38. August 18, 2025 Hilcorp request for Administrative Approval to allow seawater injection operations in Well L5-29 (PTD 187-045) (AIO 4G.019) ORDERS STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION 333 West 7t" Avenue Anchorage Alaska 99501 Re: THE APPLICATION OF BP Exploration (Alaska) Inc. for amendments to Area Injection Order 4Fto authorize the injection of carbon dioxide effluent from the proposed Alaska LNG Project gas treatment plant for the purposes of enhanced oil recovery, and the request from ConocoPhillips Alaska Inc. to authorize disposal of the carbon dioxide effluent. IT APPEARING THAT: Docket Number: AIO-15-033 Area Injection Order No. 4G Prudhoe Bay Field Prudhoe Bay Unit Eastern Operating Area Prudhoe Oil Pool Put River Oil Pool Lisburne Oil Pool Pt. McIntyre Oil Pool West Beach Oil Pool Stump Island Oil Pool North Slope Borough, Alaska October 15, 2015 1. By application received July 17, 2015, BP Exploration (Alaska) Inc. (BPXA) on behalf of itself and ExxonMobil Alaska Production Inc. (ExxonMobil) as working interest owners (WIOs) in the Prudhoe Bay Unit (PBU) requested that Area Injection Order (AIO) 4F be amended to allow the injection of carbon dioxide (CO2) for enhanced recovery and pressure maintenance purposes from sources inside and outside the PBU. 2. Pursuant to 20 AAC 25.540, the Alaska Oil and Gas Conservation Commission (AOGCC) scheduled a public hearing for August 27, 2015. On July 20, 2015, the AOGCC published notice of that hearing on the State of Alaska's Online Public Notice website and on the AOGCC's website, electronically transmitted the notice to all persons on the AOGCC's email distribution list, and mailed printed copies of the Notice of Public Hearing to all persons on the AOGCC's mailing distribution list. On July 21, 2015, the notice was published in the ALASKA DISPATCH NEWS. 3. On July 23, 2015, the AOGCC published notice of that the location of the hearing had changed on the State of Alaska's Online Public Notice website and on the AOGCC's website, electronically transmitted the notice to all persons on the AOGCC's email distribution list, and mailed printed copies of the Notice of Public Hearing to all persons on the AOGCC's mailing distribution list. On July 24, 2015, the notice was published in the ALASKA DISPATCH NEWS. 4. By letter received August 19, 2015, ConocoPhillips Alaska, Inc. (CPAI) on behalf of itself and Chevron U.S.A. Inc. (Chevron) as PBU WIOs supported BPXA's request to allow the injection of CO2 for enhanced recovery purposes, but also asked for authorization to dispose of the CO2 in the event that CO2 is not shown to provide any enhanced oil recovery benefit. Area Injection Order 4G • October 15, 2015 Page 2 of 8 5. On August 25, 2015, the AOGCC received pre -filed written testimony from BPXA. 6. On August 27, 2015, the AOGCC received a letter from ExxonMobil supporting BPXA's application. 7. The hearing commenced at 9:00 AM on August 27, 2015, in the Alaska State Legislature Building, Legislative Information Office located at 716 West 4th Avenue, Anchorage, Alaska. 8. Testimony was received from representatives of BPXA, CPAI, and Mr. Tom Lakosh, a private citizen. 9. The record was held open until September 8, 2015 for responses to requests made by the AOGCC at the public hearing. 10. The AOGCC received written comments from Mr. Lakosh on August 27, 2015, requested additional information from CPAI on September 3, 2015, and requested additional information from BPXA on September 8, 2015. 11. By email sent September 4, 2015, the AOGCC requested CPAI provide further justification for its request to dispose of CO2. CPAI responded that same day. FINDINGS: 1. Operator and Owners: BPXA is the operator of the leases in the portion of the PBU within the Affected Area of this order. BPXA, ExxonMobil, CPAI, and Chevron are the WIOs, and the State of Alaska, Department of Natural Resources (DNR) is the landowner of the Affected Area, which is located within the North Slope Borough, along Alaska's northern coastline. 2. Affected Area: The Affected Area is defined in AIO 417, and it remains unchanged for this amended order. 3. AOGCC Authority: The U.S. Environmental Protection Agency (EPA) has granted the AOGCC regulatory primacy limited to underground injection control (UIC) Class II wells. 4. Source of CO2 Effluent: The proposed Alaska Liquefied Natural Gas Project (AK LNG) includes a North Slope gas treatment plant (GTP) to process produced gas from multiple fields to sales specifications prior to shipment to the proposed LNG plant in south-central Alaska. The GTP will remove significant amounts of impurities from the produced gas — primarily CO2—prior to shipment for sales. The resulting effluent stream from the GTP is expected to contain more than 99% CO2, and it will be sent back to the PBU for injection. 5. BPXA Request: BPXA requests that AIO 417 be amended to authorize the injection of the portion of the effluent stream that is sourced from fields outside of the PBU for enhanced oil recovery (EOR) purposes. AIO 417 currently authorizes injection of produced gas that originates within the PBU. 6. CPAI Request: CPAI supports BPXA's request for authorization to inject the GTP effluent stream for FOR purposes, but additionally requests authorization to dispose of the GTP effluent stream if it is determined there is no FOR benefit to injecting that effluent stream into any of the pools covered by this AIO. CPAI also requests AIO 4F be amended to permit administrative approval of future modifications. Area Injection Order 4G • • October 15, 2015 Page 3 of 8 7. FOR Potential of CO,: BPXA states that under the right conditions, mixtures of CO2 and the hydrocarbon miscible injectant already in use for FOR purposes within the PBU will be miscible with the crude oil and thus provide an FOR benefit. In the event that mixtures containing CO2 are not miscible, injecting the CO2—bearing effluent stream should improve oil recovery by maintaining reservoir pressure. 8. CO2 Disposal: According to the EPA, CO2 can be disposed of in Class II wells when those wells were previously used for a CO2 FOR injection project. Disposal of CO2 under other circumstances requires Class VI wells, which are administered by the EPA. 9. Administrative Relief: Rule 9 of AIO 4F provides for administratively amending the order if certain conditions are met, but is an older form of the rule than the AOGCC currently uses. CONCLUSIONS: 1. Amendment of AIO 417 is necessary to authorize the injection of outside substances. 2. Injection of the effluent stream from the AK LNG GTP in the oil pools covered by this order should improve recovery and minimize waste. CPAI's proposed disposal injection of CO2-bearing effluent derived from the GTP requires use of UIC Class VI wells, which are under the jurisdiction of the EPA. 4. AIO 41's administrative relief rule should be revised to be consistent with the AOGCC's current practices. NOW, THEREFORE, IT IS ORDERED: AIO 4, AIO 4A, AIO 413, AIO 4C, AIO 4D, AIO 4E, and AIO 4F and all associated administrative approvals (except AIO 004E.012, AIO 004E.0014, AIO 004E.015 (as amended), AIO 004E.016, AIO 004E.017, AIO 004E.018, AIO 004E.020, AIO 004E.022, AIO 004E.023, AIO 004E.024, AIO 004E.025, AIO 004E.028, AIO 004E.029, AIO 004E.030, AIO 004E.032, AIO 004E.033, AIO 004E.035, AIO 004E.036, AIO 004E.037, AIO 004E 038, AIO 004E.039, AIO 004E.040, AIO 004E.041, AIO 004F.001, AIO 00417.002, AIO 00417.003, AIO 004F.004, and AIO 00417.005, which remain in effect) are hereby revoked and replaced by this order. All information related to AIO 4, AIO 4A, AIO 413, AIO 4C, AIO 4D, AIO 4E and AIO 4F is hereby incorporated by reference into the record for this order. The following rules, in addition to the statewide requirements under 20 AAC 25 (to the extent not superseded by these rules), govern Class II injection operations in the affected area described below: Area Injection Order 4G • October 15, 2015 Page 4 of 8 Affected Area: Umiat Meridian Township Range Section T13N R14E Section 26: S 1/2 Section 27: s 1/2, NW 1/4 Protracted, All Tide and Submerged Lands Shoreward of the Line Fixed by Coordinates Found in Exhibit A of the Final decree, U.S. v. Alaska, No. 84 Original Section 28: Protracted, All Tide and Submerged Lands, Excluding State Oil and Gas Lease ADL 312809 Section 33: Protracted, All Tide and Submerged Lands, Excluding State Oil and Gas Lease ADL 312809 and ADL365548 Section 34: Protracted, All Tide and Submerged Lands, Excluding State Oil and Gas Lease ADL 365548 Section 35: Protracted, All Tide and Submerged Lands, Excluding State Oil and Gas Lease ADL365548 T12N R14E Sections 3, 4, 9, 10, 13, 14, 15, 16, Section 17:NE1/4,N1/2SE1/4,E%2E1/2NW1/4,E1/2NE1/4SW1/4, Section 21: N 1/2 NE 1/4, Sections 22, 23, 24, 25, 26, 35, and 36. T12N R15E Section 16: SW 1/4 Section 17: S 1/2 Sections 18, 19, 20, 21, 22, 23, 24, 25, 26, 27, 28, 29, 30, 31, 32, 33, 34, 35, and 36. T12N R16E Sections 28, 29, 30, 31, 32, 33, and Section 34: W %2 NW 1/4, SW 1/4, and SW 1/4 SE 1/4 T11N R14E Sections 1, 2, 9, 10, 11, 12, 13, 14, 15, 16, 21, 22, 23, 24, 25, 26, 27, 28, 33, 34, 35, and 36. T11N R15E All T11N R16E Section 2: SW 1/4 NW 1/4, SW 1/4, S 1/2 SE 1/4, Sections 3, 4, 5, 6, 7, 8, 9, 10, 11, Section 12: NW 1/4, S 1/2 NE 1/4, SE 1/4, and SW 1/4 Sections 13, 14, 15, 16, 17, 18, 19, 20, 21, 28, 29, 30, 31, 32, and 33. T10N R14E Sections 1, 2, 3, 4, 9, 10, 11, 12, 13, 14, 15, 16, 21, 22, 23, 24, 25, 26, 27, 28, and 36. T10N R15E All TION R16E Sections 4, 5, 6, 7, 8, 9, 16, 17, 18, 19, 20, 29, 30, and 31. Those Lands in Block 605 lying northerly of the north boundary of Section 3, T12N, R14E, UM, AK (identical with line 4-5 on block 605) and lying easterly of the west boundary of sections 2 and 11, T12N, R14E, UM, AK (identical with line 5-6 on Block 605) and lying northerly of the south boundary of Section 11 and 12, T12N, RI4E, UM, AK, and lying northerly of the south boundary of Section 7, T12N, R15E, UM, AK (identical with line 6-7 on block 605), within the offshore three-mile arc lines listed as State Area on the "Supplemental Official O.C.S. Block Diagram," approved 12/9/79, containing 1457.32 hectares. Area Injection Order 4G • • October 15, 2015 Page 5 of 8 Rule 1 Authorized Injection Strata and Fluids for Enhanced Recovery (Revised this order) Within the affected area and the following strata: The Prudhoe Oil Pool strata defined as (i) the accumulations of oil that are common to and that correlate with the accumulations found in the Atlantic Richfield - Humble Prudhoe Bay State No. 1 well between the measured depths of 8,110 feet and 8,680 feet, and (ii) the accumulation of oil that is common to and correlates with the interval from 9,638 to 9,719 measured feet on the Borehole Compensated Sonic Log, Run 2, dated September 28, 1975, in the Atlantic Richfield -Exxon NGI No. 1 well, and that is in hydraulic communication with the gas cap of the former accumulations in the Sag River Formation. The latter accumulation is found within the following area: Umiat Meridian. T11N R14E: Sections: 1, 2, 11(N/2 and SE/4), 12, 13, 14(E/2), 23(NE/4), 24, 25(N/2); T11N R15E: Sections: 6, 7, 8, 17, 18, 19, 20, 29(N/2), 30(N/2); T12N R14E: Sections 35, 36 The Put River Oil Pool strata are defined as the sandstone reservoirs within the Southern, Central and Western lobes of the Put River Sandstone Member (PRS) of the Kalubik Formation that correlate with the interval 9,638 to 9,719 measured feet on the Borehole Compensated Sonic Log, Run 2--dated September 28, 1975--in the Atlantic Richfield - Exxon NGI No. 1 well, but excluding the PRS Northern Lobe reservoirs that are in pressure communication with the Prudhoe Oil Pool gas cap in the Sag River Formation. The Put River Oil Pool is found within the following area: Umiat Meridian. Tl1N R14E Sections: 3, 4, 9, 10, 11(SW/4), 14(W/2), 15, 16, 21, 22, 23(W/2 and SE/4), 25(S/2), 26, 27, 28, 33, 34, 35, 36; T11N R15E Sections: 29(S/2), 30(S/2), 31, 32; T10N R14E Sections: 1, 2, 3, 11, 12, 13, 14; TION R15E Sections: 5, 6, 7, 8, 17, 18 The Lisburne Oil Pool strata correlate with and are common to the formations found in the ARCO Prudhoe Bay State No. 1 well between the measured depths of 8,790-10,440. The Pt. McIntyre Oil Pool strata correlate with and are common to the formations found in the Pt. McIntyre No. 11 well between the measured depths of 9,908-10,665 feet. The West Beach Oil Pool strata correlate with and are common to the formations found in the West Beach No. 4 well between the measured depths of 14,458-14,781 feet. The Stump Island Oil Pool enhanced recovery plans will be evaluated on a well -by -well basis in conjunction with Pt. McIntyre Oil Pool development. The following fluids may be injected for pressure maintenance and enhanced recovery purposes: (a) Produced water and gas from PBU processing facilities; Area Injection Order 4G • October 15, 2015 Page 6 of 8 (b) CO2 and other GTP effluent gases from sources within or outside the Prudhoe Bay Unit; (c) Enriched hydrocarbon gas; (d) Non -hazardous water and water based fluids — (specifically seawater, source water, freshwater, domestic wastewater, equipment washwater, sump fluids, hydrotest fluids, firewater, and water with trace chemicals, and other water based fluids with a pH greater than 2 and less than 12.5 and flashpoint greater than 140 degrees F); (e) Fluids introduced to production facilities for the purpose of oil production, plant operations, plant/piping integrity or well maintenance that become entrained in the produced water stream after oil, gas, and water separation in the facility. Specifically: i. Freeze protection fluids; ii. Fluids in mixtures of oil sent for hydrocarbon recycle; iii. Corrosion/scale inhibitor fluids; iv. Anti-foams/emulsion breakers; V. Glycols; vi. Radioactive tracer survey fluids (f) Non -hazardous glycols and glycol mixtures; (g) Fluids that are used for their intended purpose within the oil production process. Specifically: i. Scavengers; ii. Biocides (h) Fluids to monitor or enhance reservoir performance. Specifically: i. Tracer survey fluids; ii. Well stimulation fluids; iii. Reservoir profile modification fluids. Rule 2 Authorized Injection Strata for Disposal (Source: AIO 40 Within the affected area, Class II waste fluids may be disposed by injection into strata defined as those which correlate with and are common to the strata found in the ARCO Sag River State No. 1 well between the measured depths of 3,607-6,750 feet. Class II slurry injection from the Grind and Inject processes may be disposed into strata defined as those which correlate with and are common to the strata found in the ARCO Sag River State No. 1 well between the measured depths of 4,270-6,750 feet. Rule 3 Fluid Iniection Wells (Source: AIO 40 The injection of fluids must be conducted: 1) through a new well that has been permitted for drilling as a service well for injection in conformance with 20 AAC 25.005; 2) through an existing well that has been approved for conversion to a service well for injection in conformance with 20 AAC 25.280; or 3) through a well that existed as a service well for injection purposes on the date of this order. Rule 4 Monitoring the Tubing -Casing Annulus Pressure Variations (Source: AI04D) The tubing and casing annuli pressures of each injection well must be monitored at least daily, except if prevented by extreme weather condition, emergency situations, or similar unavoidable Area Injection Order 4G • • October 15, 2015 Page 7 of 8 circumstances. Monitoring results shall be documented and made available for AOGCC inspection. Rule 5 Reporting the Tubing -Casing Annulus Pressure Variations (Revoked: AI04D) Rule 6 Demonstration of Tubing/Casing Annulus Mechanical Integrity (Source: AI04E) The mechanical integrity of an injection well must be demonstrated before injection begins, and before returning a well to service following a workover affecting mechanical integrity. A AOGCC-witnessed mechanical integrity test must be performed after injection is commenced for the first time in a well, to be scheduled when injection conditions (temperature, pressure, rate, etc.) have stabilized. Subsequent tests must be performed at least once every four years thereafter (except at least once every two years in the case of a slurry injection well). The AOGCC must be notified at least 24 hours in advance to enable a representative to witness mechanical integrity tests. Unless an alternate means is approved by the AOGCC, 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. Results of mechanical integrity tests must be readily available for AOGCC inspection. Rule 7 Well Integrity Failure (Source: AI04E) 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 notify the AOGCC by the next business day and submit a plan of corrective action on a Form 10-403 for AOGCC 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. Rule 8 Plugging and Abandonment of Injection Wells (Source: AIO 4C) An injection well located within the affected area must not be plugged or abandoned unless approved by the AOGCC. Rule 9 Administrative Action (Revised this order) Upon proper application, or its own motion, and unless notice and public hearing are otherwise required, the AOGCC may administratively waive the requirements of any rule stated herein or administratively amend this order 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. Rule 10 Surveillance (Source: AIO 4C and AIO 4C.001) For slurry injection wells, a baseline temperature survey from surface to total depth, initial step rate test to pressures equal or exceeding maximum injection pressure and pressure falloff are required prior to sustained disposal injection. Regular fill depth tags are required at least once annually or as warranted following consultation with the AOGCC. Operating parameters including disposal rate, disposal pressure, annulus pressures and volume of slurry pumped must be monitored and reported according to the requirements of 20 AAC 25.432. Area Injection Order 4G October 15, 2015 Page 8 of 8 Also for slurry injection wells, an annual performance report will be required including rate and pressure performance, surveillance logging, fill depth, survey results, and volumetric analysis of the disposal storage volume, estimate of fracture growth, if any, and updates of operational plans. Reports shall cover the time period of October 1st through September 30th and submission must be on or before November 15th Rule 11 Notification (Revised this order) The operator must notify the AOGCC if it learns of any improper Class II injection. Compliance with terms and conditions set forth herein does not relieve the operator of any additional notification requirements of any other State or Federal agency. Such notification remains the sole responsibility. DONE at Anchorage, Alaska and Cathy �`. Foerster 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. 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 1 (DOA) Sent: Friday, October 16, 2015 9:30 AM To: AKDCWellIntegrityCoordinator, Alex Demarban; Alexander Bridge; Allen Huckabay; Andrew VanderJack; Anna Raff; Barbara F Fullmer, bbritch; bbohrer@ap.org; Bob Shavelson; Brian Havelock, Bruce Webb; Burdick, John D (DNR); 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, Jacki Rose; Jdarlington oarlington@gmail.com); Jeanne McPherren; Williams, Jennifer L (LAW); Jerry Hodgden; Jerry McCutcheon; Solnick, Jessica D (LAW); Jim Watt; Jim White; Joe Lastufka; Joe Nicks; John Adams; Easton, John R (DNR); Jon Goltz, Juanita Lovett; Judy Stanek; Houle, Julie (DNR); Julie Little; Kari Moriarty; Kazeem Adegbola; Keith Wiles; Kelly Sperback; 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 Landt; Mark Wedman; Kremer, Marguerite C (DNR); Mary Cocklan-Vendl; Michael Calkins; Michael Duncan; Michael Moora; Mike Bill; mike@kbbi.org; Mikel Schultz; M1 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; Robert Brelsford; Ryan Tunseth; Sara Leverette; Scott Griffith; Shannon Donnelly; Sharmaine Copeland; Sharon Yarawsky; Shellenbaum, Diane P (DNR); Smart Energy Universe; Smith, Kyle S (DNR); Sondra Stewman; Stephanie Klemmer; Moothart, Steve R (DNR); Suzanne Gibson; sheffield@aoga.org; Tania Ramos; Ted Kramer, Davidson, Temple (DNR); Terence Dalton; Teresa Imm; Thor Cutler; Tim Mayers; Todd Durkee; trmjrl; Tyler Senden; Vicki Irwin; Vinnie Catalano; Aaron Gluzman; Aaron Sorrell; Ajibola Adeyeye; Alan Dennis; Andrew Cater, Anne Hillman; Brian Gross; Bruce Williams; Bruno, Jeff J (DNR); Caroline Bajsarowicz; Casey Sullivan; Diane Richmond; Don Shaw, Donna Vukich; Eric Lidji; Gary Orr, Smith, Graham O (PCO); Greg Mattson; Dickenson, Hak K (DNR); Heusser, Heather A (DNR); Holly Pearen; Hyun, lames J (DNR); Jason Bergerson; 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; Franger, lames M (DNR); Morgan, Kirk A (DNR); Pat Galvin; Bettis, Patricia K (DOA); Pete Dickinson; Peter Contreras; Richard Garrard; Robert Province; Ryan Daniel; Sandra Lemke; Sarah Baker, Peterson, Shaun (DNR); Pollard, Susan R (LAW); Talib Syed; Terence Dalton; Tina Grovier (tmgrovier@stoel.com); Todd, Richard J (LAW); Tostevin, Breck C (LAW); Wayne Wooster, William Van Dyke; Ballantine, Tab A (LAW); Bender, Makana K (DOA); Bixby, Brian D (DOA); Brooks, Phoebe L (DOA); Carlisle, Samantha J (DOA); Colombie, Jody J (DOA); Cook, Guy D (DOA); Crisp, John H (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); Loepp, Victoria T (DOA); Mumm, Joseph (DOA sponsored); Noble, Robert C (DOA); Paladijczuk, Tracie L (DOA); Pasqual, Maria (DOA); Regg, lames 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) Subject: Area Injection Order 4G (PBU) Attachments: aiopg.pdf • Please replace the version of AIO 4G sent yesterday with the one I have attached here. There were two page 8's, no other information in AIO 4G has changed. Thank you, Samantha CarCisCe Executive Secretary 11 .Alaska Oil and Gas Conservation Commission 333 West 711 .Avenue .Anchorage, AC 99501 (907) 793-1223 (yhone) (907) 276-7542 (fax) CONFIDENTWITY 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.Qov. 0 • Singh, Angela K (DOA) From: Carlisle, Samantha J (DOA) Sent: Thursday, October 15, 2015 3:32 PM To: AKDCWellIntegrityCoordinator, Alex Demarban; Alexander Bridge; Allen Huckabay; Andrew VanderJack; Anna Raff; Barbara F Fullmer, bbritch; bbohrer@ap.org; Bob Shavelson; Brian Havelock, Bruce Webb; Burdick, John D (DNR); 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, Jacki Rose; Jdarlington Oarlington@gmail.com); Jeanne McPherren; Williams, Jennifer L (LAW); Jerry Hodgden; Jerry McCutcheon; Solnick, Jessica D (LAW); Jim Watt; Jim White; Joe Lastufka; Joe Nicks; John Adams; Easton, John R (DNR); Jon Goltz; Juanita Lovett, Judy Stanek, Houle, Julie (DNR); Julie Little; Kari Moriarty; Kazeem Adegbola; Keith Wiles; Kelly Sperback; 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 Landt; Mark Wedman; Kremer, Marguerite C (DNR); Mary Cocklan-Vendl; Michael Calkins; Michael Duncan; Michael Moora; Mike Bill; mike@kbbi.org; Mikel Schultz, 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; Robert Brelsford; Ryan Tunseth; Sara Leverette; Scott Griffith; Shannon Donnelly, Sharmaine Copeland; Sharon Yarawsky; Shellenbaum, Diane P (DNR); Smart Energy Universe; Smith, Kyle S (DNR); Sondra Stewman; Stephanie Klemmer; Moothart, Steve R (DNR); Suzanne Gibson; sheffield@aoga.org; Tania Ramos; Ted Kramer, Davidson, Temple (DNR); Terence Dalton; Teresa Imm; Terry Templeman; Thor Cutler, Tim Mayers; Todd Durkee; trmjrl; Tyler Senden; Vicki Irwin; Vinnie Catalano; Aaron Gluzman; Aaron Sorrell; Ajibola Adeyeye; Alan Dennis; Andrew Cater, Anne Hillman; Brian Gross; Bruce Williams; Bruno, Jeff J (DNR); Caroline Bajsarowicz; Casey Sullivan; Diane Richmond; Don Shaw; Donna Vukich; Eric Lidji; Gary Orr; Smith, Graham O (PCO); Greg Mattson; Dickenson, Hak K (DNR); Heusser, Heather A (DNR); Holly Pearen; Hyun, James J (DNR); Jason Bergerson; 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; Franger, James M (DNR); Morgan, Kirk A (DNR); Pat Galvin; Bettis, Patricia K (DOA); Pete Dickinson; Peter Contreras; Richard Garrard; Robert Province; Ryan Daniel; Sandra Lemke; Sarah Baker; Peterson, Shaun (DNR); Pollard, Susan R (LAW); Talib Syed; Terence Dalton; Tina Grovier (tmgrovier@stoel.com); Todd, Richard J (LAW); Tostevin, Breck C (LAW); Wayne Wooster, William Van Dyke; Ballantine, Tab A (LAW); Bender, Makana K (DOA); Bixby, Brian D (DOA); Brooks, Phoebe L (DOA); Carlisle, Samantha J (DOA); Colombie, Jody J (DOA); Cook, Guy D (DOA); Crisp, John H (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); Loepp, Victoria T (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); Wallace, Chris D (DOA) Subject: Area Injection Order 3B and 4G (Prudhoe Bay Unit) Attachments: Abl.pdf, aio4g.pdf • Please see attached. Samantha CarCisCe Executive Secretary II .ACaska OiCandGas Conservation Commission 333 West 7" .Avenue .Anchorage, AX 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.Carhsle@alaska.gov. James Gibbs Jack Hakkila Bernie Karl P.O. Box 1597 P.O. Box 190083 K&K 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 Dave P. Lachance Richard Wagner Darwin Waldsmith Vice President, Reservoir Development P.O. Box 60868 P.O. Box 39309 BP Exploration (Alaska), Inc. Fairbanks, AK 99706 Ninilchik, AK 99639 P.O. Box 196612 Anchorage, AK 99508 r&z;le&- OC.�obac �ct�2ol5 Angela K. Singh THE STATE °fALASKA GOVERNOR BILL WALKER Alaska Oil and Gas Conservation Commission ADMINISTRATIVE APPROVAL AREA INJECTION ORDER NO.4G.001 Mr. Ryan Daniel Well Integrity Engineering Team Leader BP Exploration (Alaska), Inc. P.O. Box 196612 Anchorage, AK 99519-6612 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.alaska.gov Re: Docket Number: AIO-16-030 Request for administrative approval to allow well 09-25 (PTD 1840280) to be online in water only injection service with known inner annulus (IA) repressurization. Prudhoe Bay Unit (PBU) 09-25 (PTD 1840280) Prudhoe Bay Field Prudhoe Oil Pool Dear Mr. Daniel: By letter dated July 27, 2016, BP Exploration (Alaska), Inc. (BPXA) requested administrative approval to continue water only injection in the subject well. In accordance with Rule 9 of Area Injection Order (AIO) 4G.000, the Alaska Oil and Gas Conservation Commission (AOGCC) hereby GRANTS BPXA's request for administrative approval to continue water only injection in the subject well. BPXA reported a potential Inner Annulus repressurization to AOGCC and initiated additional diagnostics and monitoring. BPXA completed a passing non -state witnessed Mechanical Integrity Test of the Inner Annulus (MITIA) on June 24, 2016 which indicates that 09-25 exhibits at least two competent barriers to the release of well pressure. The well has a recorded IA build up rate of 10 psi/day while on water service and AOGCC finds that BPXA is able to manage the IA pressure with periodic pressure bleeds. Accordingly, the AOGCC believes that the well's condition does not compromise overall well integrity so as to threaten human safety or the environment A10 4G.001 August 2, 2016 Page 2 of 2 AOGCC's approval to continue water injection only in PBU 09-25 following: 1. BPXA shall record wellhead pressures and injection rate daily; 2. BPXA shall submit to the AOGCC a monthly report of well 4 5 Cel is conditioned upon the pressures, injection rates, and pressure bleeds for all annuli. Bleeds to be flagged on the report; BPXA shall perform a mechanical integrity test of the inner annulus (MITIA) every 2 years to the maximum anticipated injection pressure; BPXA shall limit the well's IA operating pressure to 2000 psi; BPXA 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 shall be required to restart injection; and 7. The MIT anniversary date is June 24, 2016. DONE at Anchorage, Alaska and dated August 2, 2016. �4 z4te� Cathy . Foerster eanielT. Se ount, Jr. Chair, Commissioner Commissioner RECONSIDERATION AND APPEAL NOTICE 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. 'hat 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: Wednesday, August 03, 2016 12:23 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); French, Hollis (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; Andrew VanderJack; Ann Danielson; Anna Raff; Barbara F Fullmer, bbritch; bbohrer@ap.org; Bill Bredar; Bob Shavelson; Brian Havelock, Bruce Webb; Caleb Conrad; Candi English; Cocklan-Vendl, Mary E; Colleen Miller, Crandall, Krissell; D Lawrence; Dale Hoffman; Dave Harbour, David Boelens; David Duffy, David House; David McCaleb; David Tetta; ddonkel@cfl.rr.com; Dean Gallegos; DNROG Units (DNR sponsored); Donna Ambruz; Ed Jones; Elowe, Kristin; Evan Osborne; Evans, John R (LDZX); Frank Molli; Gary Oskolkosf, George Pollock; Gordon Pospisil; Greeley, Destin M (DOR); Gregg Nady; Gretchen Stoddard; 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; Burdick, John D (DNR); Easton, John R (DNR); Jon Goltz; Juanita Lovett; Judy Stanek; Julie Little; 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); Mealear Tauch; Michael Bill; Michael Calkins; Michael Moora; M1 Loveland; mkm7200; 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; Randy L. Skillern; Delbridge, Rena E (LAS); 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); Stephanie Klemmer; Stephen Hennigan; Sternicki, Oliver R, 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; Umekwe, Maduabuchi P (DNR); Vicki Irwin; Vinnie Catalano; Aaron Gluzman; Aaron Sorrell; Ajibola Adeyeye; Alan Dennis; Assmann, Aaron A; Bajsarowicz, Caroline J; Brian Gross; Bruce Williams; Bruno, Jeff J (DNR); Casey Sullivan; Don Shaw; Eric Lidji; Garrett Haag; Smith, Graham O (DNR); Dickenson, Hak K (DNR); Heusser, Heather A (DNR); Holly Pearen; Jamie M. Long; Jason Bergerson; 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 Attachments: aio4G.001.pdf, aio3B.002.pdf, aio3B.003.pdf Please see attached. Docket Number: AIO-16-029 Request for administrative approval to allow well S-41A (PTD 2101010) to be online in water only injection service with known inner annulus (IA) repressurization. Prudhoe Bay Unit (PBU) S-41A (PTD 2101010) Prudhoe Bay Field Prudhoe Oil Pool Docket Number: AIO-16-030 Request for administrative approval to allow well 09-25 (PTD 1840280) to be online in water only injection service with known inner annulus (IA) repressurization. Prudhoe Bay Unit (PBU) 09-25 (PTD 1840280) Prudhoe Bay Field Prudhoe Oil Pool Docket Number: AIO-16-031 Request for administrative approval to allow well X-24A (PTD 1991250) to be online in water only injection service with known inner annulus (IA) repressurization. Prudhoe Bay Unit (PBU) X-24A (PTD 1991250) Prudhoe Bay Field Prudhoe Oil Pool jocfy J. Co(onlbie .AUGCC special -Assistant .Alaska Oiland Gas Conservation Commission hest 7" .Avenue _Aiwhorage, .Alaska 995oi of -Ice: i907) 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. Jack Hakkila Bernie Karl P.O. Box 190083 K&K Recycling Inc. Anchorage, AK 99519 P.O. Box 58055 Fairbanks, AK 99711 Penny Vadla George Vaught, Jr. 399 W. Riverview Ave. P.O. Box 13557 Soldotna, AK 99669-7714 Denver, CO 80201-3557 Mr. Ryan Daniel Richard Wagner Well Integrity Engineering Team Leader P.O. Box 60868 BP Exploration (Alaska), Inc. Fairbanks, AK 99706 P.O. Box 196612 Anchorage, AK 99519-6612 Gordon Severson 3201 Westmar Cir. Anchorage, AK 99508-4336 Darwin Waldsmith P.O. Box 39309 Ninilchik, AK 99639 W1 &'C 6 ci Angela K. Singh THE STATE °fALASKA GOVERNOR BILL WALKER Alaska Oil and Gas Conservation Commission ADMINISTRATIVE APPROVAL AREA INJECTION ORDER NO.4G.002 Mr. Ryan Daniel Well Integrity Engineering Team Lead BP Exploration (Alaska), Inc. P.O. Box 196612 Anchorage, AK 99519-6612 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.alaska.gov Re: Docket Number: AIO-16-033 Request for administrative approval to allow well P2-09 (PTD 1980660) to be online in water alternating gas (WAG) injection service with a shallow packer depth (cemented inner annulus). Prudhoe Bay Unit (PBU) PTM P2-09 (PTD 1980660) Prudhoe Bay Field Prudhoe Bay Pt McIntyre Oil Pool Dear Mr. Daniel: By letter dated August 8, 2016, BP Exploration (Alaska), Inc. (BPXA) requested administrative approval to continue WAG injection in the subject well. In accordance with Rule 9 of Area Injection Order (AIO) 4G.000, the Alaska Oil and Gas Conservation Commission (AOGCC) hereby GRANTS BPXA's request for administrative approval to continue WAG injection in the subject well. BPXA reported a potential production casing leak at 6410 ft. BPXA performed diagnostics and performed several cement squeezes of the inner annulus under Sundry 315-598 and 316-203 in May 2016. The inner annulus cement top was estimated at 5501 ft, with the upper injection perforation located at 12,116 ft. BPXA performed a passing waterflow log on June 23, 2016 which indicates no upward movement of fluid in the IA across the cemented interval. However, since the inner annulus is cemented leaving only approximately 5501 ft of inner annulus available for monitoring, this annulus does not meet the requirement that an injection well be equipped with a packer set not more than 200' measured depth above the top of the perforations. If injection does not occur into, through, or above freshwater, 20 AAC 25.450 authorizes less stringent well construction and integrity requirements if AOGCC determines the reduction in requirements will not result in an increased risk of movement of fluids into freshwater. BPXA completed a passing non -state witnessed Mechanical Integrity Test of the Inner Annulus (MITIA) on May 15, 2016 and a passing non -state witnessed Mechanical Integrity Test of the AIO 4G.002 September 1, 2016 Page 2 of 2 Tubing (MITT) on May 24, 2016 which indicates that P2-09 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 WAG injection in PBU PTM P2-09 is conditioned upon the following: 1. BPXA shall record wellhead pressures and injection rate daily; 2. BPXA 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. BPXA shall perform a mechanical integrity test of the inner annulus every 2 years to the maximum anticipated injection pressure; 4. BPXA shall perform a mechanical integrity test of the tubing every 2 years to the maximum anticipated injection pressure; 5. BPXA shall limit the well's IA operating pressure to 2500 psi; 6. BPXA shall immediately shut in the well and notify the AOGCC if there is any change in the well's mechanical condition; 7. After well shut in due to a change in the well's mechanical condition, AOGCC approval shall be required to restart injection; and 8. The MIT anniversary date is May 15, 2016. DONE at Anchorage, Alaska and dated September 1, 2016. 44 Cathy/P. Foerster Daniel T. Seamount, Jr. Chair, Commissioner 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. Colombie, Jody J (DOA) From: Colombie, Jody J (DOA) Sent: Thursday, September 01, 2016 11:28 AM 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); French, Hollis (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); 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; Bill Bredar; Bob Shavelson; Brian Havelock; Bruce Webb; Caleb Conrad; Candi English; Cocklan-Vendl, Mary E; Colleen Miller; Crandall, Krissell; D Lawrence; Dale Hoffman; Dave Harbour, David Boelens; David Duffy, David House; David McCaleb; David Tetta; ddonkel@cfl.rr.com; Dean Gallegos; DNROG Units (DNR sponsored); Donna Ambruz; Ed Jones; Elizabeth Harball; Elowe, Kristin; Evan Osborne; Evans, John R (LDZX); Gary Oskolkosf, George Pollock; Gordon Pospisil; Greeley, Destin M (DOR); Gregg Nady; Gretchen Stoddard; 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; Burdick, John D (DNR); Easton, John R (DNR); Jon Goltz; Juanita Lovett; Judy Stanek; Julie Little; Kari Moriarty; Kasper Kowalewski; 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); Mealear Tauch; Michael Bill; Michael Calkins; Michael Moora; MJ Loveland; mkm7200; 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; Delbridge, Rena E (LAS); 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); Stephanie Klemmer; Stephen Hennigan; Sternicki, Oliver R; Moothart, Steve R (DNR); Steve Quinn; Suzanne Gibson; Sheffield@aoga.org; Ted Kramer; Davidson, Temple (DNR); Teresa Imm; Thor Cutler; Tim Jones; Tim Mayers; Todd Durkee; trmjrl; Tyler Senden; Umekwe, Maduabuchi P (DNR); Vinnie Catalano; Weston Nash; Whitney Pettus; Aaron Gluzman; Aaron Sorrell; Ajibola Adeyeye; Alan Dennis; Assmann, Aaron A; Bajsarowicz, Caroline J; Brian Gross; Bruce Williams; Bruno, Jeff J (DNR); Casey Sullivan; Don Shaw; Eric Lidji; Garrett Haag; Smith, Graham O (DNR); Dickenson, Hak K (DNR); Heusser, Heather A (DNR); Holly Pearen; Jamie M. Long; Jason Bergerson; 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: Administrative Approvals Attachments: aio4G.002.pdf, aio5.028.pdf, aio2c.022 cancellation.pdf Please see attached. Re: Docket Number: AIO-16-036 Request to cancel Area Injection Order (AIO) 2C.022 Kuparuk River Unit (KRU) 30-06 (PTD 1880600) Kuparuk River Field Kuparuk River Oil Pool Re: Docket Number: AIO-16-033 Request for administrative approval to allow well P2-09 (PTD 1980660) to be online in water alternating gas (WAG) injection service with a shallow packer depth (cemented inner annulus). Prudhoe Bay Unit (PBU) PTM P2-09 (PTD 1980660) Prudhoe Bay Field Prudhoe Bay Pt McIntyre Oil Pool Re: Docket Number: AIO-16-035 Request for administrative approval to allow well G-13 (PTD 1680570) to be online in water only injection service with known tubing by inner annulus communication. Trading Bay Unit (TBU) G-13 (PTD 1680570) McArthur River Field Hemlock and Middle Kenai G Oil Pools Jotfy J. Co(omhie 'A0(7CC specia (-Assistant Alaska OiL anc((jas Conservation Commission 333 1NeSt 7'r' Avenue _Anctiorage, .Alaska 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.gov. Jack Hakkila Bernie Karl P.O. Box 190083 K&K Recycling Inc. Anchorage, AK 99519 P.O. Box 58055 Fairbanks, AK 99711 Penny Vadla George Vaught, Jr. 399 W. Riverview Ave. P.O. Box 13557 Soldotna, AK 99669-7714 Denver, CO 80201-3557 Mr. Ryan Daniel Richard Wagner Well Integrity Engineering Team Lead P.O. Box 60868 BP Exploration (Alaska), Inc. Fairbanks, AK 99706 P.O. Box 196612 Anchorage, AK 99519-6612 Gordon Severson 3201 Westmar Cir. Anchorage, AK 99508-4336 Darwin Waldsmith P.O. Box 39309 Ninilchik, AK 99639 fv�� CL S CAI? �-e �b4%( -7, 2� u4- Angela K. Singh THE STATE °fALASKA GOVERNOR BILL WALKER Alaska Oil and Gas Conservation Commission ADMINISTRATIVE APPROVAL AREA INJECTION ORDER NO. 4G.003 Mr. Ryan Daniel Well Integrity Engineering Team Leader BP Exploration (Alaska), Inc. P.O. Box 196612 Anchorage, AK 99519-6612 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.alaska.gov Re: Docket Number: AIO-16-037 Request for administrative approval to allow well 13-31A (PTD 2051600) to be online in water only injection service with known inner annulus (IA) repressurization. Prudhoe Bay Unit (PBU) 13-31A (PTD 2051600) Prudhoe Bay Field Prudhoe Oil Pool Dear Mr. Daniel: By letter dated August 22, 2016, BP Exploration (Alaska), Inc. (BPXA) requested administrative approval to continue water only injection in the subject well. In accordance with Rule 9 of Area Injection Order (AIO) 4G.000, the Alaska Oil and Gas Conservation Commission (AOGCC) hereby GRANTS BPXA's request for administrative approval to continue water only injection in the subject well. BPXA reported a potential Inner Annulus repressurization to AOGCC and initiated additional diagnostics and monitoring. BPXA completed a passing non -state witnessed Mechanical Integrity Test of the Inner Annulus (MITIA) on August 13, 2016 which indicates that 13-31A exhibits at least two competent barriers to the release of well pressure. The well has a recorded IA build up rate of 15 psi/day while on gas injection and AOGCC finds that BPXA is able to manage the IA pressure with periodic pressure bleeds. 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 4G.003 September 6, 2016 Page 2 of 2 AOGCC's approval to continue water injection only in PBU 13-31A is conditioned upon the following: 1. BPXA shall record wellhead pressures and injection rate daily; 2. BPXA 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. BPXA shall perform a mechanical integrity test of the inner annulus (MITIA) every 2 E on 7. years to the maximum anticipated injection pressure; BPXA shall limit the well's IA operating pressure to 2000 psi; BPXA 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 MIT anniversary date is August 13, 2016. DONE at Anchorage, Alaska and dated September 1, 2016. Cathy/P. Foerster Daniel T. Seamount, Jr. Chair, Commissioner Commissioner RECONSIDERATION AND APPEAL 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. Colombie, Jody J (DOA) From: Colombie, Jody J (DOA) Sent: Tuesday, September 06, 2016 3:39 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); French, Hollis (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); 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; Bill Bredar; Bob Shavelson; Brian Havelock; Bruce Webb; Caleb Conrad; Candi English; Cocklan-Vendl, Mary E; Colleen Miller, Crandall, Krissell; D Lawrence; Dale Hoffman; Dave Harbour; David Boelens; David Duffy; David House; David McCaleb; David Tetta; ddonkel@cfl.rr.com; Dean Gallegos; DNROG Units (DNR sponsored); Donna Ambruz; Ed Jones; Elizabeth Harball; Elowe, Kristin; Evan Osborne; Evans, John R (LDZX); Gary Oskolkosf, George Pollock; Gordon Pospisil; Greeley, Destin M (DOR); Gregg Nady; Gretchen Stoddard; 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; Burdick, John D (DNR); Easton, John R (DNR); Jon Goltz; Juanita Lovett; Judy Stanek, Julie Little; Kari Moriarty, Kasper Kowalewski; 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); Mealear Tauch; Michael Bill; Michael Calkins; Michael Moora; MJ Loveland; mkm7200; 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; Delbridge, Rena E (LAS); 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); Stephanie Klemmer; Stephen Hennigan; Sternicki, Oliver R; Moothart, Steve R (DNR); Steve Quinn; Suzanne Gibson; sheffield@aoga.org; Ted Kramer, Davidson, Temple (DNR); Teresa Imm; Thor Cutler; Tim Jones; Tim Mayers; Todd Durkee; trmjrl; Tyler Senden; Umekwe, Maduabuchi P (DNR); Vinnie Catalano; Weston Nash; Whitney Pettus; Aaron Gluzman; Aaron Sorrell; Ajibola Adeyeye; Alan Dennis; Assmann, Aaron A; Bajsarowicz, Caroline J; Brian Gross; Bruce Williams; Bruno, Jeff J (DNR); Casey Sullivan; Don Shaw; Eric Lidji; Garrett Haag; Smith, Graham O (DNR); Dickenson, Hak K (DNR); Heusser, Heather A (DNR); Holly Pearen; Jamie M. Long; Jason Bergerson; 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: aio4g-003 Attachments: aio4G.003.pdf Please see attached. Docket Number: AIO-16-037 Request for administrative approval to allow well 13-31A (PTD 2051600) to be online in water only injection service with known inner annulus (IA) repressurization. Prudhoe Bay Unit (PBU) 13-31A (PTD 2051600) Prudhoe Bay Field Prudhoe Oil Pool Jody J. Cotombie AOGCC SpeciatAssistant Alaska Oitand(jas Conservation Commission 333 West 7" Avenue Anctiorage, Alaska. 99501 OTice: (907) 7.93-1221 .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.gov. Jack Hakkila Bernie Karl P.O. Box 190083 K&K Recycling Inc. Anchorage, AK 99519 P.O. Box 58055 Fairbanks, AK 99711 Penny Vadla George Vaught, Jr. 399 W. Riverview Ave. P.O. Box 13557 Soldotna, AK 99669-7714 Denver, CO 80201-3557 Mr. Ryan Daniel Richard Wagner Well Integrity Engineering Team Leader P.O. Box 60868 BP Exploration (Alaska), Inc. Fairbanks, AK 99706 P.O. Box 196612 Anchorage, AK 99519-6612 Gordon Severson 3201 Westmar Cir. Anchorage, AK 99508-4336 Darwin Waldsmith P.O. Box 39309 Ninilchik, AK 99639 Angela K. Singh THE STATE °fALASKA GOVERNOR MIKE DUNLEAVY Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 w .aogcc.alaska.gov ADMINISTRATIVE APPROVAL AREA INJECTION ORDER NO. 4G.004 CANCELLATION Mr. Ryan Daniel Well Integrity Engineering Team Leader BP Exploration (Alaska), Inc. P.O. Box 196612 Anchorage, AK 99519-6612 Re: Docket Number: AIO-19-038 Request to cancel Area Injection Order (AIO) 4G.004 Prudhoe Bay Unit (PBU) 11-07 (PTD 1811770) Prudhoe Bay Field Prudhoe Oil Pool Dear Mr. Daniel: By letter dated December 9, 2019 BP Exploration (Alaska), Inc. (BPXA) requested cancellation of administrative approval (AA) Area Injection Order 4G.004. In accordance with Rule 9 of Area Injection Order (AIO) 4G.000, the Alaska Oil and Gas Conservation Commission (AOGCC) hereby GRANTS BPXA's request to cancel the AA. 11-07 developed an inner annulus (IA) by outer annulus (OA) communication in January 2017 and on February 16, 2017 the AOGCC issued AIO 4G.004. AOGCC determined that water only injection could safely continue if BPXA complied with the restrictive conditions set out in AA AIO 4G.004. BPXA replaced the 7" casing and 4.5" tubing of I1-07 under Sundry 319-377 in October 2019, which resolved the IAxOA communication. AA AIO 4G.004 is no longer necessary to the operation of 11-07 and is hereby CANCELLED. However, post rig workover when injection was recommenced, the well was reported as showing anomalous IA repressurization. BPXA completed a passing state witnessed Mechanical Integrity Test of the Inner Annulus (MITIA) on November 16, 2019 which indicates that 11-07 exhibits at least two competent barriers to the release of well pressure. The new IA repressurization and ongoing injection operations will be authorized separately under AA 4G.009. AIO 4G.004 Cancellation December 12, 2019 Page 2 of 2 DONE at Anchorage, Alaska and dated December 12, 2019. 4Chair, rice Daniel T. S amount, Jr. J ie L. Chmielowskimissioner Commissioner Commissioner 9��'_. 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 urns 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. Gordon Severson Penny Vadla P.O. Box 58055 3201 Westmar Cir. 399 W. Riverview Ave. Fairbanks, AK 99711 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 Fairbanks, AK 99706 THE STATE °fALASKA GOVERNOR BILL WALKER Alaska Oil and Gas Conservation Commission ADMINISTRATIVE APPROVAL AREA INJECTION ORDER NO.4G.004 Mr. Aras Worthington Well Integrity Engineer BP Exploration (Alaska), Inc. P.O. Box 196612 Anchorage, AK 99519-6612 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.00gcc.alaska.gov Re: Docket Number: AIO-17-006 Request for administrative approval to allow well 11-07 (PTD 1811770) to be online in water only injection service with a known inner annulus (IA) by outer annulus (OA) communication. Prudhoe Bay Unit (PBU) 11-07 (PTD 1811770) Prudhoe Bay Field Prudhoe Oil Pool Dear Mr. Worthington: By letter dated February 7, 2017, BP Exploration (Alaska), Inc. (BPXA) requested administrative approval to continue water only injection in the subject well. In accordance with Rule 9 of Area Injection Order (AIO) 4G.000, the Alaska Oil and Gas Conservation Commission (AOGCC) hereby GRANTS BPXA's request for administrative approval to continue water only injection in the subject well. BPXA reported to AOGCC a potential inner annulus by outer annulus pressure communication in January 2017 and initiated additional diagnostics and monitoring. BPXA completed a passing non -state witnessed Mechanical Integrity Test of the Inner Annulus (MITIA) on January 22, 2017. BPXA will complete a passing state witnessed Mechanical Integrity Test of the Inner Annulus (MITIA) once the well returns to injection and after stabilization is achieved. A passing MITIA will confirm that 11-07 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. AIO 4G.004 February 16, 2017 Page 2 of 2 AOGCC's approval to continue water injection only in PBU 11-07 is conditioned upon the following: 1. BPXA shall record wellhead pressures and injection rate daily; 2. BPXA 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. BPXA shall perform a mechanical integrity test of the inner annulus (MITIA) every 2 years to the maximum anticipated injection pressure; 4. BPXA shall limit the well's IA operating pressure to 2000 psi and the OA operating pressure to 1000 psi; BPXA 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 will be set as the date of the AOGCC witnessed MITIA that is to be completed once the well is returned to injection and stabilization is achieved. AOGCC must be provided the opportunity to witness the MIT for the test that will establish the new MIT anniversary date. DONE at Anchorage, Alaska and dated February 16, 2017. Cathy/P. Foerster Chair, Commissioner Daniel T. Seamount, Jr Commissioner RECONSIDERATION AND APPEAL 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. T1tl S NI A L A S K__A Alaska Oil and Gas Conservation Commission ADMINISTRATIVE APPROVAL AREA INJECTION ORDER NO.4G.004 Mr. Aras Worthington Well Integrity Engineer BP Exploration (Alaska), Inc. P.O. Box 196612 Anchorage, AK 99519-6612 Re: Docket Number: AIO-17-006 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 aogcc.alaska.gov Request for administrative approval to allow well 11-07 (PTD 1811770) to be online in water only injection service with a known inner annulus (IA) by outer annulus (OA) communication. Prudhoe Bay Unit (PBU) 11-07 (PTD 1811770) Prudhoe Bay Field Prudhoe Oil Pool Dear Mr. Worthington: By letter dated February 7, 2017, BP Exploration (Alaska), Inc. (BPXA) requested administrative approval to continue water only injection in the subject well. In accordance with Rule 9 of Area Injection Order (AIO) 4G.000, the Alaska Oil and Gas Conservation Commission (AOGCC) hereby GRANTS BPXA's request for administrative approval to continue water only injection in the subject well. BPXA reported to AOGCC a potential inner annulus by outer annulus pressure communication in January 2017 and initiated additional diagnostics and monitoring. BPXA completed a passing non -state witnessed Mechanical Integrity Test of the Inner Annulus (MITIA) on January 22, 2017. BPXA will complete a passing state witnessed Mechanical Integrity Test of the Inner Annulus (MITIA) once the well returns to injection and after stabilization is achieved. A passing MITIA will confirm that 11-07 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. AIO 4G.004 February 16, 2017 Page 2 of 2 AOGCC's approval to continue water injection only in PBU 11-07 is conditioned upon the following: 1. BPXA shall record wellhead pressures and injection rate daily; 2. BPXA 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. BPXA shall perform a mechanical integrity test of the inner annulus (MITIA) every 2 years to the maximum anticipated injection pressure; 4. BPXA shall limit the well's IA operating pressure to 2000 psi and the OA operating pressure to 1000 psi; 5. BPXA 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 will be set as the date of the AOGCC witnessed MITIA that is to be completed once the well is returned to injection and stabilization is achieved. AOGCC must be provided the opportunity to witness the MIT for the test that will establish the new MIT anniversary date. DONE at Anchorage, Alaska and dated February 16, 2017. //signature on file// //signature on file// //signature on file// Cathy P. Foerster Daniel T. Seamount, Jr. Hollis French Chair, Commissioner Commissioner Commissioner 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, February 16, 2017 9:56 AM 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; Evan Osborne; Evans, John R (LDZX); Gary Oskolkosf, George Pollock; Gordon Pospisil; Greeley, Destin M (DOR); Gretchen Stoddard; gspfoff, Hurst, Rona D (DNR); Hyun, James J (DNR); Jacki Rose; Jdarlington Oarlington@gmail.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, Sharmaine Copeland; 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 1; Bruce Williams; Bruno, Jeff J (DNR); Casey Sullivan; Catie Quinn; 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: AIO 4g-004 and AIO 4g-005 Attachments: aio4G.004.pdf, aio4G.005.pdf Re: Docket Number: AI0-17-006 Request for administrative approval to allow well 11-07 (PTD 1811770) to be online in water only injection service with a known inner annulus (IA) by outer annulus (OA) communication. Prudhoe Bay Unit (PBU) 11-07 (PTD 1811770) Prudhoe Bay Field Prudhoe Oil Pool Re: Docket Number: AIO-17-005 Request for administrative approval to allow well P1-21 (PTD 1930590) to be online in water alternating gas (WAG) injection service with a shallow packer depth (cemented inner annulus). Prudhoe Bay Unit (PBU) PTM P1-21 (PTD 1930590) Prudhoe Bay Field Prudhoe Bay Pt McIntyre Oil Pool Jody J. Cotom6ie AOC�CC Special.Assistant .ACaska Oi( and Oa.s Conservation Commission 333 West ; r" .Avenue Anchorage, .ACaska 99501 Office: (9O7)793-1221 .Tax: (,C)07) 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. Bernie Karl KBcK Recycling Inc. Gordon Severson Penny Vadla P.O. Box 58055 3201 Westmar Cir. 399 W. Riverview Ave. Fairbanks, AK 99711 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 Fairbanks, AK 99706 �'1n L 12--k4-PVT THE STATE °fALASKA GOVERNOR BILL WALKER Alaska Oil and Gas Conservation Commission ADMINISTRATIVE APPROVAL AREA INJECTION ORDER NO.4G.005 Mr. Aras Worthington Well Integrity Engineer BP Exploration (Alaska), Inc. P.O. Box 196612 Anchorage, AK 99519-6612 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.alaska.gov Re: Docket Number: AIO-17-005 Request for administrative approval to allow well P1-21 (PTD 1930590) to be online in water alternating gas (WAG) injection service with a shallow packer depth (cemented inner annulus). Prudhoe Bay Unit (PBU) PTM P1-21 (PTD 1930590) Prudhoe Bay Field Prudhoe Bay Pt McIntyre Oil Pool Dear Mr. Worthington: By letter dated February 2, 2017, BP Exploration (Alaska), Inc. (BPXA) requested administrative approval to continue WAG injection in the subject well. In accordance with Rule 9 of Area Injection Order (AIO) 4G.000, the Alaska Oil and Gas Conservation Commission (AOGCC) hereby GRANTS BPXA's request for administrative approval to continue WAG injection in the subject well. BPXA reported a potential production casing leak at 7652 ft. BPXA performed diagnostics and performed a coil tubing cement job of the inner annulus under Sundry 316-437 in January 2017. The inner annulus cement top was estimated at 2590 ft, with the upper injection perforation located at 11,032 ft. However, since the inner annulus is cemented leaving only approximately 2590 ft of inner annulus available for monitoring, this annulus does not meet the requirement that an injection well be equipped with a packer set not more than 200' measured depth above the top of the perforations. If injection does not occur into, through, or above freshwater, 20 AAC 25.450 authorizes less stringent well construction and integrity requirements if AOGCC determines the reduction in requirements will not result in an increased risk of movement of fluids into freshwater. AIO 4G.005 February 16, 2017 Page 2 of 3 BPXA completed a passing non -state witnessed Mechanical Integrity Test of the Inner Annulus (MITIA) on January 8, 2017 and a passing non -state witnessed Mechanical Integrity Test of the Tubing (MITT) on January 18, 2017. BPXA will complete a passing state witnessed MITIA and MITT once the well returns to injection and after stabilization is achieved. A passing MITIA will confirm that P1-21 exhibits at least two competent barriers to the release of well pressure. BPXA will also perform a temperature warmback log and waterflow log which will verify no flow behind pipe and no upward movement of fluid in the IA across the cemented interval. 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 PBU PTM P1-21 is conditioned upon the following: 1. BPXA shall record wellhead pressures and injection rate daily; 2. BPXA 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. BPXA shall perform a mechanical integrity test of the inner annulus every 2 years to the maximum anticipated injection pressure; 4. BPXA shall perform a mechanical integrity test of the tubing every 2 years to the maximum anticipated injection pressure; 5. BPXA shall limit the well's IA operating pressure to 2500 psi, and the OA operating pressure to 1000 psi; 6. BPXA shall perform a temperature warmback log and a waterflow log after the well has been put on injection to verify no flow behind pipe; 7. BPXA shall immediately shut in the well and notify the AOGCC if there is any change in the well's mechanical condition; 8. After well shut in due to a change in the well's mechanical condition, AOGCC approval shall be required to restart injection; and 9. The MIT anniversary date will be set as the date of the AOGCC witnessed MITIA that is to be completed once the well is returned to injection and stabilization is.,ae,,ed. AOGCC must be provided the opportunity to witness the MIT for the test that will e " T the new MIT anniversary date. _, kOIL q;�, DONE at Anchorage, Alaska and dated February 16, 2017. P44A4- Caihyk. Foerster Chair, Commissioner Daniel T. Sea t, Jr. Commissi er Hollis French Commissioner AIO 4G.005 February 16, 2017 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. Tl I E STATE "ALASKA 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 ADMINISTRATIVE APPROVAL AREA INJECTION ORDER NO.4G.005 Mr. Aras Worthington Well Integrity Engineer BP Exploration (Alaska), Inc. P.O. Box 196612 Anchorage, AK 99519-6612 Re: Docket Number: AIO-17-005 Request for administrative approval to allow well P1-21 (PTD 1930590) to be online in water alternating gas (WAG) injection service with a shallow packer depth (cemented inner annulus). Prudhoe Bay Unit (PBU) PTM P1-21 (PTD 1930590) Prudhoe Bay Field Prudhoe Bay Pt McIntyre Oil Pool Dear Mr. Worthington: By letter dated February 2, 2017, BP Exploration (Alaska), Inc. (BPXA) requested administrative approval to continue WAG injection in the subject well. In accordance with Rule 9 of Area Injection Order (AIO) 4G.000, the Alaska Oil and Gas Conservation Commission (AOGCC) hereby GRANTS BPXA's request for administrative approval to continue WAG injection in the subject well. BPXA reported a potential production casing leak at 7652 ft. BPXA performed diagnostics and performed a coil tubing cement job of the inner annulus under Sundry 316-437 in January 2017. The inner annulus cement top was estimated at 2590 ft, with the upper injection perforation located at 11,032 ft. However, since the inner annulus is cemented leaving only approximately 2590 ft of inner annulus available for monitoring, this annulus does not meet the requirement that an injection well be equipped with a packer set not more than 200' measured depth above the top of the perforations. If injection does not occur into, through, or above freshwater, 20 AAC 25.450 authorizes less stringent well construction and integrity requirements if AOGCC determines the reduction in requirements will not result in an increased risk of movement of fluids into freshwater. AIO 4G.005 February 16, 2017 Page 2 of 3 BPXA completed a passing non -state witnessed Mechanical Integrity Test of the Inner Annulus (MITIA) on January 8, 2017 and a passing non -state witnessed Mechanical Integrity Test of the Tubing (MITT) on January 18, 2017. BPXA will complete a passing state witnessed MITIA and MITT once the well returns to injection and after stabilization is achieved. A passing MITIA will confirm that P1-21 exhibits at least two competent barriers to the release of well pressure. BPXA will also perform a temperature warmback log and waterflow log which will verify no flow behind pipe and no upward movement of fluid in the IA across the cemented interval. 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 PBU PTM P1-21 is conditioned upon the following: 1. BPXA shall record wellhead pressures and injection rate daily; 2. BPXA 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. BPXA shall perform a mechanical integrity test of the inner annulus every 2 years to the maximum anticipated injection pressure; 4. BPXA shall perform a mechanical integrity test of the tubing every 2 years to the maximum anticipated injection pressure; 5. BPXA shall limit the well's IA operating pressure to 2500 psi, and the OA operating pressure to 1000 psi; 6. BPXA shall perform a temperature warmback log and a waterflow log after the well has been put on injection to verify no flow behind pipe; 7. BPXA shall immediately shut in the well and notify the AOGCC if there is any change in the well's mechanical condition; 8. After well shut in due to a change in the well's mechanical condition, AOGCC approval shall be required to restart injection; and 9. The MIT anniversary date will be set as the date of the AOGCC witnessed MITIA that is to be completed once the well is returned to injection and stabilization is achieved. AOGCC must be provided the opportunity to witness the MIT for the test that will establish the new MIT anniversary date. DONE at Anchorage, Alaska and dated February 16, 2017. //signature on file// //signature on file// //signature on file// Cathy P. Foerster Daniel T. Seamount, Jr. Hollis French Chair, Commissioner Commissioner Commissioner A10 4G.005 February 16, 2017 Page 3 of 3 n znnii 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 1 (DOA) Sent: Thursday, February 16, 2017 9:56 AM 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; Evan Osborne; Evans, John R (LDZX); Gary Oskolkosf, George Pollock; Gordon Pospisil; Greeley, Destin M (DOR); Gretchen Stoddard; gspfoff, Hurst, Rona D (DNR); Hyun, James J (DNR); Jacki Rose; Jdarlington Oarlington@gmail: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, Sharmaine Copeland; 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; 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: AIO 4g-004 and AIO 4g-005 Attachments: aio4G.004.pdf, aio4G.005.pdf Re: Docket Number: AI0-17-006 Request for administrative approval to allow well 11-07 (PTD 1811770) to be online in water only injection service with a known inner annulus (IA) by outer annulus (OA) communication. Prudhoe Bay Unit (PBU) 11-07 (PTD 1811770) Prudhoe Bay Field Prudhoe Oil Pool Re: Docket Number: AIO-17-005 Request for administrative approval to allow well P 1-21 (PTD 1930590) to be online in water alternating gas (WAG) injection service with a shallow packer depth (cemented inner annulus). Prudhoe Bay Unit (PBU) PTM P1-21 (PTD 1930590) Prudhoe Bay Field Prudhoe Bay Pt McIntyre Oil Pool Judy J. Colombie A0(jCC Special Assistanl .Alaska 0ilarld yas Coiiservation Commission 333 14 est 7"' .Avenue Anchorage, Alaska 995oi Office: (907) 793-1221 fax: (g) 07) 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. 2 Bernie Karl K&K Recycling Inc. Gordon Severson Penny Vadla P.O. Box 58055 3201 Westmar Cir. 399 W. Riverview Ave. Fairbanks, AK 99711 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 Fairbanks, AK 99706 W�A,'(4:SL 2- k�4--12-C) VT <<� THE STATE JALASKA GOVERNOR BILL WALKER Alaska Oil and Gas Conservation Commission ADMINISTRATIVE APPROVAL AREA INJECTION ORDER NO. 4G.006 Mr. Ryan Daniel Well Integrity Engineering Team Lead BP Exploration (Alaska), Inc. P.O. Box 196612 Anchorage, AK 99519-6612 Re: Docket Number: AIO-17-012 333 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 04-43 (PTD 1940130) to be online in water only injection service with a shallow packer depth (cemented inner annulus). Prudhoe Bay Unit (PBU) 04-43 (PTD 1940130) Prudhoe Bay Field Prudhoe Oil Pool Dear Mr. Daniel: By letter dated March 24, 2017, BP Exploration (Alaska), Inc. (BPXA) requested administrative approval to continue water only injection in the subject well. In accordance with Rule 9 of Area Injection Order (AIO) 4G.000, the Alaska Oil and Gas Conservation Commission (AOGCC) hereby GRANTS BPXA's request for administrative approval to continue water only injection in the subject well. BPXA reported a potential production casing leak at 7255 ft and tubing leaks at 1578 ft and 4980 ft. BPXA performed diagnostics and performed a coil tubing cement job of the inner annulus under Sundry 316-213 in June 2016. The inner annulus cement top was estimated at 450 ft, with the upper injection perforation located at 12,688 ft. However, since the inner annulus is cemented leaving only approximately 450 ft of inner annulus available for monitoring, this annulus does not meet the requirement that an injection well be equipped with a packer set not more than 200' measured depth above the top of the perforations. If injection does not occur into, through, or above freshwater, 20 AAC 25.450 authorizes less stringent well construction and integrity requirements if AOGCC determines the reduction in requirements will not result in an increased risk of movement of fluids into freshwater. BPXA performed a temperature warmback log and waterflow log on September 24, 2016, which confirmed no flow behind pipe and no upward movement of fluid in the IA between the tubing punch holes and the production casing leak across the cemented interval. BPXA completed a passing non -state witnessed Mechanical Integrity Test of the Inner Annulus (MITIA) on October 7, 2016, and a passing non -state witnessed Mechanical Integrity Test of the Tubing (MITT) on AIO 4G.006 April 6, 2017 Page 2 of 2 August 6, 2016. BPXA will complete a state witnessed MITIA and MITT once the well returns to injection and after stabilization is achieved. A passing MITIA will confirm that 04-43 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 PBU 04-43 is conditioned upon the following: 1. BPXA shall record wellhead pressures and injection rate daily; 2. BPXA 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. BPXA shall perform a mechanical integrity test of the inner annulus every 2 years to the maximum anticipated injection pressure; 4. BPXA shall perform a mechanical integrity test of the tubing every 2 years to the maximum anticipated injection pressure; 5. BPXA shall limit the well's IA operating pressure to 2000 psi; 6. BPXA shall immediately shut in the well and notify the AOGCC if there is any change in the well's mechanical condition; 7. After well shut in due to a change in the well's mechanical condition, AOGCC approval shall be required to restart injection; and 8. The MIT anniversary date will be set as the date of the AOGCC witnessed MITIA that is to be completed once the well is returned to injection and stabilization is achieved. AOGCC must be provided the opportunity to witness the MIT for the test that will establ' the new MIT anniversary date. DONE at Anchorage, Alaska and dated April 6, 2017. Cath P. Foerster Daniel T. Seamount, Jr. Hollis French Chair, Commissioner 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. T l i l: S"l' 1T 'ALASKA Alaska Oil and Gas Conservation Commission ADMINISTRATIVE APPROVAL AREA INJECTION ORDER NO.4G.006 Mr. Ryan Daniel Well Integrity Engineering Team Lead BP Exploration (Alaska), Inc. P.O. Box 196612 Anchorage, AK 99519-6612 Re: Docket Number: AIO-17-012 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 aogcc.alaska.gov Request for administrative approval to allow well 04-43 (PTD 1940130) to be online in water only injection service with a shallow packer depth (cemented inner annulus). Prudhoe Bay Unit (PBU) 04-43 (PTD 1940130) Prudhoe Bay Field Prudhoe Oil Pool Dear Mr. Daniel: By letter dated March 24, 2017, BP Exploration (Alaska), Inc. (BPXA) requested administrative approval to continue water only injection in the subject well. In accordance with Rule 9 of Area Injection Order (AIO) 4G.000, the Alaska Oil and Gas Conservation Commission (AOGCC) hereby GRANTS BPXA's request for administrative approval to continue water only injection in the subject well. BPXA reported a potential production casing leak at 7255 ft and tubing leaks at 1578 ft and 4980 ft. BPXA performed diagnostics and performed a coil tubing cement job of the inner annulus under Sundry 316-213 in June 2016. The inner annulus cement top was estimated at 450 ft, with the upper injection perforation located at 12,688 ft. However, since the inner annulus is cemented leaving only approximately 450 ft of inner annulus available for monitoring, this annulus does not meet the requirement that an injection well be equipped with a packer set not more than 200' measured depth above the top of the perforations. If injection does not occur into, through, or above freshwater, 20 AAC 25.450 authorizes less stringent well construction and integrity requirements if AOGCC determines the reduction in requirements will not result in an increased risk of movement of fluids into freshwater. BPXA performed a temperature warmback log and waterflow log on September 24, 2016, which confirmed no flow behind pipe and no upward movement of fluid in the IA between the tubing punch holes and the production casing leak across the cemented interval. BPXA completed a passing non -state witnessed Mechanical Integrity Test of the Inner Annulus (MITIA) on October 7, 2016, and a passing non -state witnessed Mechanical Integrity Test of the Tubing (MITT) on AIO 4G.006 April 6, 2017 Page 2 of 2 August 6, 2016. BPXA will complete a state witnessed MITIA and MITT once the well returns to injection and after stabilization is achieved. A passing MITIA will confirm that 04-43 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 PBU 04-43 is conditioned upon the following: l . BPXA shall record wellhead pressures and injection rate daily; 2. BPXA 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. BPXA shall perform a mechanical integrity test of the inner annulus every 2 years to the maximum anticipated injection pressure; 4. BPXA shall perform a mechanical integrity test of the tubing every 2 years to the maximum anticipated injection pressure; 5. BPXA shall limit the well's IA operating pressure to 2000 psi; 6. BPXA shall immediately shut in the well and notify the AOGCC if there is any change in the well's mechanical condition; 7. After well shut in due to a change in the well's mechanical condition, AOGCC approval shall be required to restart injection; and 8. The MIT anniversary date will be set as the date of the AOGCC witnessed MITIA that is to be completed once the well is returned to injection and stabilization is achieved. AOGCC must be provided the opportunity to witness the MIT for the test that will establish the new MIT anniversary date. DONE at Anchorage, Alaska and dated April 6, 2017. //signature on file// //signature on file// //signature on file// Cathy P. Foerster Daniel T. Seamount, Jr. Hollis French Chair, Commissioner 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. 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 99711-0055 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 q--7-k-T M, Colombie, Jody J (DOA) From: Colombie, Jody J (DOA) Sent: Thursday, April 06, 2017 2:33 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@gmail.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; Bajsarowicz, Caroline J; Bruce Williams; Bruno, Jeff J (DNR); Casey Sullivan; Catie Quinn; Corey Munk; Don Shaw; Eppie Hogan; 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: AIO 4G.006 Attachments: aio4g.006.pdf Please see attached. Re: Docket Number: AIO-17-012 Request for administrative approval to allow well 04-43 (PTD 1940130) to be online in water only injection service with a shallow packer depth (cemented inner annulus). Prudhoe Bay Unit (PBU) 04-43 (PTD 1940130) Prudhoe Bay Field Prudhoe Oil Pool jolly f. CotomHte Ao (�C'C' Spectat 'Assistant Atasfa 0it'amQ4as Co1isel,vation Comnitssioll 333 West 7"' _venue -Anchorage, Alaska 9) 5oi ORice: (.007) 793-1221 fax: (c)07) 276-754.2 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 °fALASKA GOVERNOR MIKE DUNLEAVY Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 w .aogcc.alaska.gov ADMINISTRATIVE APPROVAL AREA INJECTION ORDER NO. 4G.007 CANCELLATION Mr. Ryan Daniel Well Integrity & Compliance Team Leader BP Exploration (Alaska), Inc. P.O. Box 196612 Anchorage, AK 99519-6612 Re: Docket Number: AIO-19-023 Request to cancel Area Injection Order (AIO) 4G.007 Prudhoe Bay Unit (PBU) 16-14B (PTD 2060030) Prudhoe Bay Field Prudhoe Oil Pool Dear Mr. Daniel: By letter dated June 7, 2019, received July 9, 2019, BP Exploration (Alaska), Inc. (BPXA) requested cancellation of administrative approval (AA) Area Injection Order 4G.007. In accordance with Rule 9 of Area Injection Order (AIO) 4G.000, the Alaska Oil and Gas Conservation Commission (AOGCC) hereby GRANTS BPXA's request to cancel the AA. 16-14B developed an inner annulus repressurization in May 2017 and on September 18, 2017 the AOGCC issued AID 4G.007. AOGCC determined that water alternating gas injection could safely continue if BPXA complied with the restrictive conditions set out in AA AIO 4G.007. BPXA abandoned 16-14B in October 2018 under Sundry 318-366 prior to drilling a new well sidetrack 16-14C (PTD 2181170). The 16-14C well completed a passing state witnessed Mechanical Integrity Tests of the Inner Annulus (MITIA) on March 28, 2019 and April 7, 2019 which indicate that 16-14C exhibits at least two competent barriers to the release of well pressure. AA AIO 4G.007 is no longer necessary to the operation of 16-14C and is hereby CANCELLED. AIO 4G.007 Cancellation July 11, 2019 Page 2 of 2 DONE at Anchorage, Alaska and dated July 11, 2019. Daniel T. eamount, Jr. J si�L. Chmielowski Commissioner Commissioner AND APPEAL 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. THE STATE °ALASKA GOVERNOR MICHAEL I. DUNLEAVY 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 ADMINISTRATIVE APPROVAL AREA INJECTION ORDER NO. 4G.007 CANCELLATION Mr. Ryan Daniel Well Integrity & Compliance Team Leader BP Exploration (Alaska), Inc. P.O. Box 196612 Anchorage, AK 99519-6612 Re: Docket Number: AIO- 19-023 Request to cancel Area Injection Order (AIO) 4G.007 Prudhoe Bay Unit (PBU) 16-14B (PTD 2060030) Prudhoe Bay Field Prudhoe Oil Pool Dear Mr. Daniel: By letter dated June 7, 2019, received July 9, 2019, BP Exploration (Alaska), Inc. (BPXA) requested cancellation of administrative approval (AA) Area Injection Order 4G.007. In accordance with Rule 9 of Area Injection Order (AIO) 4G.000, the Alaska Oil and Gas Conservation Commission (AOGCC) hereby GRANTS BPXA's request to cancel the AA. 16-14B developed an inner annulus repressurization in May 2017 and on September 18, 2017 the AOGCC issued AIO 4G.007. AOGCC determined that water alternating gas injection could safely continue if BPXA complied with the restrictive conditions set out in AA AIO 4G.007. BPXA abandoned 16-14B in October 2018 under Sundry 318-366 prior to drilling a new well sidetrack 16-14C (PTD 2181170). The 16-14C well completed a passing state witnessed Mechanical Integrity Tests of the Inner Annulus (MITIA) on March 28, 2019 and April 7, 2019 which indicate that 16-14C exhibits at least two competent barriers to the release of well pressure. AA AID 4G.007 is no longer necessary to the operation of 16-14C and is hereby CANCELLED. AIO 443.007 Cancellation July 11, 2019 Page 2 of 2 DONE at Anchorage, Alaska and dated July 11, 2019. //signature on file// Daniel T. Seamount, Jr Commissioner //signature on file// Jessie L. Chmielowski Commissioner (4 4`anoa co`� 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. Gordon Severson Penny Vadla P.O. Box 58055 3201 Westmar Cir. 399 W. Riverview Ave. Fairbanks, AK 99711 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 Fairbanks, AK 99706 THE STATE °fALASKA GOVERNOR BILL WALKER Alaska Oil and Gas Conservation Commission ADMINISTRATIVE APPROVAL AREA INJECTION ORDER NO. 4G.007 Mr. Ryan Daniel Well Integrity Engineering Team Lead BP Exploration (Alaska), Inc. P.O. Box 196612 Anchorage, AK 99519-6612 Re: Docket Number: AIO-17-029 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1 433 Fax: 907.276.7542 www.00gcc.olaska.gov Request for administrative approval to allow well 16-14B (PTD 2060030) to be online in water alternating gas (WAG) injection service with known inner annulus repressurization. Prudhoe Bay Unit (PBU) 16-14B (PTD 2060030) Prudhoe Bay Field Prudhoe Oil Pool Dear Mr. Daniel: By letter dated August 28, 2017, BP Exploration (Alaska), Inc. (BPXA) requested administrative approval to continue WAG injection in the subject well. In accordance with Rule 9 of Area Injection Order (AIO) 4G.000, the Alaska Oil and Gas Conservation Commission (AOGCC) hereby GRANTS BPXA's request for administrative approval to continue WAG injection in the subject well. BPXA reported a potential Inner Annulus repressurization to AOGCC in May 2017. BPXA performed diagnostics and completed a passing non -state witnessed Mechanical Integrity Test of the Inner Annulus (MITIA) on July 27, 2017 which indicates that 16-14B exhibits at least two competent barriers to the release of well pressure. BPXA also performed a passing non -state witnessed Mechanical Integrity Test of the Tubing (MIT -T) on June 23, 2017 which confirmed tubing integrity. The well had a recorded IA build up rate of approximately 600 psi/day. If injection does not occur into, through, or above freshwater, 20 AAC 25.450 authorizes less stringent well construction and integrity requirements if AOGCC determines the reduction in requirements will not result in an increased risk of movement of fluids into freshwater. 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 4G.007 September 18, 2017 Page 2 of 2 AOGCC's approval to continue WAG in PBU 16-14B is conditioned upon the following: 1. BPXA shall record wellhead pressures and injection rate daily; 2. BPXA 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. BPXA shall perform a mechanical integrity test of the inner annulus every 2 years to 1.1 times the maximum anticipated injection pressure; 4. BPXA shall limit the well's IA operating pressure to 2000 psi; 5. BPXA 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 will be set as the date of the AOGCC witnessed MITIA that is to be completed once the well is returned to injection and stabilization is achieved. AOGCC must be provided the opportunity to witness the MIT for the test that will establish the new MIT anniversary date. DONE at Anchorage, Alaska and dated September 18, 2017. Hollis French QP Daniel T. Seamodnt, Jr. Chair, Commissioner Commissioner nON 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. 1'111: STAFF. "ALASKA ( OVERNO IZ rill I A\AI KIP Alaska Oil and Gas Conservation Commission ADMINISTRATIVE APPROVAL AREA INJECTION ORDER NO. 4G.007 Mr. Ryan Daniel Well Integrity Engineering Team Lead BP Exploration (Alaska), Inc. P.O. Box 196612 Anchorage, AK 99519-6612 Re: Docket Number: AIO-17-029 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 oogcc.alaska.gov Request for administrative approval to allow well 16-14B (PTD 2060030) to be online in water alternating gas (WAG) injection service with known inner annulus repressurization. Prudhoe Bay Unit (PBU) 16-14B (PTD 2060030) Prudhoe Bay Field Prudhoe Oil Pool Dear Mr. Daniel: By letter dated August 28, 2017, BP Exploration (Alaska), Inc. (BPXA) requested administrative approval to continue WAG injection in the subject well. In accordance with Rule 9 of Area Injection Order (AIO) 4G.000, the Alaska Oil and Gas Conservation Commission (AOGCC) hereby GRANTS BPXA's request for administrative approval to continue WAG injection in the subject well. BPXA reported a potential Inner Annulus repressurization to AOGCC in May 2017. BPXA performed diagnostics and completed a passing non -state witnessed Mechanical Integrity Test of the Inner Annulus (MITIA) on July 27, 2017 which indicates that 16-14B exhibits at least two competent barriers to the release of well pressure. BPXA also performed a passing non -state witnessed Mechanical Integrity Test of the Tubing (MIT -T) on June 23, 2017 which confirmed tubing integrity. The well had a recorded IA build up rate of approximately 600 psi/day. If injection does not occur into, through, or above freshwater, 20 AAC 25.450 authorizes less stringent well construction and integrity requirements if AOGCC determines the reduction in requirements will not result in an increased risk of movement of fluids into freshwater. 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 4G.007 September 18, 2017 Page 2 of 2 AOGCC's approval to continue WAG in PBU 16-14B is conditioned upon the following: 1. BPXA shall record wellhead pressures and injection rate daily; 2. BPXA 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. BPXA shall perform a mechanical integrity test of the inner annulus every 2 years to 1.1 times the maximum anticipated injection pressure; 4. BPXA shall limit the well's IA operating pressure to 2000 psi; 5. BPXA 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 will be set as the date of the AOGCC witnessed MITIA that is to be completed once the well is returned to injection and stabilization is achieved. AOGCC must be provided the opportunity to witness the MIT for the test that will establish the new MIT anniversary date. DONE at Anchorage, Alaska and dated September 18, 2017. //signature on file// //signature on file// Hollis French Daniel T. Seamount, Jr. Chair, 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 furtber 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 emmeous. 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 ran 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 raps 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. Gordon Severson Penny.Vadla Rive 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 997060868 M -A, (-Q A- `!-1 2v k7 Colombie, Jody J (DOA) From: Colombie, Jody 1 (DOA) Sent: Monday, September 18, 2017 10:47 AM 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); 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; Alicia Showalter; 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; Cody Gauer; Colleen Miller; Connie Downing; Crandall, Krissell; D Lawrence; Dale Hoffman; Darci Horner; Dave Harbour; David Boelens; David Duffy; David House; David McCaleb; David McCraine; ddonkel@cfl.rr.com; Diemer, Kenneth J (DNR); DNROG Units (DNR sponsored); Donna Ambruz; Ed Jones; Elizabeth Harball; Elowe, Kristin; Elwood Brehmer; Evan Osborne; Evans, John R (LDZX); Brown, Garrett A (DNR); George Pollock, Gordon Pospisil; Greeley, Destin M (DOR); Gretchen Stoddard; gspfoff; Hunter Cox; Hurst, Rona D (DNR); Hyun, James J (DNR); Jacki Rose; Jason Brune; Jdarlington (arlington@gmail.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); Kyla Choquette; Gregersen, Laura S (DNR); Leslie Smith; Lori Nelson; 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; Mike Morgan; MJ Loveland; mkm7200; Motteram, Luke A; Mueller, Marta R (DNR); knelson@petroleumnews.com; Nichole Saunders; Nick Ostrovsky; 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; Robert Warthen; 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; Tim Jones; Tim Mayers; Todd Durkee; Tom Maloney; 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; Andy Bond; Bajsarowicz, Caroline J; Bruce Williams; Bruno, Jeff J (DNR); Casey Sullivan; Corey Munk; Don Shaw, Eppie Hogan; Eric Lidji; Garrett Haag; Smith, Graham O (DNR); Heusser, Heather A (DNR); Fair, Holly S (DNR); Jamie M. Long; Jason Bergerson; Jesse Chielowski; Jim Magill; Shine, Jim M (DNR); Joe Longo; John Martineck; Josh Kindred; Keith Lopez, Laney Vazquez, Lois Epstein; Longan, Sara W (DNR); Louisiana Cutler; Marc Kuck; Marcia Hobson; Steele, Marie C (DNR); Matt Armstrong; Melonnie Amundson; Franger, lames M (DNR); Morgan, Kirk A (DNR); Umekwe, Maduabuchi P (DNR); Pat Galvin; Pete Dickinson; Peter Contreras; Rachel Davis; Richard Garrard; Richmond, Diane M; Robert Province; Ryan Daniel; Sandra Lemke; Pollard, Susan R (LAW); Talib Syed; Tina Grovier (tmgrovier@stoel.com); William Van Dyke Subject: aio4g.007 Attachments: aio4G.007.pdf Please see attached. Re: Docket Number: AIO-17-029 Request for administrative approval to allow well 16-14B (PTD 2060030) to be online in water alternating gas (WAG) injection service with known inner annulus repressurization. Prudhoe Bay Unit (PBU) 16-14B (PTD 2060030) Prudhoe Bay Field Prudhoe Oil Pool Jody i. CoCombie AOCGCC Specia(Assistant ACaska OiCandGas Conservation Commission 333 West 711 Avenue .anchorage, .Kaska 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. TI IE SI'ATP. "ALASKA ( OVERNI>R DILL 1\ALF:FR Alaska Oil and Gas Conservation Commission ADMINISTRATIVE APPROVAL AREA INJECTION ORDER NO. 4G.008 Mr. Aras Worthington Well Integrity Engineer BP Exploration (Alaska), Inc. P.O. Box 196612 Anchorage, AK 99519-6612 Re: Docket Number: AIO-18-006 333 west Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 aogcc.alaska.gov Request for administrative approval to allow well R -22A (PTD 2141640) and lateral R- 22AL1 (PTD 2141650) to be online in water only injection service with known inner annulus (IA) repressurization. Prudhoe Bay Unit (PBU) R -22A (PTD 2141640) and lateral R-22AL1 (PTD 2141650) Prudhoe Bay Field Prudhoe Oil Pool Dear Mr. Worthington: By letter received February 8, 2018, BP Exploration (Alaska), Inc. (BPXA) requested administrative approval to continue water only injection in the subject well. In accordance with Rule 9 of Area Injection Order (AIO) 4G.000, the Alaska Oil and Gas Conservation Commission (AOGCC) hereby GRANTS BPXA's request for administrative approval to continue water only injection in the subject well. BPXA reported a potential inner annulus repressurization to AOGCC and initiated additional diagnostics and monitoring. BPXA completed a passing non -state witnessed Mechanical Integrity Test of the Inner Annulus (MITIA) on March 27, 2017 which indicates that R -22A exhibits at least two competent barriers to the release of well pressure. The well only exhibits IA repressurization (tubing to inner annulus) when injecting miscible injectant (MI) and AOGCC finds that BPXA is able to manage the IA pressure with periodic pressure bleeds. 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 4G.008 February 15, 2018 Page 2 of 2 AOGCC's approval to continue water infection only in PBU R -22A and lateral R-22ALI is conditioned upon the following: 1. BPXA shall record wellhead pressures and injection rate daily; 2. BPXA 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. BPXA shall perform a mechanical integrity test of the inner annulus (MITIA) every 2 years to the maximum anticipated injection pressure; 4. BPXA shall limit the well's IA operating pressure to 2000 psi, and the outer annulus operating pressure to 1000 psi; 5. BPXA 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 will be set as the date of the AOGCC witnessed MITIA that is to be completed once the well is returned to injection and stabilization is achieved. AOGCC must be provided the opportunity to witness the MIT for the test that will establish the new MIT anniversary date. DONE at Anchorage, Alaska and dated February 15, 2018. //signature on file// Hollis French Chair, Commissioner //signature on file// Cathy P. Foerster Commissioner //signature on file// Daniel T. Seamount, Jr. 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 ertoneous. 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 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. THE STATE GOVERNOR BILL WALKER Alaska Oil and Gas Conservation Commission ADMINISTRATIVE APPROVAL AREA INJECTION ORDER NO. 4G.008 Mr. Aras Worthington Well Integrity Engineer BP Exploration (Alaska), Inc. P.O. Box 196612 Anchorage, AK 99519-6612 Re: Docket Number: AIO-18-006 333 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 R -22A (PTD 2141640) and lateral R- 22AL1 (PTD 2141650) to be online in water only injection service with known inner annulus (IA) repressurization. Prudhoe Bay Unit (PBU) R -22A (PTD 2141640) and lateral R-22AL1 (PTD 2141650) Prudhoe Bay Field Prudhoe Oil Pool Dear Mr. Worthington: By letter received February 8, 2018, BP Exploration (Alaska), Inc. (BPXA) requested administrative approval to continue water only injection in the subject well. In accordance with Rule 9 of Area Injection Order (AIO) 4G.000, the Alaska Oil and Gas Conservation Commission (AOGCC) hereby GRANTS BPXA's request for administrative approval to continue water only injection in the subject well. BPXA reported a potential inner annulus repressurization to AOGCC and initiated additional diagnostics and monitoring. BPXA completed a passing non -state witnessed Mechanical Integrity Test of the Inner Annulus (MITIA) on March 27, 2017 which indicates that R -22A exhibits at least two competent barriers to the release of well pressure. The well only exhibits IA repressurization (tubing to inner annulus) when injecting miscible injectant (MI) and AOGCC finds that BPXA is able to manage the IA pressure with periodic pressure bleeds. 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 4G.008 February 15, 2018 Page 2 of 2 AOGCC's approval to continue water injection only in PBU R -22A and lateral R-22AL1 is conditioned upon the following: 1. BPXA shall record wellhead pressures and injection rate daily; 2. BPXA 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. BPXA shall perform a mechanical integrity test of the inner annulus (MITIA) every 2 years to the maximum anticipated injection pressure; 4. BPXA shall limit the well's IA operating pressure to 2000 psi, and the outer annulus 5. Q operating pressure to 1000 psi; BPXA 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 MIT anniversary date will be set as the date of the AOGCC witnessed MITIA that is to be completed once the well is returned to injection and stabilization is achieved. AOGCC must be provided the opportunity to witness the MIT for the test that will establish the new MIT anniversary date. DONE at Anchorage, Alaska and dated February 15, 2018. Hollis French Chair, Commissioner 441 2 2w� Cath P. Foerster 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 par 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. George Vaught, Jr. P.O. Box 13557 Denver, CO 80201-3557 Bernie Karl M Recycling Inc. P.O. Box 58055 Fairbanks, AK 99711 Darwin Waldsmith P.O. Box 39309 Ninilchik, AK 99639 Gordon Severson 3201 Westmar Cir. Anchorage, AK 99508-4336 Penny Vacila 399 W. Riverview Ave. Soldotna, AK 99669-7714 Richard Wagner P.O. Box 60868 Fairbanks, AK 99706 Colombie, Jody 1 (DOA) From: Colombie, Jody 1 (DOA) Sent: Thursday, February 15, 2018 3:14 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); 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); McPhee, Megan S (DOA); Rixse, Melvin G (DOA); Mumm, Joseph (DOA sponsored); Paladijczuk, Tracie L (DOA); Pasqual, Maria (DOA); Regg, James B (DOA); Roby, David S (DOA); Schwartz, Guy L (DOA); Seamount, Dan T (DOA); Ballantine, Tab A (LAW); Erickson, Tamara K (DOA); Wallace, Chris D (DOA); AK, GWO Projects Well Integrity; AKDCWeIIIntegrityCoordinator; Alan Bailey; Alex Demarban; Alicia Showalter; Allen Huckabay; Andrew Vandedack, 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; Cody Gauer; Cody Terrell; Colleen Miller, Connie Downing; Crandall, Krissell; D Lawrence; Dale Hoffman; Danielle Mercurio; Darci Horner; Dave Harbour; David Boelens; David Duffy; David House; David McCaleb; ddonkel@cfl.rr.com; Diemer, Kenneth 1 (DNR); DNROG Units (DNR sponsored); Donna Ambruz; Ed Jones; Elizabeth Harball; Elowe, Kristin; Elwood Brehmer; Evan Osborne; Evans, John R (LDZX); Brown, Garrett A (DNR); George Pollock; Gordon Pospisil; Greeley, Destin M (DOR); Gretchen Stoddard; gspfoff; Hurst, Rona D (DNR); Hyun, James J (DNR); Jacki Rose; Jason Brune; Jdarlington Qarlington@gmail.com); Jeanne McPherren; Jerry Hodgden; Jill Simek; Jim Shine; Jim Watt; Jim White; Young, Jim P (DNR); Joe Lastufka; Radio Kenai; Burdick, John D (DNR); Easton, John R (DNR); Larsen, John M (DOR); 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); Kyla Choquette; Gregersen, Laura S (DNR); Leslie Smith; Lori Nelson; Luke Keller; Marc Kovak; Dalton, Mark (DOT sponsored); Mark Hanley (mark.hanley@anadarko.com); Mark Landt; Mark Wedman; Michael Bill; Michael Calkins; Michael Moora; Michael Quick; Michael Schoetz; Mike Morgan; MJ Loveland; mkm7200; Motteram, Luke A; Mueller, Marta R (DNR); Nathaniel Herz; knelson@petroleumnews.com; Nichole Saunders; Nick Ostrovsky; 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; Robert Warthen; Sara Leverette; Scott Griffith; Shahla Farzan; Shannon Donnelly; Sharon Yarawsky; Skutca, Joseph E (DNR); Smith, Kyle S (DNR); Stephanie Klemmer; Stephen Hennigan; Sternicki, Oliver R; Moothart, Steve R (DNR); Steve Quinn; Suzanne Gibson; sheffield@aoga.org; Tanisha Gleason; Ted Kramer; Teresa Imm; Tim Jones; Tim Mayers; Todd Durkee; Tom Maloney, 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; Andy Bond; Bajsarowicz, Caroline J; Bruce Williams; Casey Sullivan; Corey Munk; D. McCraine; Don Shaw; Eppie Hogan; Eric Lidji; Garrett Haag; Smith, Graham O (DNR); Heusser, Heather A (DNR); Fair, Holly S (DNR); Jamie M. Long; Jason Bergerson; Jesse Chielowski; Jim Magill; Joe Longo; John Martineck; Josh Kindred; Keith Lopez; Laney Vazquez, Lois Epstein; Longan, Sara W (DNR); Marc Kuck; Marcia Hobson; Steele, Marie C (DNR); Matt Armstrong; Melonnie Amundson; Franger, James M (DNR); Morgan, Kirk A (DNR); Umekwe, Maduabuchi P (DNR); Pat Galvin; Pete Dickinson; Peter Contreras; Rachel Davis; Richard Garrard; Richmond, Diane M; Robert Province; Ryan Daniel; Sandra Lemke; Pollard, Susan R (LAW); Talib Syed; Tina Grovier (tmgrovier@stoel.com); William Van Dyke Subject: AIO 4G.008 Attachments: aio4G.008.pdf Please see attached. Re: Docket Number: AIO-18-006 Request for administrative approval to allow well R -22A (PTD 2141640) and lateral R-22AL1 (PTD 2141650) to be online in water only injection service with known inner annulus (IA) repressurization. Prudhoe Bay Unit (PBU) R -22A (PTD 2141640) and lateral R-22AL1 (PTD 2141650) Prudhoe Bay Field Prudhoe Oil Pool Jody J. Co(ombie .AOGCC Syecia(Assistant Alaska Oi(andgas Conservation Commission 333 west 711 avenue Anchorage, Ataska 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@alaskaQgov. THE STATE °fALASKA GOVERNOR MIKE DUNLEAVY Alaska Oil and Gas Conservation Commission ADMINISTRATIVE APPROVAL AREA INJECTION ORDER NO. 4G.009 Mr. Ryan Daniel Well Integrity Engineering Team Leader BP Exploration (Alaska), Inc. P.O. Box 196612 Anchorage, AK 99519-6612 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.00gcc.aloslka.gov Re: Docket Number: AIO-19-039 Request for administrative approval to allow well 11-07 (PTD 1811770) to be online in water only injection service with a known inner annulus repressurization Prudhoe Bay Unit (PBU) 11-07 (PTD 1811770) Prudhoe Bay Field Prudhoe Oil Pool Dear Mr. Daniel: By letter dated December 9, 2019 BP Exploration (Alaska), Inc. (BPXA) requested administrative approval to continue water only injection in the subject well. In accordance with Rule 9 of Area Injection Order (AIO) 4G.000, the Alaska Oil and Gas Conservation Commission (AOGCC) hereby GRANTS BPXA's request for administrative approval to continue water only injection in the subject well. BPXA replaced the 7" casing and 4.5" tubing of 11-07 under Sundry 319-377 in October 2019, which resolved the inner annulus (IA) by outer annulus (OA) communication. AA AIO 4G.004 is therefore no longer necessary to the operation of 11-07 and was cancelled on December 12, 2019. 11-07 developed an IA repressurization shortly after the rig workover was performed and injection was recommenced. BPXA performed diagnostics and completed a passing state witnessed Mechanical Integrity Test of the Inner Annulus (MITIA) on November 16, 2019 which indicates that 11-07 exhibits at least two competent barriers to the release of well pressure. The well has a recorded IA build up rate of 95 psi/hour that stabilizes at 1030 psi with a tubing injection pressure of 1375 psi. BPXA has installed wireless gauges on DS -11 wells that allow for real time monitoring and alarm notifications of IA and outer annulus (OA) pressures. AOGCC finds that BPXA is able to manage the IA pressure with periodic pressure bleeds. 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 4G.009 December 12, 2019 Page 2 of 2 AOGCC's approval to continue water injection only in PBU 11-07 is conditioned upon the following: 1. BPXA shall record wellhead pressures and injection rate daily; 2. BPXA 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. BPXA shall perform a mechanical integrity test of the inner annulus every 2 years to the greater of the maximum anticipated injection pressure or 0.25 x packer TVD, but not less than 1500 psi; 4. BPXA shall limit the well's IA operating pressure to 2000 psi; 5. BPXA 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 November 16, 2019. DONE at Anchorage, Alaska and dated December 12, 2019. (U � (� Jer y Price Daniel T. Seamount, Jr. J Ie L. Chmielc r ommissioner Commissioner Commissioner 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 I0 -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 coup. 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 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 THE sTATI: ALASKA GOVERNOR MICHAEL I. DUNL -AFY Alaska Oil and Gas Conservation Commission ADMINISTRATIVE APPROVAL AREA INJECTION ORDER NO. 4G.008 AMENDED Mr. Stan Golis PBW Operations Manager Hilcorp North Slope LLC. 3800 Centerpoint Dr, Suite 1400 Anchorage, AK 99503 Re: Docket Number: AIO-20-015 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.alaska.gov Request for administrative approval to amend AIO 4G.008 to allow well R -22A (PTD 2141640) and lateral R-22AL1 (PTD 2141650) to be online in water only injection service with known inner annulus (IA) repressurization. Prudhoe Bay Unit (PBU) R -22A (PTD 2141640) and lateral R-22AL1 (PTD 2141650) Prudhoe Bay Field Prudhoe Oil Pool Dear Mr. Golis: By letter dated July 21, 2020, Hilcorp North Slope, LLC (Hilcorp) requested administrative approval to amend AIO 4G.008 to continue water only injection in the subject well. In accordance with Rule 9 of Area Injection Order (AIO) 4G.000, the Alaska Oil and Gas Conservation Commission (AOGCC) hereby GRANTS Hilcorp's request to amend administrative approval AIO 4G.008 and continue water only injection in the subject well. Former field operator BPXA reported a potential inner annulus repressurization to AOGCC and initiated additional diagnostics and monitoring in March 2017. A passing non -state witnessed Mechanical Integrity Test of the Inner Annulus (MITIA) on March 27, 2017 indicated that R -22A exhibits at least two competent barriers to the release of well pressure. The well only exhibited IA repressurization (tubing to inner annulus) when injecting miscible injectant (MI). AOGCC found that BPXA was able to manage the IA pressure with periodic pressure bleeds and issued AIO 4G.008 on February 15, 2018 restricting the well to water only injection. The well restarted water injection in March 2020. On July 17, 2020, the new field operator Hilcorp reported that the well had IA repressurization while on water injection. The well passed a state witnessed Mechanical Integrity Test of the Inner Annulus (MITIA) on July 20, 2020 which indicates that the well exhibits at least two competent barriers to the release of well pressure. AOGCC believes Hilcorp can safely manage the IA AIO 4G.008 Amended July 23, 2020 Page 2 of 2 repressurization with periodic pressure bleeds and wireless pressure gauges. 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 PBU R -22A and lateral R-22AL1 is conditioned upon the following: 1. Hilcorp shall record wellhead pressures and injection rate daily; 2. Hilcorp 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. Hilcorp shall perform a mechanical integrity test of the inner annulus (MITIA) every 2 years to the greater of the maximum anticipated injection pressure or 0.25 x packer TVD, but not less than 1500 psi; 4. 5. 1 Hilcorp shall limit the well's IA operating pressure to 2000 psi, and the outer annulus operating pressure to 1000 psi; Hilcorp 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 July 2022. DONE at Anchorage, Alaska and dated July 23, 2020. Jeremy M. =.'."M'=� Price °ifpi0.0'v EnSaSNW Jeremy M. Price Chair, Commissioner Daniel T. seamount Jr. Daniel T. Seamount, Jr Commissioner Jessie L. Digitally agnedbyieme L ChOudowsltl Chmielowski 11111.23 13:30%3-OWW 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 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 we 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 George Vaught, Jr. P.O. Box 13557 Denver, CO 80201-3557 Gordon Severson 3201 Westmar Cir. Anchorage, AK 99508-4336 Darwin Waldsmith P.O. Box 39309 Ninilchik, AK 99639 Richard Wagner P.O. Box 60868 Fairbanks, AK 99706 TI IE STATE ,,ALASKA 6okT.RNOR MK-KkEL J. DUNtr ivY ADMINISTRATIVE APPROVAL AREA INJECTION ORDER NO. 4G.010 Mr. Bo York PBE Operations Manager Hilcorp North Slope LLC. 3800 Centerpoint Dr, Suite 1400 Anchorage, AK 99503 Re: Docket Number: AIO-20-018 Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 ww .00gcc.oloska.gov Request for administrative approval to allow well PSI -01 (PTD 2021450) to be online in water only injection service with a known inner annulus (IA) repressurization. Prudhoe Bay Unit (PBU) PSI -01 (PTD 2021450) Prudhoe Bay Field Prudhoe Oil Pool Dear Mr. York: By letter dated July 31, 2020, Hilcorp North Slope, LLC (Hilcorp) requested administrative approval to continue water only injection in the subject well. In accordance with Rule 9 of Area Injection Order (AIO) 4G.000, the Alaska Oil and Gas Conservation Commission (AOGCC) hereby GRANTS Hilcorp's request for administrative approval to continue water only injection in the subject well. On July 16, 2020, the new field operator Hilcorp reported that the well had potential IA repressurization while on seawater injection. The well passed a state witnessed Mechanical Integrity Test of the Inner Annulus (MITIA) on July 29, 2020 which indicates that the well exhibits at least two competent barriers to the release of well pressure. AOGCC believes Hilcorp can safely manage the IA repressurization with periodic pressure bleeds and wireless pressure gauges. Accordingly, the AOGCC believes that the well's condition does not compromise overall well integrity so as to threaten human safety or the environment. A10 413.0 10 August 10, 2020 Page 2 of 2 AOGCC's approval to continue water injection only in PBU PSI -01 is conditioned upon the following: 1. Hilcorp shall record wellhead pressures and injection rate daily; 2. Hilcorp 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. Hilcorp shall perform a mechanical integrity test of the inner annulus (MITIA) every 2 years to the greater of the maximum anticipated injection pressure or 0.25 x packer TVD, but not less than 1500 psi; 4. Hilcorp shall limit the well's IA operating pressure to 2000 psi, and the outer annulus operating pressure to 1000 psi; 5. Hilcorp 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 July 2022. DONE at Anchorage, Alaska and dated August 10, 2020. Jeremy M. Daniel T. G91uIM,NnM by Daniel D191WI1y A9ned by J— r,xemWntx. Je%W L.[hmlelowski L0—eto-kl MW:" 0,%rolel&M Dae:mma9.r9tosnas Price '°""' Seamount, Jr..... oaar Jeremy M. Price Daniel T. Seamount, Jr. Jessie L. Chmielowski Chair, Commissioner 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 ease 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 George Vaught, Jr. P.O. Box 13557 Denver, CO 80201-3557 Gordon Severson 3201 Westmar Cir. Anchorage, AK 99508-4336 Darwin Waldsmith P.O. Box 39309 Ninilchik, AK 99639 Richard Wagner P.O. Box 60868 Fairbanks, AK 99706 Tl 11? S 1ATF ,,ALASKA GOVERNORhIICHAN 1 PUNLi AVY ADMINISTRATIVE APPROVAL AREA INJECTION ORDER NO. 4G.01I Mr. Bo York PBE Operations Manager Hilcorp North Slope LLC. 3800 Centerpoint Dr, Suite 1400 Anchorage, AK 99503 Re: Docket Number: AIO-20-019 Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.olasko.gov Request for administrative approval to allow well 17-13A (PTD 2050200) to be online in water only injection service with a known inner annulus (IA) repressurization. Prudhoe Bay Unit (PBU) 17-13A (PTD 2050200) Prudhoe Bay Field Prudhoe Oil Pool Dear Mr. York: By letter dated July 31, 2020, Hilcorp North Slope, LLC (Hilcorp) requested administrative approval to continue water only injection in the subject well. In accordance with Rule 9 of Area Injection Order (AIO) 4G.000, the Alaska Oil and Gas Conservation Commission (AOGCC) hereby GRANTS Hilcorp's request for administrative approval to continue water only injection in the subject well. On July 17, 2020, the new field operator Hilcorp reported that the well had potential IA repressurization while on produced water injection. The well passed a state witnessed Mechanical Integrity Test of the Inner Annulus (MITIA) on July 29, 2020 which indicates that the well exhibits at least two competent barriers to the release of well pressure. AOGCC believes Hilcorp can safely manage the IA repressurization with periodic pressure bleeds and wireless pressure gauges. Accordingly, the AOGCC believes that the well's condition does not compromise overall well integrity so as to threaten human safety or the environment. A10 4G.011 August 10, 2020 Page 2 of 2 AOGCC's approval to continue water injection only in PBU 17-13A is conditioned upon the following: 1. Hilcorp shall record wellhead pressures and injection rate daily; 2. Hilcorp 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. Hilcorp shall perform a mechanical integrity test of the inner annulus (MITIA) every 2 years to the greater of the maximum anticipated injection pressure or 0.25 x packer TVD, but not less than 1500 psi; 4. Hilcorp shall limit the well's IA operating pressure to 2000 psi, and the outer annulus operating pressure to 1000 psi; 5. Hilcorp 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 July 2022. DONE at Anchorage, Alaska and dated August 10, 2020. Jessie LDigitally signed ay Jeremy M. °,°•` L. Jessie L. Chmlelowski "die ChmielowSkl Date:2o2o.os.to 10:57:05 moos Jeremy M. Price Daniel T. Seamount, Jr. Jessie L. Chmielowski Chair, Commissioner Commissioner Commissioner WnIeIT. Seemoun,.,r. As provided in AS 31.05.080(a), within 20 days after written notice of the entry of this order or decision, or such father 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 he 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 George Vaught, Jr. P.O. Box 13557 Denver, CO 80201-3557 Gordon Severson 3201 Westmar Cir. Anchorage, AK 99508-4336 Darwin Waldsmith P.O. Box 39309 Ninilchik, AK 99639 Richard Wagner P.O. Box 60868 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 4G.011 AMENDED Mr. Bo York PBE Operations Manager Hilcorp North Slope LLC. 3800 Centerpoint Dr, Suite 1400 Anchorage, AK 99503 Re: Docket Number: AIO-23-032 Request to Amend Area Injection Order 4G.011; Water Alternating Gas Injection Prudhoe Bay Unit (PBU) 17-13A (PTD 2050200), Prudhoe Oil Pool Dear Mr. York: By emailed letter dated November 13, 2023, Hilcorp North Slope LLC (Hilcorp)requested administrative approval to amend Area Injection Order (AIO) 4G.011 to include water alternating gas (WAG) injection with a known tubing by inner annulus (TxIA) pressure communication. In accordance with 20AAC 25.556(d), the Alaska Oil and Gas Conservation Commission (AOGCC) hereby GRANTS, subject to conditions, Hilcorp’s request to amend the administrative approval to continue WAG injection in the subject well. Hilcorp reported a potential TxIA pressure communication to AOGCC on July 17, 2020, while the well was on produced water injection. AOGCC found that Hilcorp was able to manage the IA pressure with periodic pressure bleeds and issued AIO 4G.011 on July 31, 2020, restricting the well to water only injection. Hilcorp completed additional diagnostics including a passing state witnessed mechanical integrity test (MIT) of the inner annulus (to a test pressure greater than the anticipated gas injection pressure) on October 10, 2023. This indicates that the well exhibits at least two competent barriers to the release of well pressure. Hilcorp maintains live transmitters on the inner and outer annulus and alarm functions in the Supervisory Control and Data Acquisition (SCADA) system with remote shut down capabilities that create 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 Hilcorp can safely manage the TxIA communication with periodic pressure bleeds by maintaining the inner annulus to a pressure not to exceed 2,100 psi. Accordingly, the AOGCC believes that the well’s condition does AIO 4G.011 Amended November 28, 2023 Page 2 of 2 not compromise overall well integrity so as to threaten human safety or the environment. AOGCC’s approval to continue WAG injection in PBU 17-13A is conditioned upon the following: 1) Hilcorp shall record wellhead pressures and injection rate daily; 2) Hilcorp 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) Hilcorp 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) Hilcorp shall limit the well’s inner annulus operating pressure to 2,100 psi and the outer annulus operating pressure to 1,000 psi. Audible control room alarms shall be set at or below these limits; 5) Hilcorp shall monitor the inner and outer annulus pressures in real time with its SCADA system; 6) Hilcorp shall maintain the FS2 plant or Drill Site 17 manifold building remote shut down capability for 17-13A when on gas or miscible injectant (MI) operation; 7) Hilcorp shall immediately shut in the well and notify the AOGCC if there is any change in the well's mechanical condition; 8) After well shut in due to a change in the well's mechanical condition, AOGCC approval shall be required to restart injection; and 9) The next required MIT shall be completed before or during the month of October 2025. DONE at Anchorage, Alaska and dated November 28, 2023. Brett W. Huber, Sr Jessie L. Chmielowski Gregory C. Wilson Chair, Commissioner 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. Gregory Wilson Digitally signed by Gregory Wilson Date: 2023.11.28 13:26:03 -09'00' Brett W. Huber, Sr. Digitally signed by Brett W. Huber, Sr. Date: 2023.11.28 13:32:01 -09'00' Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2023.11.28 14:28:35 -09'00' 1 Carlisle, Samantha J (OGC) From:Carlisle, Samantha J (OGC) <samantha.carlisle@alaska.gov> Sent:Tuesday, November 28, 2023 2:58 PM To:AOGCC_Public_Notices Subject:[AOGCC_Public_Notices] Area Injection Order 4G.011 amended Attachments:aio4G.011 amended.pdf Docket Number: AIO-23-032 Request to Amend Area Injection Order 4G.011; Water Alternating Gas Injection Prudhoe Bay Unit (PBU) 17-13A (PTD 2050200), Prudhoe Oil Pool Samantha Carlisle 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 4G.012 February 3, 2022 Mr. Bo York, PBE Operations Manager Hilcorp North Slope, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Re: Docket Number: AIO-22-005 Request for Administrative Approval to Area Injection Order 4G Water Alternating Gas Injection Prudhoe Bay Unit (PBU) P1-01 (PTD 1900270), Point McIntyre Oil Pool Dear Mr. York: By emailed letter dated January 25, 2022, Hilcorp North Slope, LLC (Hilcorp) requested administrative approval to continue water alternating gas (WAG) injection with a known tubing by inner annulus (TxIA) pressure communication. In accordance with 20AAC 25.556(d), the Alaska Oil and Gas Conservation Commission (AOGCC) hereby GRANTS, subject to conditions, Hilcorp’s request for administrative approval to continue WAG injection in the subject well. Hilcorp reported a potential TxIA pressure communication to AOGCC on January 18, 2022, while the well was on miscible gas injection. On January 19, 2022, Hilcorp performed additional diagnostics including a passing non state-witnessed mechanical integrity test (MIT) of the inner annulus (to a test pressure of 3,986 psi which is greater than the anticipated gas injection pressure of 3,300 psi). This indicates that P1-01 exhibits at least two competent barriers to the release of well pressure. Hilcorp 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. AOGCC believes Hilcorp can safely manage the TxIA communication with periodic pressure bleeds by maintaining the inner annulus to a pressure not to exceed 2,500 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. AIO 4G.012 February 3, 2022 Page 2 of 2 AOGCC’s approval to continue WAG injection in PBU P1-01 is conditioned upon the following: 1) Hilcorp shall record wellhead pressures and injection rate daily; 2) Hilcorp 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) Hilcorp 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) Hilcorp shall limit the well’s inner annulus operating pressure to 2,500 psi and the outer annulus operating pressure to 1,000 psi. Audible control room alarms shall be set at or below these limits; 5) Hilcorp shall monitor the inner and outer annulus pressures in real time with its SCADA system; 6) Hilcorp shall immediately shut in the well and notify the AOGCC if there is any change in the well's mechanical condition; 7) After well shut in due to a change in the well's mechanical condition, AOGCC approval shall be required to restart injection; and 8) The next required MIT shall be completed before or during the month of January 2024. DONE at Anchorage, Alaska and dated February 3, 2022 . Jeremy M. Price Daniel T. Seamount, Jr. Jessie L. Chmielowski Chair, Commissioner 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. Dan Seamount Digitally signed by Dan Seamount Date: 2022.02.03 12:29:51 -09'00' Jeremy Price Digitally signed by Jeremy Price Date: 2022.02.03 12:56:01 -09'00' Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2022.02.03 13:11:09 -09'00' From:Salazar, Grace (OGC) To:AOGCC_Public_Notices Subject:[AOGCC_Public_Notices] AOGCC Area Injection Order No. 4G.012 (Hilcorp, Prudhoe Bay Unit) Date:Thursday, February 3, 2022 2:06:22 PM Attachments:AIO 4G.012.pdf The Alaska Oil and Gas Conservation Commission has issued the attached administrative approval, granting Hilcorp North Slope, LLC’s request to continue water alternating gas injection for Prudhoe Bay Unit P1-01 Well. Grace ____________________________________ Respectfully, M. Grace Salazar, Special Assistant Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage, AK 99501 Direct: (907) 793-1221 Email: grace.salazar@alaska.gov https://www.commerce.alaska.gov/web/aogcc/ __________________________________ List Name: AOGCC_Public_Notices@list.state.ak.us You subscribed as: grace.salazar@alaska.gov Unsubscribe at: https://list.state.ak.us/mailman/options/aogcc_public_notices/grace.salazar%40alaska.gov AOGCC 333 W 7th Avenue, Anchorage, AK 99501 TO: BERNIE KARL K&K RECLYCLING, INC. PO BOX 58055 FAIRBANKS, AK 99711 Mailed 2/4/22gs 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 4G.013 February 16, 2022 Mr. Bo York PBE Operations Manager Hilcorp North Slope, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Re: Docket Number: AIO-22-006 Request for Administrative Approval to Area Injection Order 4G Water Alternating Gas Injection Prudhoe Bay Unit (PBU) P2-34 (PTD 1950660), Point McIntyre Oil Pool Dear Mr. York: By emailed letter dated February 2, 2022, Hilcorp North Slope, LLC (Hilcorp) requested administrative approval to continue water alternating gas (WAG) injection with a known tubing by inner annulus (TxIA) pressure communication. In accordance with 20AAC 25.556(d), the Alaska Oil and Gas Conservation Commission (AOGCC) hereby GRANTS, subject to conditions, Hilcorp’s request for administrative approval to continue WAG injection in the subject well. Hilcorp reported a potential TxIA pressure communication to AOGCC on January 25, 2022, while the well was on miscible gas injection. On January 30, 2022, Hilcorp performed additional diagnostics including a passing state-witnessed mechanical integrity test (MIT) of the inner annulus (to a test pressure of 3,882 psi which is greater than the anticipated gas injection pressure of 3,200 psi). This indicates that P2-34 exhibits at least two competent barriers to the release of well pressure. Hilcorp 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. AOGCC believes Hilcorp can safely manage the TxIA communication with periodic pressure bleeds by maintaining the inner annulus to a pressure not to exceed 2,500 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. AIO 4G.013 February 16, 2022 Page 2 of 2 AOGCC’s approval to continue WAG injection in PBU P2-34 is conditioned upon the following: 1) Hilcorp shall record wellhead pressures and injection rate daily; 2) Hilcorp 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) Hilcorp 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) Hilcorp shall perform a MIT of the tubing every four years to the maximum anticipated injection pressure to verify zonal isolation per packer depth variance in Sundry 321-186; 5) Hilcorp shall limit the well’s inner annulus operating pressure to 2,500 psi and the outer annulus operating pressure to 1,000 psi. Audible control room alarms shall be set at or below these limits; 6) Hilcorp shall monitor the inner and outer annulus pressures in real time with its SCADA system; 7) Hilcorp shall immediately shut in the well and notify the AOGCC if there is any change in the well's mechanical condition; 8) After well shut in due to a change in the well's mechanical condition, AOGCC approval shall be required to restart injection; and 9) The next required MIT shall be completed before or during the month of January 2024. DONE at Anchorage, Alaska and dated February 16, 2022. Jeremy M. Price Daniel T. Seamount, Jr. Jessie L. Chmielowski Chair, Commissioner 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. Dan Seamount Digitally signed by Dan Seamount Date: 2022.02.16 13:59:16 -09'00' Jeremy Price Digitally signed by Jeremy Price Date: 2022.02.16 14:26:08 -09'00' Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2022.02.16 14:34:48 -09'00' From:Salazar, Grace (OGC) To:AOGCC_Public_Notices Subject:[AOGCC_Public_Notices] AOGCC Area Injection Order No. 4G.013 Date:Wednesday, February 16, 2022 3:09:55 PM Attachments:AIO 4G.013.pdf The Alaska Oil and Gas Conservation Commission has issued the attached Area Injection Order No. 4G.013, granting Hilcorp North Slope, LLC’s request to continue Water Alternating Gas Injection into the Prudhoe Bay Unit Point McIntyre well P2-34 (PTD 195-066). Grace ____________________________________ Respectfully, M. Grace Salazar, Special Assistant Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage, AK 99501 Direct: (907) 793-1221 Email: grace.salazar@alaska.gov https://www.commerce.alaska.gov/web/aogcc/ __________________________________ List Name: AOGCC_Public_Notices@list.state.ak.us You subscribed as: grace.salazar@alaska.gov Unsubscribe at: https://list.state.ak.us/mailman/options/aogcc_public_notices/grace.salazar%40alaska.gov AOGCC 333 W 7th Avenue, Anchorage, AK 99501 TO: BERNIE KARL K&K RECLYCLING, INC. PO BOX 58055 FAIRBANKS, AK 99711 Mailed 2/16/22gs 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 4G.014 March 2, 2022 Mr. Bo York PBE Operations Manager Hilcorp North Slope, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Re: Docket Number: AIO-22-007 Request for Administrative Approval to Area Injection Order 4G; Gas Injection Prudhoe Bay Unit (PBU) NGI-12 (PTD 1770810), Prudhoe Oil Pool Dear Mr. York: By emailed letter dated February 21, 2022, Hilcorp North Slope, LLC (Hilcorp) requested administrative approval to continue gas injection with a known tubing by inner annulus (TxIA) pressure communication. In accordance with 20AAC 25.556(d), the Alaska Oil and Gas Conservation Commission (AOGCC) hereby GRANTS, subject to conditions, Hilcorp’s request for administrative approval to continue gas injection in the subject well. Hilcorp reported a potential TxIA pressure communication to AOGCC on January 20, 2022, while the well was on gas injection. On February 10, 2022, Hilcorp performed additional diagnostics including a passing state-witnessed mechanical integrity test (MIT) of the inner annulus (to a test pressure of 3,645 psi which is greater than the anticipated gas injection pressure of 3,500 psi). This indicates that NGI-12 exhibits at least two competent barriers to the release of well pressure. Hilcorp 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. AOGCC believes Hilcorp can safely manage the TxIA communication with periodic pressure bleeds by maintaining the inner annulus to a pressure not to exceed 2,100 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. AIO 4G.014 March 2, 2022 Page 2 of 2 AOGCC’s approval to continue gas injection in PBU NGI-12 is conditioned upon the following: 1) Hilcorp shall record wellhead pressures and injection rate daily; 2) Hilcorp 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) Hilcorp 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) Hilcorp shall limit the well’s inner annulus operating pressure to 2,100 psi and the outer annulus operating pressure to 1,000 psi. Audible control room alarms shall be set at or below these limits; 5) Hilcorp shall monitor the inner and outer annulus pressures in real time with its SCADA system; 6) Hilcorp shall immediately shut in the well and notify the AOGCC if there is any change in the well's mechanical condition; 7) After well shut in due to a change in the well's mechanical condition, AOGCC approval shall be required to restart injection; and 8) The next required MIT shall be completed before or during the month of February 2024. DONE at Anchorage, Alaska and dated March 2, 2022. Jeremy M. Price Daniel T. Seamount, Jr. Jessie L. Chmielowski Chair, Commissioner 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. Daniel Seamount Digitally signed by Daniel Seamount Date: 2022.03.01 09:12:37 -09'00' Jeremy Price Digitally signed by Jeremy Price Date: 2022.03.01 13:22:00 -09'00' Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2022.03.02 09:20:02 -09'00' From:Salazar, Grace (OGC) To:AOGCC_Public_Notices Subject:[AOGCC_Public_Notices] AOGCC Area Injection Order No. 4G.014 (Hilcorp, PBU) Date:Wednesday, March 2, 2022 9:40:48 AM Attachments:AIO 4G.014.pdf The Alaska Oil and Gas Conservation Commission has issued the attached Area Injection Order 4G.014, granting Hilcorp North Slope, LLC’s request to continue Gas Injection into Prudhoe Bay Well NGI-12. Grace ____________________________________ Respectfully, M. Grace Salazar, Special Assistant Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage, AK 99501 Direct: (907) 793-1221 Email: grace.salazar@alaska.gov https://www.commerce.alaska.gov/web/aogcc/ __________________________________ List Name: AOGCC_Public_Notices@list.state.ak.us You subscribed as: grace.salazar@alaska.gov Unsubscribe at: https://list.state.ak.us/mailman/options/aogcc_public_notices/grace.salazar%40alaska.gov AOGCC 333 W 7th Avenue, Anchorage, AK 99501 TO: BERNIE KARL K&K RECLYCLING, INC. PO BOX 58055 FAIRBANKS, AK 99711 Mailed 3/2/22 gs 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 4G.015 March 21, 2022 Mr. Bo York PBE Operations Manager Hilcorp North Slope, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Re: Docket Number: AIO-22-008 Request for Administrative Approval to Area Injection Order 4G; Gas Injection Prudhoe Bay Unit (PBU) WGI-02 (PTD 1790430), Prudhoe Oil Pool Dear Mr. York: By emailed letter dated March 14, 2022, Hilcorp North Slope, LLC (Hilcorp) requested administrative approval to continue gas injection with a known inner annulus by outer annulus (IAxOA) pressure communication. In accordance with 20AAC 25.556(d), the Alaska Oil and Gas Conservation Commission (AOGCC) hereby GRANTS, subject to conditions, Hilcorp’s request for administrative approval to continue gas injection in the subject well. Hilcorp reported a potential IAxOA pressure communication to AOGCC on February 17, 2022, while the well was on gas injection. On February 10, 2022, Hilcorp performed additional diagnostics including a passing state-witnessed mechanical integrity test (MIT) of the inner annulus (to a test pressure of 3,722 psi which is greater than the anticipated gas injection pressure of 3,700 psi). This indicates that WGI-02 exhibits at least two competent barriers to the release of well pressure. Hilcorp 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. AOGCC believes Hilcorp can safely manage the IAxOA communication with periodic pressure bleeds by maintaining the inner annulus to a pressure not to exceed 2,100 psi and the outer annulus 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. AIO 4G.015 March 21, 2022 Page 2 of 2 AOGCC’s approval to continue gas injection in PBU WGI-02 is conditioned upon the following: 1) Hilcorp shall record wellhead pressures and injection rate daily; 2) Hilcorp 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) Hilcorp 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) Hilcorp shall limit the well’s inner annulus operating pressure to 2,100 psi and the outer annulus operating pressure to 1,000 psi. Audible control room alarms shall be set at or below these limits; 5) Hilcorp shall monitor the inner and outer annulus pressures in real time with its SCADA system; 6) Hilcorp shall immediately shut in the well and notify the AOGCC if there is any change in the well's mechanical condition; 7) After well shut in due to a change in the well's mechanical condition, AOGCC approval shall be required to restart injection; and 8) The next required MIT shall be completed before or during the month of March 2024. DONE at Anchorage, Alaska and dated March 21, 2022. Jeremy M. Price Jessie L. Chmielowski 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. Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2022.03.21 08:11:56 -08'00' Jeremy Price Digitally signed by Jeremy Price Date: 2022.03.21 11:49:54 -08'00' From:Salazar, Grace (OGC) To:AOGCC_Public_Notices Subject:[AOGCC_Public_Notices] AOGCC Area Injection Order No. 4G.015 Date:Monday, March 21, 2022 12:12:12 PM Attachments:AIO 4G.015.pdf The Alaska Oil and Gas Conservation Commission has issued the attached administrative approval granting Hilcorp North Slope, LLC’s request for continued gas injection into Prudhoe Bay Well WGI- 02. Grace ____________________________________ Respectfully, M. Grace Salazar, Special Assistant Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage, AK 99501 Direct: (907) 793-1221 Email: grace.salazar@alaska.gov https://www.commerce.alaska.gov/web/aogcc/ __________________________________ List Name: AOGCC_Public_Notices@list.state.ak.us You subscribed as: grace.salazar@alaska.gov Unsubscribe at: https://list.state.ak.us/mailman/options/aogcc_public_notices/grace.salazar%40alaska.gov AOGCC 333 W 7th Avenue, Anchorage, AK 99501 TO: BERNIE KARL K&K RECLYCLING, INC. PO BOX 58055 FAIRBANKS, AK 99711 Mailed 3/21/22 gs 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 4G.016 Mr. Bo York, PBE Operations Manager Hilcorp North Slope, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Re: Docket Number: AIO-23-016 Request for Administrative Approval to Area Injection Order 4G; Water Injection Prudhoe Bay Unit (PBU) 04-11A (PTD 1931580), Prudhoe Oil Pool Dear Mr. York: By letter dated June 6, 2023, Hilcorp North Slope, LLC (Hilcorp) requested administrative approval to continue water injection with a known tubing by inner annulus (TxIA) pressure communication. In accordance with 20AAC 25.556(d), the Alaska Oil and Gas Conservation Commission (AOGCC) hereby GRANTS, subject to conditions, Hilcorp’s request for administrative approval to continue water only injection in the subject well. Hilcorp reported a potential TxIA pressure communication to AOGCC on June 1, 2023, while the well was on water injection. On June 6, 2023, Hilcorp performed additional diagnostics including a passing state-witnessed mechanical integrity test (MIT) of the inner annulus which indicates that 04-11A exhibits at least two competent barriers to the release of well pressure. Hilcorp 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. AOGCC believes Hilcorp can safely manage the TxIA communication with periodic pressure bleeds by maintaining the inner annulus to a pressure not to exceed 2,100 psi and the outer annulus 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 injection only in PBU 04-11A is conditioned upon the following: 1) Hilcorp shall record wellhead pressures and injection rate daily; 2) Hilcorp 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) Hilcorp 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 4G.016 June 14, 2023 Page 2 of 2 4) Hilcorp shall limit the well’s inner annulus operating pressure to 2,100 psi and the outer annulus operating pressure to 1,000 psi. Audible control room alarms shall be set at or below these limits; 5) Hilcorp shall monitor the inner and outer annulus pressures in real time with its SCADA system; 6) Hilcorp shall immediately shut in the well and notify the AOGCC if there is any change in the well's mechanical condition; 7) After well shut in due to a change in the well's mechanical condition, AOGCC approval shall be required to restart injection; and 8) The next required MIT shall be completed before or during the month of June 2025. DONE at Anchorage, Alaska and dated June 14, 2023. Brett W. Huber, Sr Jessie L. Chmielowski Gregory C. Wilson Chair, Commissioner 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. Brett W. Huber, Sr. Digitally signed by Brett W. Huber, Sr. Date: 2023.06.14 14:09:33 -08'00' Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2023.06.14 14:16:57 -08'00' Gregory Wilson Digitally signed by Gregory Wilson Date: 2023.06.14 14:19:36 -08'00' From:Carlisle, Samantha J (OGC) To:AOGCC_Public_Notices Subject:[AOGCC_Public_Notices] Area Injection Order 4G.016 Date:Wednesday, June 14, 2023 2:37:51 PM Attachments:aio4G.016.pdf Docket Number: AIO-23-016 Request for Administrative Approval to Area Injection Order 4G; Water Injection Prudhoe Bay Unit (PBU) 04-11A (PTD 1931580), Prudhoe Oil Pool Samantha Carlisle 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 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 4G.017 Mr. Bo York Operations Manager Hilcorp North Slope, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Re: Docket Number: AIO-24-011 Request for Administrative Approval to Area Injection Order 4G; Gas Injection Prudhoe Bay Unit (PBU) 03-07B (PTD 2191820), Prudhoe Oil Pool Dear Mr. York: By emailed letter dated March 12, 2024, Hilcorp North Slope, LLC (Hilcorp) requested administrative approval to continue gasinjection with a known tubing by inner annulus (TxIA) pressure communication. In accordance with 20 AAC 25.556(d), the Alaska Oil and Gas Conservation Commission (AOGCC) hereby GRANTS, subject to conditions, Hilcorp’s request for administrative approval to continue gas injection in the subject well. Hilcorp reported a potential TxIA pressure communication to AOGCC on February 4, 2024, when the well was on miscible gas injection. Hilcorp performed diagnostics and monitoring which confirmed slow TxIA. Hilcorp has performed additional diagnostics including a passing state-witnessed mechanical integrity test (MIT) of the inner annulus (to a test pressure of 3,269 psi) on February 24, 2024. This indicates that 03-07B exhibits at least two competent barriers to the release of well pressure. Hilcorp maintains live transmitters on the inner and outer annulus and alarm functions in the Supervisory Control and Data Acquisition (SCADA) system with remote shut down capabilities that create 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 continue to authorize gas injection. AOGCC believes Hilcorp can safely manage the slow TxIA communication with periodic pressure bleeds by maintaining the IA to a pressure not to exceed 2,100 psi and OA to 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 gas injection in PBU 03-07B is conditioned upon the following: 1) Hilcorp shall record wellhead pressures and injection rate daily; 2) Hilcorp 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; AIO 4G.017 March 18, 2024 Page 2 of 2 3) Hilcorp 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) Hilcorp shall limit the well’s inner annulus operating pressure to 2,100 psi and the outer annulus operating pressure to 1,000 psi. Audible control room alarms shall be set at or below these limits; 5) Hilcorp shall monitor the inner and outer annulus pressures in real time with its SCADA system; 6) Hilcorp shall maintain the FS2 plant or Drill Site 03 manifold building remote shut down capability for 03-07B when on gas or miscible injectant (MI) operation; 7) Hilcorp shall immediately shut in the well and notify the AOGCC if there is any change in the well's mechanical condition; 8) After well shut in due to a change in the well's mechanical condition, AOGCC approval shall be required to restart injection; and 9) The next required MIT shall be completed before or during the month of February 2026. DONE at Anchorage, Alaska and dated March 18, 2024. Brett W. Huber, Sr Jessie L. Chmielowski Gregory C. Wilson Chair, Commissioner 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. Gregory Wilson Digitally signed by Gregory Wilson Date: 2024.03.18 13:47:59 -08'00' Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2024.03.18 13:50:46 -08'00' Brett W. Huber, Sr. Digitally signed by Brett W. Huber, Sr. Date: 2024.03.18 20:58:35 -05'00' From:Coldiron, Samantha J (OGC) To:AOGCC_Public_Notices Subject:[AOGCC_Public_Notices] Area Injection Order 4G.017 (Hilcorp) Date:Tuesday, March 19, 2024 7:50:14 AM Attachments:aio4G.017.pdf Docket Number: AIO-24-011 Request for Administrative Approval to Area Injection Order 4G; Gas Injection Prudhoe Bay Unit (PBU) 03-07B (PTD 2191820), Prudhoe Oil Pool Samantha Coldiron 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 APPROVAL AREA INJECTION ORDER 4G.018 Mr. Bo York PBE Operations Manager Hilcorp North Slope, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Re: Docket Number: AIO-25-012 Request for Administrative Approval to Area Injection Order 4G.018: Water Only Injection Prudhoe Bay Unit PAVE 3-1 (PTD 2241400), Prudhoe Oil Pool Dear Mr. York: By emailed letter dated April 17, 2025, Hilcorp North Slope, LLC (Hilcorp) requested administrative approval to continue water only injection with a high set packer that reduces the monitorable inner annulus (IA). The packer design does not meet the requirement of 20 AAC 25.412(b) that “an injector be equipped with tubing and a packer… the packer must be placed within 200 feet measured depth above the top of the perforations…”. The well, currently, has no known pressure communication integrity issues. In accordance with 20AAC 25.556(d), the Alaska Oil and Gas Conservation Commission (AOGCC) hereby GRANTS, subject to conditions, Hilcorp’s request for administrative approval to continue water only injection in the subject well. The completion of PAVE 3-1 left the 7” cemented solid liner with a packer set at 11,805 ft measured depth (MD) which is now 2,937 ft MD above the shallowest open injection zone. The high set packer effectively prevents integrity verification by IA monitoring below 11,805 ft, so there is potentially an increased risk of fluids undetectably being injected outside of the approved injection zone. Hilcorp has completed diagnostics including non state-witnessed mechanical integrity tests of the inner annulus (MITIA) and a 7” (MIT-T) and plans a state-witnessed MITIA and MIT-T after the well is on injection and conditions (temperature, pressure, rate etc.) have stabilized. Passing tests will indicate that PAVE 3-1 exhibits at least two competent barriers to the release of well pressure. Hilcorp 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. AOGCC believes Hilcorp can safely manage injection operations with periodic pressure bleeds by maintaining the inner annulus to a pressure not to exceed 2,100 psi and the outer annulus not to exceed 1,000 psi. AIO 4G.018 April 23, 2025 Page 2 of 3 Accordingly, the AOGCC believes that the well 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 PAVE 3-1 is conditioned upon the following: 1)Hilcorp shall record wellhead pressures and injection rate daily; 2)Hilcorp 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)Hilcorp shall perform a MITIA every two years to the greater of the maximum anticipated header injection pressure or 0.25 x packer TVD, but not less than 1,500 psi; 4)Hilcorp shall perform a MIT-T every two years, with a plug set in the 7” production liner below 13,500 ft MD, to the greater of the maximum anticipated header injection pressure or 0.25 x packer TVD, but not less than 1,500 psi; 5)Hilcorp shall limit the well’s inner annulus operating pressure to 2,100 psi. Audible control room alarms shall be set at or below these limits; 6)Hilcorp 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)Hilcorp shall monitor the inner and outer annulus pressures in real time with its SCADA system; 8)Hilcorp 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 MITIA is to be after the well is placed on injection and injection conditions (temperature, pressure, rate etc.) have stabilized. AOGCC must be provided the opportunity to witness the MIT for a test to establish a new test due date. DONE at Anchorage, Alaska and dated April 23, 2025. Jessie L. Chmielowski Gregory C. Wilson Commissioner Commissioner Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2025.04.23 14:05:59 -08'00' Gregory C. Wilson Digitally signed by Gregory C. Wilson Date: 2025.04.23 14:34:03 -08'00' AIO 4G.018 April 23, 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 Order 4G.018 (Hilcorp) Date:Wednesday, April 23, 2025 3:15:42 PM Attachments:AIO4G.018.pdf Docket Number: AIO-25-012 Request for Administrative Approval to Area Injection Order 4G.018: Water Only Injection Prudhoe Bay Unit PAVE 3-1 (PTD 2241400), Prudhoe 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 APPROVAL AREA INJECTION ORDER 4G.019 Mr. Bo York PBE Operations Manager Hilcorp North Slope, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Re: Docket Number: AIO-25-018 Request for Administrative Approval to Area Injection Order 4G: Water Only Injection Prudhoe Bay Unit L5-29 (PTD 1870450), Lisburne Oil Pool Dear Mr. York: By emailed letter dated August 18, 2025, Hilcorp North Slope, LLC (Hilcorp) requested administrative approval to continue water only injection with a high set packer that reduces the monitorable inner annulus (IA). The packer design doesn’t meet the requirement of 20 AAC 25.412(b) that “an injector be equipped with tubing and a packer… the packer must be placed within 200 feet measured depth above the top of the perforations…”. The well, currently, has no known pressure communication integrity issues. In accordance with 20AAC 25.556(d), the Alaska Oil and Gas Conservation Commission (AOGCC) hereby GRANTS, subject to conditions, Hilcorp’s request for administrative approval to continue water only injection in the subject well. A rig workover was performed under Sundry Approval 322-724 in September 2023 to isolate a production casing leak and correct a tubing leak at 10,820 ft. Two packers were set at 10,678 ft and 13,142 ft with the shallowest open perforation at 13,585 ft. The high set packer effectively prevents integrity verification by IA monitoring below 10,678 ft, so there is potentially an increased risk of fluids undetectably being injected outside of the approved injection zone. After the rig workover, Hilcorp completed diagnostics including state-witnessed mechanical integrity tests of the inner annulus (MIT-IA) and tubing (MIT-T) in September 2023. Hilcorp plans to retest the well in September 2025. Passing tests will continue to indicate that L5-29 exhibits at least two competent barriers to the release of well pressure. Hilcorp 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. AOGCC believes Hilcorp can safely manage injection operations with periodic pressure bleeds AIO 4G.019 August 26, 2025 Page 2 of 3 by maintaining the inner annulus to a pressure not to exceed 2,500 psi and the outer annulus 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 L5-29 is conditioned upon the following: 1)Hilcorp shall record wellhead pressures and injection rate daily; 2)Hilcorp 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)Hilcorp shall perform a MIT-IA every two years to the greater of the maximum anticipated header injection pressure or 0.25 x packer TVD, but not less than 1,500 psi; 4)Hilcorp shall perform a MIT-T every two years, with a deep set plug, to the greater of the maximum anticipated header injection pressure or 0.25 x packer TVD, but not less than 1,500 psi; 5)Hilcorp shall limit the well’s inner annulus operating pressure to 2,500 psi. Audible control room alarms shall be set at or below these limits; 6)Hilcorp 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)Hilcorp shall monitor the inner and outer annulus pressures in real time with its SCADA system; 8)Hilcorp 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 MITIA is to be completed before or during the month of September 2025. AOGCC must be provided the opportunity to witness the MIT for a test to establish a new test due date. DONE at Anchorage, Alaska and dated August 26, 2025. Jessie L. Chmielowski Gregory C. Wilson Commissioner Commissioner Gregory C. Wilson Digitally signed by Gregory C. Wilson Date: 2025.08.26 15:03:10 -08'00' Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2025.08.26 15:50:24 -08'00' AIO 4G.019 August 26, 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 Order 4G.019 (Hilcorp) Date:Wednesday, August 27, 2025 6:55:51 AM Attachments:AIO4G.019.pdf Docket Number: AIO-25-018 Request for Administrative Approval to Area Injection Order 4G: Water Only Injection Prudhoe Bay Unit L5-29 (PTD 1870450), Lisburne 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 INDEXES 38 Hilcorp North Slope, LLC Bo York, PBE Operations Manager 3800 Centerpoint Dr, Suite 1400 Anchorage, Alaska 99503 08/18/2025 Commissioners – Jesse Chmielowski, Greg Wilson Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage, Alaska 99501 Subject: Lisburne Well L5-29 (PTD #187045). Request for Administrative Approval to allow seawater injection operations. Dear Commissioner Chmielowski and Commissioner Wilson, Hilcorp North Slope, LLC requests administrative approval to allow for seawater injection into Lisburne well L5-29 with high-set packer. RWO operations were completed on 9/10/2023, under sundry # 322-724, where a PC leak located at 10821’ MD was isolated behind tubing, between 4.5”x 9.625” packers at 10678’ MD and 13142’ MD. This work reduced the monitorable inner annulus (IA) of the well and does not meet the requirement of 20 AAC 25.412(b) with the uppermost injection perforation located at 13585’ MD. The maximum anticipated injection pressure for L5-29 is approximately 1900 psi. An AOGCC witness offline MIT-IA passed to 3500 psi and MIT-T passed to 3250 psi on 9/10/2023 with a plug set at 13328’ MD. An AOGCC witnessed online MIT-IA passed to 2232 psi on 9/25/2023. Hilcorp North Slope, LLC has determined that well L5-29 is safe to operate in its current condition and requests administrative approval based on the following conditions: x Injection is isolated to the approved injection interval. x Passing pressure test of the primary and secondary barriers. x IA and OA pressures will be monitored with wireless pressure gauges. If you have any questions, please call me at 907-777-8345 or Oliver Sternicki at 907-564-4891. Sincerely, Bo York PBE Operations Manager Attachments Technical Justification TIO/ Injection Plot Wellbore Schematic By Samantha Coldiron at 12:04 pm, Aug 19, 2025 Digitally signed by Bo York (1248) DN: cn=Bo York (1248) Date: 2025.08.18 19:10:20 - 08'00' Bo York (1248) Lisburne Well L5-29 Technical Justification for Administrative Approval Request 08/18/2025 Well History and Status L5-29 was recompleted in 2008 as a seawater injector at L5 pad that injects into the Lisburne gas cap. The well acts as a shield from gas to the producers to the south. The well had been on consistent injection since it was converted in 2008; however, it had been patched multiple times to repair TxIA communication. The tubing patch was found to be leaking after a failed MIT-IA on 05/03/2020 with a LLR of 1.5 gpm at 2500 psi. The patch was pulled, and a series of subsequent LDLs were run which confirmed the presence of a tubing leak and a PC leak at 10,820’ MD. On 9/10/2023, under sundry # 322-724, RWO operations were completed isolating the PC leak behind tubing, between two 4.5”x 9.625” packers, at 10678’ MD and 13142’ MD. The uppermost injection perforation is located at 13585’ MD. The maximum anticipated injection pressure for L5-29 is approximately 1900 psi. An AOGCC witness offline MIT-IA passed to 3500 psi and MIT-T passed to 3250 psi on 09/10/2023 with a plug set at 13328’ MD. An AOGCC witnessed online MIT-IA passed to 2232 psi on 09/25/2023. Recent Well Events: 09/25/2025 Online AOGCC witnessed MIT-IA passed to 2232 psi. 09/10/2023 RWO completed. Offline AOGCC witnessed MIT-T passed to 3250 psi, MIT-IA passed to 3500 psi. 10/11/2022 LDL finds PC leak at 10820’ MD 05/03/2020 MIT-IA failed, well made not operable. 01/12/2019 AOGCC MIT-IA Passed to 2293 psi. Barrier and Hazard Evaluation The primary and secondary barriers systems consist of the tubing and production casing and associated hardware. The passing pressure tests conducted on 9/10/25, which tested both barriers, demonstrates competent primary and secondary barrier systems. Proposed Operating and Monitoring Plan 1. Record wellhead pressures and injection rates daily; 2. 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. Perform a MIT-IA every two years to the greater of the maximum anticipated wellhead injection pressure or 0.25 x packer TVD, but not less than 1,500 psi; 4. Perform a MIT-T every two years to the greater of the maximum anticipated wellhead injection pressure or 0.25 x packer TVD, but not less than 1,500 psi with a deep set plug; 5. Limit the well’s inner annulus operating pressure to 2,100 psi. Audible control room alarms shall be set at or below these limits; 6. 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. Monitor the inner and outer annulus pressures in real time with SCADA system; 8. 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; TIO/ Injection Plot Wellbore Schematic 37 Hilcorp North Slope, LLC Bo York, PBE Operations Manager 3800 Centerpoint Dr, Suite 1400 Anchorage, Alaska 99503 04/17/2025 Commissioners – Jesse Chmielowski, Greg Wilson Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage, Alaska 99501 Subject: Prudhoe Bay Well PAVE 3-1(PTD #224140). Request for Administrative Approval to allow Produce Water Injection Operations. Dear Commissioner Chmielowski and Commissioner Wilson, Hilcorp North Slope, LLC requests administrative approval to allow for produced water injection into Prudhoe Bay well PAVE 3-1 with high set injection packer. PAVE 3-1 was drilled as a produced water injector in the gravity drainage of the Ivishak. The original PTD was approved for running slotted liner in the production hole and to set the production packer at ~13500’ MD, which would fall within the requirements of 20 AAC 25.412(b) for packer setting depth. During the second stage cement job for the 9.625” intermediate casing, a cementing stage tool at 12242’ MD failed to close properly, resulting in a leak in the intermediate casing string. Multiple cement squeezes were executed to remediate the leaking cementing stage tool to allow drilling to move forward. The completion plan was changed at this time to isolate the leaking stage tool behind a cemented solid liner instead of risking a leak in the IA with the packer set below the leak at the original depth of ~13500’ MD. The well was completed with a cemented solid liner and the injection packer at 11805’ MD, the distance from the top of the pool (TSGR) to the packer is 2937’ MD. The injection packer at 11805’ MD was set post rig and a non-AOGCC witnessed MIT-T and MIT-IA passed to 2975 psi and 3215 psi on 3/19/25. A pre-injection AOGCC witnessed MIT-T and MIT-IA are planned in the next few weeks after completion of surface tie-in work associated with the well. Hilcorp North Slope, LLC has determined that well Pave 3-1 is safe to operate in its current condition and requests administrative approval for a variance to the packer depth requirement within 20 AAC 25.412(b) based on the following conditions: x Biennial MIT-T schedule to ensure injection is isolated to the approved injection interval. x Passing pressure test of the primary and secondary barriers. x IA and OA pressures will be monitored with wireless pressure gauges. Proposed Operating and Monitoring Plan 1. Record wellhead pressures and injection rates daily; 2. 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. Perform a MIT-IA every four years to the greater of the maximum anticipated wellhead injection pressure or 0.25 x packer TVD, but not less than 1,500 psi; 4. Perform a MIT-T every two years with a plug set in the 7” production liner below 13500’ MD to the greater of the maximum anticipated wellhead injection pressure or 0.25 x packer TVD, but not less than 1,500 psi; 5. Limit the well’s inner annulus operating pressure to 2,100 psi. Audible control room alarms shall be set at or below these limits; By Samantha Coldiron at 1:41 pm, Apr 17, 2025 6. 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. Monitor the inner and outer annulus pressures in real time with SCADA system; 8. 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 If you have any questions, please call me at 907-777-8345 or Oliver Sternicki at 907-564-4891. Sincerely, Bo York PBE Operations Manager Attachments Wellbore Schematic Digitally signed by Bo York (1248) DN: cn=Bo York (1248) Date: 2025.04.17 10:39:10 - 08'00' Bo York (1248) Wellbore Schematic 36 Hilcorp North Slope, LLC Bo York, PBE Operations Manager 3800 Centerpoint Dr, Suite 1400 Anchorage, Alaska 99503 03/12/2024 Chairman Brett Huber, Sr Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage, Alaska 99501 Subject: Prudhoe Well 03-07B (PTD #219182). Request for Administrative Approval to allow continued gas injection operations. Dear Chairman Huber, Hilcorp North Slope, LLC requests administrative approval to allow for continued gas injection into Prudhoe well 03-07B with slow tubing x inner annulus (IA) communication. Gas injection well 03-07B was initially flagged as having possible slow IA re-pressurization on 02/04/2024 while on Miscible Gas Injection (MI). The well was immediately reported to the AOGCC with a plan to continue monitoring the IA pressure for indication of tubing x inner annulus (IA) communication. On 02/14/2024, 03-07B was placed under evaluation and the AOGCC notified due to continuing IA repressurization trends. The tubing hanger passed a pressure test to 5000 psi on 02/19/2024. An AOGCC witness MIT-IA was conducted on 02/24/2024 and passed to 3,269 psi confirming the integrity of the primary and secondary well barriers. The maximum anticipated injection pressure for 03-07B is approximately 3,150 psi. Hilcorp North Slope, LLC has determined that well 03-07B is safe to operate in its current condition and requests administrative approval based on the following conditions: x IA pressure can be maintained below MOASP by managing the IA repressurization with periodic annular bleeds. x Passing pressure test of the primary and secondary barriers. x IA and OA pressures will be monitored with wireless pressure gauges. If you have any questions, please call me at 907-777-8345 or Oliver Sternicki at 907-564-4891. Sincerely, Bo York PBE Operations Manager Attachments Technical Justification TIO/ Injection Plot Wellbore Schematic By Samantha Coldiron at 12:57 pm, Mar 13, 2024 Digitally signed by Bo York (1248) DN: cn=Bo York (1248) Date: 2024.03.12 08:51:46 - 08'00' Bo York (1248) Prudhoe Well 03-07B Technical Justification for Administrative Approval Request 03/12/2024 Well History and Status Well 03-07A was a rig sidetrack drilled in 2004 as a water alternating gas (WAG) injector, well 03-07B was then drilled in 2020 as a thru tubing coil sidetrack for WAG service. The well was changed in late 2020 to a gas only MI injector. 03-07B was initially flagged as having possible slow IA re-pressurization on 02/04/2024 while on injection and was then placed under evaluation on 02/14/2024 due to continuing IA repressurization trends. The tubing hanger passed a pressure test to 5000 psi on 02/19/2024. An AOGCC witness MIT-IA was conducted on 02/24/2024 and passed to 3,269 psi. Recent Well Events: 04/03/2020 AOGCC MIT-IA passed to 2547 psi 02/04/2024 AOGCC notified of suspected IA repressurization. 02/14/2024 Well placed under evaluation. 02/19/2024 PPPOT-T passed to 5000 psi 02/24/2024 Online AOGCC witnessed MIT-IA passed to 3269 psi Barrier and Hazard Evaluation The primary and secondary barriers systems consist of the tubing and production casing and associated hardware. A passing online pressure test conducted on 02/24/2024, to 3,269 psi, which tested both barriers, demonstrates competent primary and secondary barrier systems. Due to the low IA repressurization rate, no logging or further repair attempt is planned at this time due to the low likelihood of locating the leak point. Proposed Operating and Monitoring Plan 1. Record wellhead pressures and injection rates daily; 2. 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. Perform a MITIA every two years to the greater of the maximum anticipated wellhead injection pressure or 0.25 x packer TVD, but not less than 1,500 psi; 4. Limit the well’s inner annulus operating pressure to 2,100 psi. Audible control room alarms shall be set at or below these limits; 5. Limit the well’s outer annulus operating pressure to 1,000 psi. Audible control room alarms shall be set at or below these limits; 6. Monitor the inner and outer annulus pressures in real time with SCADA system; 7. Install and maintain automatic shut-in equipment linked to the well’s IA pressure. Actuation pressure shall not exceed 2200 psi. Testing of the shut-in equipment (actuated valve and mechanical or electrical pressure detection device) shall be performed in conjunction with SVS testing. 8. 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; TIO/ Injection Plot Wellbore Schematic 35 Hilcorp North Slope, LLC Bo York, PBE Operations Manager 3800 Centerpoint Dr, Suite 1400 Anchorage, Alaska 99503 11/13/2023 Chairman Brett Huber, Sr Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage, Alaska 99501 Subject: Prudhoe Bay Well 17-13A (PTD #205020). Request for amendment to AIO 4G.011 to allow WAG injection operations. Dear Chairman Huber, Hilcorp North Slope, LLC requests amendment to AIO 4G.011 to allow for WAG injection into Prudhoe Bay well 17-13A with slow tubing x inner annulus (IA) communication. 17-13A currently operates under AIO 4G.011, approved 08/10/20 for continued water only injection with inner annulus (IA) re-pressurization. The AOGCC granted a trial period for Miscible Gas Injection (MI) after an AOGCC witnessed MIT-IA passed to 3187 psi 10/10/23. The passing pressure test confirms both the primary and secondary well barrier integrity. The well was placed on MI on 10/27/23 and the IA pressure has stabilized <200 psi while the injection pressure has maintained >3000 psi. Hilcorp North Slope, LLC has determined that well 17-13A is safe to operate in its current condition and requests an amendment to AIO 4G.011 for WAG injection based on the following: x IA pressure can be maintained below MOASP by managing the IA repressurization with periodic annular bleeds. x Passing pressure test of the primary and secondary barriers. x IA and OA pressures will be monitored with wireless pressure gauges. If you have any questions, please call me at 907-777-8345 or Oliver Sternicki at 907-564-4891. Sincerely, Bo York PBE Operations Manager Attachments Technical Justification TIO/ Injection Plot Wellbore Schematic Digitally signed by Bo York (1248) DN: cn=Bo York (1248) Date: 2023.11.13 14:08:26 - 09'00' Bo York (1248) Prudhoe Bay Well 17-13A Technical Justification for Administrative Approval Request 11/13/2023 Well History and Status Well 17-13A is a WAG injector that was originally drilled in January 1985 and sidetracked in April 2005. The well went under evaluation on 7/17/20 for IA re-pressurization and passed all diagnostics including an AOGCC witnessed MIT-IA to 2339 psi with the well online on 07/29/20. Administrative Approval was granted for water only injection with IA re-pressurization on 08/10/20. A trial period for MI was granted after an AOGCC witnessed MIT- IA passed on 10/10/23 to 3187 psi. The MI trial period commenced on 10/27/23 and no significant IA re- pressurization has been observed. Recent Well Events: 10/27/2023 MI trial started 10/10/2023 Online AOGCC MIT-IA passed to 3187 psi 08/10/2020 AIO 4G.011 approved for PWI only 08/05/2020 Online AOGCC MIT-IA passed to 2339 psi 07/18/2020 PPPOT-T passed 07/17/2020 Anomalous IA re-pressurization reported to the AOGCC 04/03/2018 Online AOGCC MIT-IA passed to 2451 psi. Barrier and Hazard Evaluation The primary and secondary barriers systems consist of the tubing and production casing and associated hardware. A passing online pressure test conducted on 10/10/23, to 3187 psi, which tested both barriers, demonstrates competent primary and secondary barrier systems. Due to the low IA repressurization rate, no logging or repair attempt is planned at this time due to the low likelihood of locating the leak point. Proposed Operating and Monitoring Plan 1. Record wellhead pressures and injection rates daily; 2. 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. Perform a MITIA every two years to the greater of the maximum anticipated wellhead injection pressure or 0.25 x packer TVD, but not less than 1,500 psi; 4. Limit the well’s inner annulus operating pressure to 2,100 psi. Audible control room alarms shall be set at or below these limits; 5. Limit the well’s outer annulus operating pressure to 1,000 psi. Audible control room alarms shall be set at or below these limits; 6. Monitor the inner and outer annulus pressures in real time with SCADA system; 7. Maintain the FS2 plant or Drill Site 17 manifold building remote shut down capability for 17-13A when on gas or miscible injectant (MI) operation. 8. 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; TIO/ Injection Plot Wellbore Schematic 34 Hilcorp North Slope, LLC Bo York, PBE Operations Manager 3800 Centerpoint Dr, Suite 1400 Anchorage, Alaska 99503 06/06/2023 Chairman Brett Huber, Sr. Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage, Alaska 99501 Subject: Prudhoe Well 04-11A (PTD# 193158). Request for Administrative Approval to continue Water Injection Operations. Dear Chairman Huber, Hilcorp North Slope, LLC requests administrative approval for continued water injection into Prudhoe well 04-11A with slow tubing by inner annulus (IA) repressurization. Water injector 04-11A was flagged for anomalous IA repressurization and bled on 5/31/2023. Continued repressurization was reported to the AOGCC on 06/01/2023 and the well was placed under evaluation. The well had a passing AOGCC witnessed online MIT-IA on 06/06/2023 to 2870 psi which confirms both the primary and secondary well barrier integrity. Hilcorp North Slope, LLC has determined that well 04-11A is safe to operate in its current condition and requests an AA for water injection based on the following: x MIT-IA passed to 2870 psi. x IA and OA pressures will be monitored with wireless pressure gauges. If you have any questions, please call me at 907-777-8345 or Oliver Sternicki at 907-564-4891. Sincerely, Bo York PBE Operations Manager Attachments Technical Justification TIO/ Injection Plot Wellbore Schematic Digitally signed by Bo York (1248) DN: cn=Bo York (1248) Date: 2023.06.07 07:09:05 -08'00' Prudhoe Well 04-11A Technical Justification for Administrative Approval Request 06/06/2023 Well History and Status Well 04-11 was originally drilled as a producer in February 1978 and sidetracked as a water injector in February 1994. 04-11A failed an MIT-IA in early 2003 and the well operated with TxIA communication beginning is July 2003 under sundry approval 303-176 and 303-252. An LDL on 7/21/2003 found a tubing leak at 9699’ MD. On 01/18/2008 the sundries were canceled at the request of the operator due to the well not meeting revised internal operating policy and the well was shut-in. In July 2008 a tubing patch was set across the known tubing leak depth, the well passed an AOGCC witnessed MIT-IA and was made Operable and placed online. Prior to the recent discovery of the IA pressure anomaly on 04-11A, the most recent AOGCC witnessed MIT-IA passed to 2368 psi on 09/20/2020. On 05/31/2023, 04-11A was flagged for slow IA repressurization and was then reported to the AOGCC and placed under evaluation on 06/1/2023. An online AOGCC witnessed MIT-IA passed to 2870 psi on 06/06/2023. Recent Well Events: 06/06/2023 AOGCC witnessed MIT-IA passed to 2870 psi. 06/05/2023 PPPOT-T passed to 5000 psi. 06/01/2023 Notification sent to the AOGCC, well placed under evaluation. 05/31//2023 IA repressurization identified, IA bled. 09/20/2020 AOGCC witnessed MIT-IA passed to 2368 psi. Barrier and Hazard Evaluation The primary and secondary barriers systems consist of the tubing and production casing and associated hardware. A passing pressure test of the inner annulus to 2870 psi on 06/06/2023, which tests both barriers, demonstrates competent primary and secondary barrier systems. No further diagnostics/ repair will be pursued at this time due to the low likelihood of being able to determine the leakage point based on the low repressurization rate. Proposed Operating and Monitoring Plan 1. Record wellhead pressures and injection rates daily; 2. 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. Perform a MITIA every two years to the greater of the maximum anticipated wellhead injection pressure or 0.25 x packer TVD, but not less than 1,500 psi; 4. Limit the well’s inner annulus operating pressure to 2,100 psi. Audible control room alarms shall be set at or below these limits; 5. Limit the well’s outer annulus operating pressure to 1,000 psi. Audible control room alarms shall be set at or below these limits; 6. Monitor the inner and outer annulus pressures in real time with its SCADA system; 7. Immediately shut in the well and notify the AOGCC if there is any change in the well's mechanical condition; 8. After well shut in due to a change in the well's mechanical condition, AOGCC approval shall be required to restart injection; TIO/ Injection Plot Wellbore Schematic 32 Hilcorp North Slope, LLC Bo York, PBE Operations Manager 3800 Centerpoint Dr, Suite 1400 Anchorage, Alaska 99503 03/14/2022 Mr. Jeremy Price, Chair Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage, Alaska 99501 Subject: Prudhoe Bay well WGI-02 (PTD# 179043). Request to allow continued gas injection operations with slow inner annulus by outer annulus communication. Dear Mr. Price, Hilcorp North Slope, LLC requests administrative approval for continued gas injection (GI) into Prudhoe Bay well WGI-02 (PTD# 179043) with slow inner annulus (IA) by outer annulus (OA) communication. No increase to Maximum Operating Annulus Surface Pressure (MOASP) is required. WGI-02 was reported to the AOGCC on 02/17/2022 at which time the well was placed under evaluation for suspected IA by OA pressure communication based on OA pressure trends. On 02/22/2022 a casing hanger pack-off test passed to 3500 psi. An offline AOGCC witnessed MIT- IA passed to 3722 psi on 03/13/2022. The passing MIT-IA confirms both the primary and secondary well barrier integrity. Hilcorp North Slope, LLC has determined that well WGI-02 is safe to operate in its current condition and requests administrative approval for continued GI service based on the following: x OA pressure can be maintained below MOASP by managing the OA repressurization with periodic annular bleeds. x MIT-IA passed to 3722 psi. x IA and OA pressures will be monitored with wireless pressure gauges. If you have any questions, please call me at 907-777-8345 or Oliver Sternicki at 907-564-4891. Sincerely, Bo York PBE Operations Manager Attachments TIO/ Injection Plot Wellbore Schematic By Grace Salazar at 2:14 pm, Mar 14, 2022 Digitally signed by Bo York (1248) DN: cn=Bo York (1248), ou=Users Date: 2022.03.14 09:57:58 -08'00' Bo York (1248) Prudhoe Bay Well WGI-02 Technical Justification for Administrative Approval Request 03/14/2022 Well History and Status WGI-02 is a GI well that was originally drilled in 1979 and worked over in 1989. In 2015 a non- witnessed MIT-IA passed to 3606 psi with the well shut-in. The most recent AOGCC witnessed online MIT-IA passed to 2472 psi on 07/06/2018. In 2020 WGI-02 was made under evaluation for IA repressurization and reported to the AOGCC. The repressurization was found to be TxIA communication through the SSSV nipple and replacement of the A-1 injection valve resolved the issue. On 02/17/2022 the OA pressure plots showed signs of repressurization, the well was placed under evaluation and the AOGCC was notified. On 02/22/2022 a PPPOT-IC passed to 3500 psi. In support of this AA request an offline AOGCC witnessed MIT-IA passed to 3722 psi on 03/13/2022 with the tubing loaded (1% KCl) and a plug set in the tubing tail. The highest recorded tubing injection pressure in the last 12 months was 3700 psi. Recent Well Events: 03/13/2022 AOGCC witnessed offline MIT-IA passed to 3722psi. 03/13/2022 Pull SSSV, load tubing with 1% KCL, set TTP. 02/22/2022 Casing hanger pack-off test passed to 3500 psi. 02/17/2022 Under Eval for OA repressurization, AOGCC notified. 07/22/2020 IA repressurization repaired, well made Operable. 07/12/2020 SSSV replaced. 07/06/2020 GX sealant job pumped. 07/03/2020 Under Eval for IA repressurization, AOGCC notified. 07/06/2018 Online AOGCC witnessed MIT-IA passed to 2472 psi. Barrier and Hazard Evaluation The primary and secondary barriers systems consist of the tubing and production casing and associated hardware. A passing pressure test of the inner annulus to 3722 psi on 03/13/2022, which tests both barriers, demonstrates competent primary and secondary barrier systems. No further diagnostics/ repair attempts are proposed at this time. The annuli well pressure transmitters are set to alert the board operator with audio/visual warnings via SCADA if the annuli pressures exceed the high and high-high set point. In this situation the board operator will notify the pad operator when the high set point has been reached and the pad operator will bleed the pressures or shut the well in as needed. The well annuli pressure alerts are set as follows: Annulus High High-High (MOASP) IA 1000 2100 OA 500 1000 Pressure on the outer annulus will be maintained below MOASP of 1000 psi when the well is on-line with periodic bleeds of the OA. Proposed Operating and Monitoring Plan 1. Record wellhead pressures and injection rate daily. 2. Submit a report monthly of well pressures, injection rates and bleeds to the AOGCC. 3. Perform a MIT-IA every 2 years to the greater of the maximum anticipated injection pressure or 0.25 x packer TVD, but not less than 1500 psi. 4. IA MOASP= 2100 psi, OA MOASP= 1000 psi with audible control room alerts set at or below these limits. 5. IA and OA pressures will be monitored with wireless pressure gauges through SCADA system. 6. The well will be shut-in and the AOGCC notified if there is any change in the wells mechanical condition. 7. After well shut-in due to a change in the well’s mechanical condition, AOGCC approval shall be required to restart injection. TIO/ Injection Plots Wellbore Schematic From:PB Wells Integrity To:Wallace, Chris D (OGC) Cc:Regg, James B (OGC); Bo York; Oliver Sternicki Subject:RE: [EXTERNAL] RE: UPDATE UNDER EVALUATION: Gas Injector WGI-02 (PTD #1790430) IAxOA communication Date:Friday, March 18, 2022 1:36:27 PM Attachments:image001.png image002.png image003.png MIT PBU WGI-02 03-13-22.xlsx Mr. Wallace – Please see attached 10-426 for AOGCC MIT-IA conducted on WGi-02 03/13/22. Thanks, Ryan Holt Hilcorp Alaska LLC Field Well Integrity / Compliance Ryan.Holt@Hilcorp.com P: (907) 659-5102 M: (907) 232-1005 From: Wallace, Chris D (OGC) <chris.wallace@alaska.gov> Sent: Friday, March 18, 2022 10:04 AM To: PB Wells Integrity <PBWellsIntegrity@hilcorp.com> Cc: Regg, James B (OGC) <jim.regg@alaska.gov>; Bo York <byork@hilcorp.com>; Oliver Sternicki <Oliver.Sternicki@hilcorp.com> Subject: [EXTERNAL] RE: UPDATE UNDER EVALUATION: Gas Injector WGI-02 (PTD #1790430) IAxOA communication Ryan, Please provide the mentioned MITIA of 03/13/2022 on the Form 10-426, to the distribution list, so we may add to our database and progress the admin approval for this well. 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: Wallace, Chris D (OGC) Sent: Wednesday, March 16, 2022 10:11 AM To: PB Wells Integrity <PBWellsIntegrity@hilcorp.com> Cc: Regg, James B (OGC) <jim.regg@alaska.gov>; Bo York <byork@hilcorp.com>; Oliver Sternicki <Oliver.Sternicki@hilcorp.com> Subject: RE: UPDATE UNDER EVALUATION: Gas Injector WGI-02 (PTD #1790430) IAxOA communication Ryan, We have received the AA request and you are approved for continued gas injection while we process this. 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 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. 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: PB Wells Integrity <PBWellsIntegrity@hilcorp.com> Sent: Wednesday, March 16, 2022 9:43 AM To: Wallace, Chris D (OGC) <chris.wallace@alaska.gov> Cc: Regg, James B (OGC) <jim.regg@alaska.gov>; Bo York <byork@hilcorp.com>; Oliver Sternicki <Oliver.Sternicki@hilcorp.com> Subject: UPDATE UNDER EVALUATION: Gas Injector WGI-02 (PTD #1790430) IAxOA communication Mr. Wallace, Gas Injector WGI-02 (PTD # 1790430) passed AOGCC witnessed MIT-IA on 03/13/22. An AA request has been submitted. With permission, we would like to extend the UNDER EVALUATION period and keep the well on gas injection as needed until the AA request has been reviewed by the AOGCC. Please call with any questions or concerns. Ryan Holt Hilcorp Alaska LLC Field Well Integrity / Compliance Ryan.Holt@Hilcorp.com P: (907) 659-5102 M: (907) 232-1005 From: PB Wells Integrity Sent: Thursday, February 17, 2022 5:27 PM To: chris.wallace@alaska.gov Cc: Regg, James B (CED) <jim.regg@alaska.gov>; Bo York <byork@hilcorp.com>; Oliver Sternicki <Oliver.Sternicki@hilcorp.com> Subject: UNDER EVALUATION: Gas Injector WGI-02 (PTD #1790430) IAxOA communication Mr. Wallace, Gas Injector WGI-02 (PTD # 1790430) has been found to have probable slow IAxOA communication. OA pressure trends with IA pressure / temp rate swings but also has a buildup rate of ~5 psi / day. At this time, the well is classified as UNDER EVALUATION and on a 28 day clock to be resolved. Plan Forward: 1. Downhole Diagnostics: PPPOT-IC; OA re-pressurization test 2. Well Integrity: Further action as required Please call with any questions or concerns. Ryan Holt Hilcorp Alaska LLC Field Well Integrity / Compliance Ryan.Holt@Hilcorp.com P: (907) 659-5102 M: (907) 232-1005 From: Alaska NS - PB - Field Well Integrity <PBFieldWellIntegrity@hilcorp.com> Sent: Wednesday, July 22, 2020 9:30 AM To: chris.wallace@alaska.gov Cc: Regg, James B (CED) <jim.regg@alaska.gov>; Stan Golis <sgolis@hilcorp.com>; Bo York <byork@hilcorp.com>; Aras Worthington <Aras.Worthington@hilcorp.com>; Oliver Sternicki <Oliver.Sternicki@hilcorp.com>; Travis Smith - (C) <Travis.Smith@hilcorp.com> Subject: OPERABLE: Gas Injector WGI-02 (PTD #1790430) TxIA mitigated with oversized packing on SSSV Mr. Wallace, Gas Injector WGI-02 (PTD # 1790430) was made Under Evaluation on 07/03/20 to address TxIA communication. On 07/12/20 Slickline replaced the A1 Injection Valve with oversized-Freudenberg packing to mitigate communication through the control and balance lines. Follow up monitors confirm the TxIA has been mitigated and the well is now re-classified back to OPERABLE. Please respond with any questions. Andy Ogg Hilcorp Alaska LLC Field Well Integrity / Compliance andrew.ogg@hilcorp.com P: (907) 659-5102 M: (307)399-3816 From: Alaska NS - PB - Field Well Integrity Sent: Friday, July 3, 2020 6:31 PM To: Bo York <byork@hilcorp.com>; Stan Golis <sgolis@hilcorp.com>; Jennifer Blake <Jennifer.Blake@hilcorp.com>; John Menke <jmenke@hilcorp.com>; George Ivie <givie@hilcorp.com>; David Bjork <David.Bjork@hilcorp.com>; 'chris.wallace@alaska.gov' <chris.wallace@alaska.gov> Cc: Oliver Sternicki <Oliver.Sternicki@hilcorp.com>; Aras Worthington <Aras.Worthington@hilcorp.com>; Patrick Bixby <Corey.Bixby@hilcorp.com>; 'jim.regg@alaska.gov' <jim.regg@alaska.gov> Subject: UNDER EVALUATION: Injector WGI-02 (PTD #1790430) Slow Tubing x Inner Annulus Communication All – Injector WGI-02 (PTD #1790430) has been found to have slow tubing x inner annulus communication. IA pressure was bled on 7/1/20 from 730 psi to 290 psi and subsequent monitoring indicates ~40 psi / day build up rate with steady injection rate and temperature. The well is now classified as Under Evaluation and on a 28 day clock to be resolved. Plan Forward: 1. Downhole Diagnostics: Flush control / balance lines and pump GX Sealant 2. Downhole Diagnostics: Monitor IA re-pressurization 3. Well Integrity: Additional corrective action as required. A 90 day injection rate / pressure and TIO plot have been included for reference however it does not show the most recent bleed event due to network outage. Please call with any questions or concerns. Ryan Holt Hilcorp Well Integrity / Compliance 907-659-5102 The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptlyand permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or useof this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptlyand permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or useof this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. Submit to: OPERATOR: FIELD / UNIT / PAD: DATE: OPERATOR REP: AOGCC REP: Well Pressures:Pretest Initial 15 Min.30 Min.45 Min.60 Min. PTD 1790430 Type Inj N Tubing 780 1173 1169 1165 1161 Type Test P Packer TVD 7541 BBL Pump 4.7 IA 508 3753 3741 3730 3722 Interval O Test psi 1885 BBL Return 4.6 OA 191 195 195 195 195 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: Hilcorp Alaska LLC Prudhoe Bay / PBU / WGI Pad Matt Herrera Matt Ross 03/13/22 Notes:AOGCC MIT-IA for AA request slow IAxOA communication Notes: Notes: Notes: WGI-02 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION Mechanical 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)MIT PBU WGI-02 03-13-22 (002) 31 Hilcorp North Slope, LLC Bo York, PBE Operations Manager 3800 Centerpoint Dr, Suite 1400 Anchorage, Alaska 99503 02/21/2022 Mr. Jeremy Price, Chair Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage, Alaska 99501 Subject: Prudhoe Bay well NGI-12 (PTD# 177081). Request to allow continued gas injection operations with slow tubing by inner annulus communication. Dear Mr. Price, Hilcorp North Slope, LLC requests administrative approval for continued gas injection (GI) into Prudhoe Bay well NGI-12 (PTD# 177081) with slow tubing by inner annulus communication. No increase to Maximum Operating Annulus Surface Pressure (MOASP) is required. NGI-12 was reported to the AOGCC on 01/20/2022 at which time the well was placed under evaluation for suspected slow tubing by inner annulus pressure communication based on IA pressure trends. On 01/23/2022 a tubing hanger pack-off test passed to 5000 psi. An offline AOGCC witnessed MIT-IA passed to 3645 psi on 02/10/2022. The passing MIT-IA confirms both the primary and secondary well barrier integrity. Hilcorp North Slope, LLC has determined that well NGI-12 is safe to operate in its current condition and requests administrative approval for continued GI service based on the following: x IA pressure can be maintained below MOASP by managing the IA repressurization with periodic annular bleeds. x MIT-IA passed to 3645 psi. x IA and OA pressures will be monitored with wireless pressure gauges. If you have any questions, please call me at 907-777-8345 or Oliver Sternicki at 907-564-4891. Sincerely, Bo York PBE Operations Manager Attachments TIO/ Injection Plot Wellbore Schematic By Grace Salazar at 3:20 pm, Feb 23, 2022 Digitally signed by Bo York (1248) DN: cn=Bo York (1248), ou=Users Date: 2022.02.23 12:16:50 -09'00' Bo York (1248) Prudhoe Bay Well NGI-12 Technical Justification for Administrative Approval Request 02/21/2022 Well History and Status NGI-12 is a GI well that was originally drilled in 1978 and worked over in 1987. Slow IA repressurization was previously reported to the AOGCC on 05/17/2021 at which time a GX sealant job was conducted on the control and balance SSSV lines. After an extended monitoring period ending 07/07/2021, the IA repressurization had not continued and the well was made operable. The most recent AOGCC witnessed online MIT-IA passed to 2591 psi on 08/15/2021. On 01/20/2022 the IA pressure trend showed signs of repressurization and the well was again placed under evaluation and the AOGCC was notified. On 01/23/2022 a PPPOT-T passed to 5000 psi and GX sealant was pumped into the control and balance SSSV lines. In support of this AA request an offline AOGCC witnessed MIT-IA passed to 3645 psi on 02/10/2022 with the tubing loaded (1% KCl) and a plug set in the tubing tail. As part of this work the SSSV was pulled and replaced. The slow IA repressurization continued after this work was completed. Recent Well Events: 02/11/2022 Pull lug, set new SSSV. 02/10/2022 AOGCC witnessed offline MIT-IA passed to 3645 psi. 02/05/2022 Pull SSSV, load tubing with 1% KCL, set TTP. 01/23/2022 PPPOT-T passed to 5000 psi. 01/20/2022 Under Eval for IA repressurization, AOGCC notified. 08/15/2021 AOGCC witnessed MIT-IA passed to 2591 psi on GI. 07/07/2021 Operable after extended monitoring. 05/17/2021 Under Eval for IA repressurization, AOGCC notified, GX sealant job pumped. Barrier and Hazard Evaluation The primary and secondary barriers systems consist of the tubing and production casing and associated hardware. A passing pressure test of the inner annulus to 3645 psi on 02/10/2022, which tests both barriers, demonstrates competent primary and secondary barrier systems. No further diagnostics/ repair attempts are proposed at this time. Pressure on the inner annulus will be maintained below MOASP of 2100 psi when the well is on-line with periodic bleeds of the IA. Proposed Operating and Monitoring Plan 1. Record wellhead pressures and injection rate daily. 2. Submit a report monthly of well pressures and injection rates to the AOGCC. 3. Perform a MIT-IA every 2 years to the greater of the maximum anticipated injection pressure or 0.25 x packer TVD, but not less than 1500 psi. 4. IA MOASP= 2100 psi, OA MOASP= 1000 psi. 5. IA and OA pressures will be monitored with wireless pressure gauges through SCADA system. 6. The well will be shut-in and the AOGCC notified if there is any change in the wells mechanical condition. 7. After well shut-in due to a change in the well’s mechanical condition, AOGCC approval shall be required to restart injection. TIO/ Injection Plots Wellbore Schematic 1 Carlisle, Samantha J (OGC) From:PB Wells Integrity <PBWellsIntegrity@hilcorp.com> Sent:Thursday, February 24, 2022 2:55 PM To:Wallace, Chris D (OGC); PB Wells Integrity Cc:Oliver Sternicki Subject:RE: [EXTERNAL] FW: Request to keep Gas Injector NGI-12 (PTD #1770810) online while AA is processed Mr. Wallace, That is correct, for NGI‐12, we do not see any added value in increasing the MOASP to 2500 psi. Thanks, Andy From: Wallace, Chris D (OGC) <chris.wallace@alaska.gov> Sent: Thursday, February 24, 2022 1:09 PM To: PB Wells Integrity <PBWellsIntegrity@hilcorp.com> Cc: Oliver Sternicki <Oliver.Sternicki@hilcorp.com> Subject: [EXTERNAL] FW: Request to keep Gas Injector NGI‐12 (PTD #1770810) online while AA is processed Andy, I also see the max IA requested is 2100 psi whereas other admin approved NGI wells are at 2500 psi? Thanks, From: Wallace, Chris D (OGC) Sent: Thursday, February 24, 2022 11:37 AM To: PB Wells Integrity <PBWellsIntegrity@hilcorp.com> Cc: Regg, James B (OGC) <jim.regg@alaska.gov>; Oliver Sternicki <Oliver.Sternicki@hilcorp.com>; Bo York <byork@hilcorp.com> Subject: RE: Request to keep Gas Injector NGI‐12 (PTD #1770810) online while AA is processed Andy, Continued gas injection while the AA is being processed is approved. For our records, please detail the shut down functionality associated with this well/pad. I am interested in what high and high high alarms are set at for the annuli and what procedure is in place if the alarms are tripped? I am interested in what shutdown procedure/functionality is in place either at the pad or remotely from the central control room. Can the control room shut in the well separately or do all pad injectors get shut down in the event of the control room seeing the NGI‐12 alarms? I would put the maximum anticipated injection pressure at 3500 psi from the TIO plot but if you have a better number please let me know. 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 1 Carlisle, Samantha J (OGC) From:PB Wells Integrity <PBWellsIntegrity@hilcorp.com> Sent:Thursday, February 24, 2022 2:52 PM To:Wallace, Chris D (OGC); PB Wells Integrity Cc:Regg, James B (OGC); Oliver Sternicki; Bo York Subject:RE: [EXTERNAL] RE: Request to keep Gas Injector NGI-12 (PTD #1770810) online while AA is processed Chris, The Well/Pad does not have remote shut‐in capability. The annuli have audio/visual alarms that alert the board operator via SCADA when the pressures exceed the high and high‐high set point. The board operator will notify the pad operator when the high set point has been reached and the pad operator will bleed the pressures or shut the well in as needed. The alarm set points for the annuli are as follows: Annulus High High‐High (MOASP) IA 1000 2100 OA 500 1000 3500 psi is correct. Going back 1‐year, the highest Injection pressure recorded on daily reads was 3470 psi. Let me know if you have any more questions. Andy Ogg Hilcorp Alaska LLC Field Well Integrity / Compliance andrew.ogg@hilcorp.com P: (907) 659‐5102 M: (307)399‐3816 From: Wallace, Chris D (OGC) <chris.wallace@alaska.gov> Sent: Thursday, February 24, 2022 11:37 AM To: PB Wells Integrity <PBWellsIntegrity@hilcorp.com> Cc: Regg, James B (OGC) <jim.regg@alaska.gov>; Oliver Sternicki <Oliver.Sternicki@hilcorp.com>; Bo York <byork@hilcorp.com> Subject: [EXTERNAL] RE: Request to keep Gas Injector NGI‐12 (PTD #1770810) online while AA is processed Andy, Continued gas injection while the AA is being processed is approved. For our records, please detail the shut down functionality associated with this well/pad. I am interested in what high and high high alarms are set at for the annuli and what procedure is in place if the alarms are tripped? I am interested in what shutdown procedure/functionality is in place either at the pad or remotely from the central control room. Can the control room shut in the well separately or do all pad injectors get shut down in the event of the control room seeing the NGI‐12 alarms? I would put the maximum anticipated injection pressure at 3500 psi from the TIO plot but if you have a better number please let me know. 1 Carlisle, Samantha J (OGC) From:Wallace, Chris D (OGC) Sent:Thursday, February 24, 2022 11:37 AM To:PB Wells Integrity Cc:Regg, James B (OGC); Oliver Sternicki; Bo York Subject:RE: Request to keep Gas Injector NGI-12 (PTD #1770810) online while AA is processed Andy, Continued gas injection while the AA is being processed is approved. For our records, please detail the shut down functionality associated with this well/pad. I am interested in what high and high high alarms are set at for the annuli and what procedure is in place if the alarms are tripped? I am interested in what shutdown procedure/functionality is in place either at the pad or remotely from the central control room. Can the control room shut in the well separately or do all pad injectors get shut down in the event of the control room seeing the NGI‐12 alarms? I would put the maximum anticipated injection pressure at 3500 psi from the TIO plot but if you have a better number please let me know. 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: PB Wells Integrity <PBWellsIntegrity@hilcorp.com> Sent: Thursday, February 24, 2022 10:16 AM To: Wallace, Chris D (OGC) <chris.wallace@alaska.gov> Cc: Regg, James B (OGC) <jim.regg@alaska.gov>; Oliver Sternicki <Oliver.Sternicki@hilcorp.com>; Bo York <byork@hilcorp.com> Subject: Request to keep Gas Injector NGI‐12 (PTD #1770810) online while AA is processed Mr. Wallace, Hilcorp submitted an AA request on 02/23/22 for continued Gas Injection on NGI‐12 (PTD #1770810) with slow TxIA communication. Hilcorp is requesting your approval to keep NGI‐12 (PTD #1770810) on Gas Injection until the AA is processed. Please let me know if you have any questions. Andy Ogg 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. 2 Hilcorp Alaska LLC Field Well Integrity / Compliance andrew.ogg@hilcorp.com P: (907) 659‐5102 M: (307)399‐3816 From: PB Wells Integrity Sent: Saturday, February 12, 2022 7:37 AM To: 'chris.wallace@alaska.gov' <chris.wallace@alaska.gov> Cc: 'Regg, James B (CED)' <jim.regg@alaska.gov>; Oliver Sternicki <Oliver.Sternicki@hilcorp.com>; Bo York <byork@hilcorp.com> Subject: UPDATE UNDER EVALUATION: Gas Injector NGI‐12 (PTD #177081) Slow TxIA communication Mr. Wallace, Injector NGI‐12 (PTD #177081) passed AOGCC MIT‐IA on 02/10/22 and SSSV has been re‐installed. Our current plan forward is to monitor re‐pressurization while online for an additional 14 days and decide at that point based on the results weather to apply for AA for continued injection or if the TxIA communication has been resolved. Please call with any questions or concerns. Ryan Holt Hilcorp Alaska LLC Field Well Integrity / Compliance Ryan.Holt@Hilcorp.com P: (907) 659‐5102 M: (907) 232‐1005 From: PB Wells Integrity Sent: Thursday, January 20, 2022 1:15 PM To: chris.wallace@alaska.gov Cc: Regg, James B (CED) <jim.regg@alaska.gov>; Oliver Sternicki <Oliver.Sternicki@hilcorp.com>; Bo York <byork@hilcorp.com> Subject: UNDER EVALUATION: Gas Injector NGI‐12 (PTD #177081) Slow TxIA communication Mr. Wallace, Injector NGI‐12 (PTD #177081) is suspected to have slow TxIA communication <5 psi / day as evidenced by daily pressure monitoring and a 40’ liquid level in the IA. The well is now classified as UNDER EVALUATION and will remain online for diagnostics / corrective action. Plan forward: 1.Downhole diagnostics: Packoff test tubing / GX sealant control & balance lines. 2.Well Integrity: Monitoring / further action as needed. Please call with any questions or concerns. Ryan Holt Hilcorp Alaska LLC Field Well Integrity / Compliance Ryan.Holt@Hilcorp.com P: (907) 659‐5102 3 M: (907) 232‐1005 From: Alaska NS ‐ PB ‐ Field Well Integrity <PBFieldWellIntegrity@hilcorp.com> Sent: Wednesday, July 7, 2021 3:46 PM To: Alaska NS ‐ PB ‐ Field Well Integrity <PBFieldWellIntegrity@hilcorp.com>; chris.wallace@alaska.gov Cc: Regg, James B (CED) <jim.regg@alaska.gov>; Oliver Sternicki <Oliver.Sternicki@hilcorp.com>; John Condio ‐ (C) <John.Condio@hilcorp.com>; Alaska NS ‐ PB ‐ Field Well Integrity <PBFieldWellIntegrity@hilcorp.com> Subject: RE: UPDATE: OPERABLE: Gas Injector NGI‐12 (PTD #177081) extend monitoring period after GX pumping Mr. Wallace, DHD pumped a GX sealant job on 05/18/21 into the Control and Balance SSSV lines and during the subsequent extended monitoring period the IA has not demonstrated any re‐pressurization. The well is now classified as OPERABLE. Please respond with any questions. Aras Worthington Hilcorp Alaska LLC Well Integrity Engineer, PE Aras.worthington@hilcorp.com 907.564.4763 907.440.7692 mobile 4 From: Alaska NS ‐ PB ‐ Field Well Integrity <PBFieldWellIntegrity@hilcorp.com> Sent: Monday, June 14, 2021 10:34 AM To: chris.wallace@alaska.gov Cc: Regg, James B (CED) <jim.regg@alaska.gov>; Aras Worthington <Aras.Worthington@hilcorp.com>; Oliver Sternicki <Oliver.Sternicki@hilcorp.com>; John Condio ‐ (C) <John.Condio@hilcorp.com>; Alaska NS ‐ PB ‐ Field Well Integrity <PBFieldWellIntegrity@hilcorp.com> Subject: UPDATE: UNDER EVALUATION: Gas Injector NGI‐12 (PTD #177081) extend monitoring period after GX pumping Mr. Wallace, DHD pumped the GX sealant job on 05/18/21 and during the subsequent monitoring period, the IA has not demonstrated any re‐pressurization. However, due to the slow nature of re‐pressurization when the well was initially reported, the Under Evaluation period will be extended for continued monitoring. Please respond with any questions. Andy Ogg Hilcorp Alaska LLC 5 Field Well Integrity / Compliance andrew.ogg@hilcorp.com P: (907) 659‐5102 M: (307)399‐3816 From: Alaska NS ‐ PB ‐ Field Well Integrity <PBFieldWellIntegrity@hilcorp.com> Sent: Monday, May 17, 2021 12:57 PM To: chris.wallace@alaska.gov Cc: Regg, James B (CED) <jim.regg@alaska.gov>; Aras Worthington <Aras.Worthington@hilcorp.com>; Oliver Sternicki <Oliver.Sternicki@hilcorp.com>; John Condio ‐ (C) <John.Condio@hilcorp.com>; Alaska NS ‐ PB ‐ Field Well Integrity <PBFieldWellIntegrity@hilcorp.com> Subject: UNDER EVALUATION: Gas Injector NGI‐12 (PTD #177081) slow IA re‐pressurization Mr. Wallace, Gas Injector NGI‐12 (PTD # 177081) has been identified to have a slow IA re‐pressurization trend. A possible source of the re‐pressurization could be from a Wireline Retrievable SSSV that was set in November of 2020. The well is now classified as UNDER EVALUATION and is on the 28‐day clock for diagnostics. Plan Forward: 1.DHD: Pump GX sealant down control line 2.DHD: Monitor for BUR post GX pumping 6 3.Well Integrity: Additional diagnostics as needed Please respond with any questions. Andy Ogg Hilcorp Alaska LLC Field Well Integrity / Compliance andrew.ogg@hilcorp.com P: (907) 659‐5102 M: (307)399‐3816 The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. 30 Hilcorp North Slope, LLC Bo York, PBE Operations Manager 3800 Centerpoint Dr, Suite 1400 Anchorage, Alaska 99503 01/25/2022 Mr. Jeremy Price, Chair Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage, Alaska 99501 Subject: Point McIntyre Well P1-01 (PTD# 190027).Request to allow continued WAG injection operations with slow tubing by inner annulus communication. Dear Mr. Price, Hilcorp North Slope, LLC requests administrative approval for continued WAG injection into Point McIntyre well P1-01 (PTD# 190027) with slow tubing by inner annulus communication. No increase to Maximum Operating Annulus Surface Pressure (MOASP) is required. P1-01 was found to have slow tubing by inner annulus pressure communication and was reported to the AOGCC on 01/18/2022 at which time the well was placed under evaluation. On 01/19/2022 a tubing hanger pack-off test passed to 4850 psi and a non-state witnessed MIT-IA passed to 3986 psi with the well on MI. The passing MIT-IA confirms both the primary and secondary well barrier integrity. Hilcorp North Slope, LLC has determined that well P1-01 is safe to operate in its current condition and requests administrative approval for continued WAG service based on the following: x IA pressure can be maintained below MOASP by managing the IA repressurization with periodic annular bleeds. x MIT-IA passed to 3986 psi. x IA and OA pressures will be monitored with wireless pressure gauges. If you have any questions, please call me at 907-777-8345 or Oliver Sternicki at 907-564-4891. Sincerely, Bo York PBE Operations Manager Attachments TIO/ Injection Plot Wellbore Schematic By Grace Salazar at 3:26 pm, Jan 25, 2022 Digitally signed by Bo York DN: cn=Bo York, c=US, o=HIlcorp Alaska LLC, ou=Alaska North Slope, email=byork@hilcorp.com Date: 2022.01.25 12:46:04 -09'00' Bo York Point McIntyre Well P1-01 Technical Justification for Administrative Approval Request 01/25/2022 Well History and Status P1-01 was originally drilled in April 1990 as an oil well and was then converted to an injector in 1994. The most recent AOGCC witnessed MIT-IA for P1-01 passed to 2302 psi on 11/27/2020 while on PWI service. On 9/14/2021 the well was swapped from produced water to MI service. On 01/18/2022 P1-01 was found to have slow tubing by IA pressure communication and was reported to the AOGCC and placed under evaluation. A passing MIT-IA was conducted on 01/19/2022 to 3986 psi while on MI. Recent Well Events: 01/19/2022 MIT-IA passed to 3986 psi on MI. 01/19/2022 PPPOT-T Passed to 4850 psi. 01/18/2022 TxIA pressure communication noted and notification sent to the AOGCC. 11/27/2020 AOGCC witnessed MIT-IA passed to 2302 psi on PWI. Barrier and Hazard Evaluation The primary and secondary barriers systems consist of the tubing and production casing and associated hardware. A passing pressure test of the inner annulus to 3986 psi on 01/19/2021, which tests both barriers, demonstrates competent primary and secondary barrier systems. No further diagnostics/ repair attempts are proposed at this time. Pressure on the inner annulus will be maintained below MOASP of 2100 psi when the well is on-line with periodic bleeds of the IA. Proposed Operating and Monitoring Plan 1. Record wellhead pressures and injection rate daily. 2. Submit a report monthly of well pressures and injection rates to the AOGCC. 3. Perform a MIT-IA every 2 years to the greater of the maximum anticipated injection pressure or 0.25 x packer TVD, but not less than 1500 psi. 4. IA MOASP= 2100 psi, OA MOASP= 1000 psi 5. The well will be shut-in and the AOGCC notified if there is any change in the wells 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. TIO/ Injection Plots Wellbore Schematic Submit to: OPERATOR: FIELD / UNIT / PAD: DATE: OPERATOR REP: AOGCC REP: Well Pressures:Pretest Initial 15 Min.30 Min.45 Min.60 Min. PTD 1900270 Type Inj G Tubing 3220 3249 3260 3247 Type Test P Packer TVD 8356 BBL Pump 6.7 IA 1010 4000 3989 3979 Interval O Test psi 2089 BBL Return 0.0 OA 0 0 0 0 Result I Well Pressures:Pretest Initial 15 Min.30 Min.45 Min.60 Min. PTD 1900270 Type Inj G Tubing 3247 3229 3221 3228 Type Test P Packer TVD 8356 BBL Pump 0.1 IA 3979 4000 3991 3986 Interval O Test psi 2089 BBL Return 5.9 OA 0 0 0 0 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 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: STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION Mechanical Integrity Test jim.regg@alaska.gov;AOGCC.Inspectors@alaska.gov;phoebe.brooks@alaska.gov chris.wallace@alaska.gov Notes:Pressured back up to 4000 psi and started new test. Notes: Notes: Hilcorp North Slope, LLC Prudhoe Bay / PBU / PM1 Non-Witnessed Ryan Holt 01/19/22 Notes:Well is Under Evaluation for TxIA communication. AA request will be pursued with passing MIT-IA. Did not bleed. Pressured back up to start test again. See second test for bleed back volume. Notes: Notes: Notes: P1-01 P1-01 Form 10-426 (Revised 01/2017)MIT PBU P1-01 01-19-21 29 'FHE STATE 'ALASKA October 21, 2021 GOVERNOR MIKE. DUNLEAVY Mr. Stan Golis, PBW Operations Manager Hilcorp North Slope, LLC 3800 Centerpoint Dr., Suite 1400 Anchorage, AK 99503 Alaska Oil and Gas Conservation Commission Re: Docket OTH-21-039 Investigation of Late Mechanical Integrity Test (MIT) Prudhoe Bay Unit W-44 (PTD 1891000) Area Injection Order (AIO) 4G Prudhoe Bay Unit (PBU), Prudhoe Oil Pool Dear Mr. Golis: 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.alaska.gov Pursuant to 20 AAC 25.300, by letter dated October 6, 2021, the AOGCC requested the following additional information be provided by Hilcorp North Slope, LLC regarding its operations and operation of PBU W-44. 1. 12 -month Tubing, Inner Annulus, and Outer Annulus (TIO) raw data (excel format) and pressure plot identifying TIO pressures, injection rate, injection temperatures, and any bleed events of W-44; 2. A timeline of well events since a passing state -witnessed MITIA on July 16, 2017 to present, including correspondence with AOGCC, if any, on scheduling the MIT or postponing the test; 3. Full root cause analysis, including results and conclusions, addressing the failure to perform the required MIT during the due month of July 2021; and 4. Results of a review of each of the Hilcorp injectors authorized by AIO 4G specifically to the MIT due date and identification of any wells that are out of compliance with test dates. This was subsequently amended by AOGCC to focus solely on W pad wells. The information listed above was provided to the Commission by letter dated October 11, 2021. Notice of Investigation — Late MIT W-44 Closeout Docket OTE -21-039 October 21, 2021 Page 2 of 2 The Commission does not intend to take enforcement action in connection with this matter. Sincerely, �+b�ea nrxm�, Jeremy Price..M.,, ., aim Jeremy M. Price Chair, Commissioner cc: Timothy Mayers, US Environmental Protection Agency, Region 10 Jim Regg and AOGCC Inspectors Oliver Sternicki, Hilcorp Well Integrity Engineer 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. 28 Hilcorp North Slope, LLC Stan Golis, PBW Operations Manager 3800 Centerpoint Dr, Suite 1400 Anchorage, Alaska 99503 4 Hilcorp North Slope, LLC 10/11/2021 RECEIVED Jeremy M. Price By Samantha Carlisle at 1:27 pm, Oct 11, 2021 Chair, Commissioner Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage, Alaska 99501 Subject: Docket OTH-21-039: Investigation of Late Mechanical Integrity Test (MIT) for W-44 (PTD# 189100), Hilcorp North Slope, LLC Dear Mr. Price, Please see below for information requested per Docket OTH-21-039 dated 10/6/2021 regarding operations and operation of W-44 (PTD# 189100). 1. 12 -month Tubing, Inner Annulus, and Outer Annulus (T10) raw data (excel formas) and pressure plot identifying TIO pressures, injection rate, injection temperature, and any bleed events of W-44, W-44 TIO raw data 10/6/2020-10/6/2021: 10� W-44 TIO 201006-211006.xlsx W-44 10/6/2020-10/6/2021 TIO, injection rate and temperature plot. No bleed events. U DO Pa t nP 4 op r Opr Abt— 0— ♦ U M -�MAN_IA •�AI/+N OA -H AW! OOOn Tan PonA+n 2. A timeline of well events since a passing state -witnessed MITIA on July 16, 2017 to present, including correspondence with AOGCC, if any, on scheduling the MIT or postponing the test; Well Events data 7/16/2017-10/6/2021: W-44 Well Events 170716-211006.xlsx 3. Full root cause analysis, including results and conclusions, addressing the failure to perform the required MIT during the due month of July 2021; and W-44 was due for a 4 -year online AOGCC witnessed MIT -IA in July 2021. The only online period during the month was 7/8-7/16, but the well was not pressure tested during this period due to a lack of stabilized injection rate. W-44 was shut-in on 7/16 due to maintenance on the pad. At the end of July W-44 remained offline, but work was planned in the first few days of August to bring the well back online. W-44 remained Operable (offline) during this period from 8/1-8/4, after which the well was placed on injection. Stabilized injection was achieved and a passing MIT -IA was witnessed by Inspector Jeff Jones on 8/8/2021. Hilcorp North Slope, LLC maintains a strong compliance pressure test tracking system with pressure tests entered into it's Well Integrity management software which generates a daily report of test due within the next 90 days. Wells that are past due for a compliance test such as W-44 are highlighted at the top of the list which is reviewed daily by the Well Integrity Coordinator, Well Integrity Engineer and Operations field personnel. Clarification should have been provided to the AOGCC per Industry Guidance Bulletin 10-02B regarding short-term shut-in status in a case such as W-44. This information has been reviewed with the Well Integrity Coordinator to ensure the guidelines in Industry Guidance Bulletin 10-02B are adhered to. 4. Results of a review of each of the Hilcorp injectors authorized by AIO 4G specifically to the MIT due date and idendrication of any wells that are out of compliance with test dates. Per conversation with Chris Wallace on 10/6/2021 request #4 to be limited to W pad wells only. If you have any questions, please call me at 907-564-5231 or Oliver Stemicki at 907-564-4891. _t�Sincerely, p� - , L�) Stan Golis PBW Operations anager MIT -A Duration MIT -IA MITaA ONOO#na between MI14ANer4 STabA T40 Wel W1 Slat TWO 6a0 NRNllData MIT4AOumuNs tests Date Y=Pma Roes W-03 Operable WAG Y 04!13/21 AOGCCw4triassedbyAusdnMcleod 48 04/13125 Y 2315 W-11 Operable WAG Y 06104/19 WltrmsedbyJeAJones 48 06/04/23 Y 2410 W-17 Operable WAG Y 01/16/21 AOGCCwbessbyLou Laubensteln 48 01/16/25 Y 1780 W-20 Operable WAG Y 08/14/20 AOGCC Wlbmssed by JaR Jona 49 OB/ 14124 Y 2430 W-207 Operable WAG Y 10110119 W anezeu by Metz Herrera 48 10/10123 Y 1953 W-209 Operable WAG Y 08114120 AOGOC WOtreass Jeff Jones 48 08/14/24 Y 2199 W-210 Operaba WAG Y 05/31/19 Witnessed byJeff Jonea 48 05!31123 Y 1934 W212 Operable PWI Y 08103121 Will ressedbyBrian Bhnby 48 08103!25 Y 2264 W-213 Operable WAG Y 08114/20 AOGOCWfNessJeff Jones 48 08/14/24 Y 2140 W214 Operable WAG Y 11/04/20 AOGCC Witness Brian Bbmy 48 11/04124 Y 2431 W215 Net Operable WAG N 04/29/13 State wenes5 Jeff Jonm 48 04/29117 Y 2514 W216 Operable WAG Y 08/14/20 AOGCCWkressJWJorms 48 08/14/24 Y 2156 W-217 Operable WAG Y 02/19/18 Witnessed by B. Bbtby 48 OW19122 Y 2458 W-218 Operable WAG Y 04/13/21 AOG0CwftnesedbyAustlnMcleod 46 04!13125 Y 1636 W-219 Operable WAG Y 10120/19 AOG'CCwlbnessedbyBMnBbdry 48 10/20/23 Y 2394 W220 Operable PWI Y 11130/19 Witnessed byA Ort McLeod 48 11/30123 Y 2460 W221 Operable WAG Y 10/10/19 Wanessed by Man Herrera 48 10110/23 Y 2456 W223 Operable WAS Y 01127/20 Wenessed by Man Herrera 48 01/77/24 Y 1958 W-24 Operable WAG Y 01114120 AOGCC witnessed by Bob Noble 24 01126122 Y 2261 W-29 Operable WAG Y 01105!19 Wttn®Bdtry Adam Ead 48 01/05123 Y 2832 W135 Operable WAS Y 04/10/20 AA mntverssry. AOSOC rep Jeff Jones D 24 04110122 Y 3056 W-42 Not Operable PWI N 07/31/16 AOGCCWIbnass Bob Noble 12 07/31/17 Y 1400 W-44 Operable PWI Y 09/08121 Witnessed byMJmes 48 08108/25 Y 2267 If you have any questions, please call me at 907-564-5231 or Oliver Stemicki at 907-564-4891. _t�Sincerely, p� - , L�) Stan Golis PBW Operations anager Date TBG (psi) IA (psi) OA (psi 10/5/2021 816 450 200 10/4/2021 816 450 200 10/3/2021 816 450 200 10/2/2021 816 450 200 10/1/2021 813 400 200 9/30/2021 813 400 200 9/29/2021 813 400 200 9/28/2021 813 400 200 9/27/2021 813 400 200 9/26/2021 812 400 200 9/25/2021 812 400 200 9/24/2021 812 400 200 9/23/2021 812 400 200 9/22/2021 812 400 200 9/21/2021 810 450 200 9/20/2021 810 450 200 9/19/2021 810 450 200 9/18/2021 810 450 200 9/17/2021 810 450 200 9/16/2021 807 400 250 9/15/2021 808 400 200 9/14/2021 808 400 200 9/13/2021 808 375 200 9/12/2021 808 375 200 9/11/2021 808 375 200 9/10/2021 807 375 200 9/9/2021 807 375 200 9/8/2021 807 375 200 9/7/2021 806 350 200 9/6/2021 805 350 200 9/5/2021 805 350 200 9/4/2021 805 350 200 9/3/2021 803 350 200 9/2/2021 803 350 200 9/1/2021 803 350 200 8/31/2021 803 350 200 8/30/2021 803 350 200 8/29/2021 802 325 200 8/28/2021 804 350 200 8/27/2021 804 300 200 8/26/2021 804 300 200 8/25/2021 799 300 200 8/24/2021 799 300 200 8/23/2021 799 300 200 8/22/2021 797 300 200 8/21/2021 797 250 200 8/20/2021 795 250 200 8/19/2021 794 250 200 8/18/2021 793 200 200 8/17/2021 791 150 200 8/16/2021 784 150 200 8/15/2021 766 150 200 8/14/2021 766 150 200 8/13/2021 754 100 200 8/12/2021 752 100 200 8/11/2021 740 100 200 8/10/2021 732 100 200 8/9/2021 703 100 200 8/8/2021 703 100 200 8/7/2021 686 150 200 8/6/2021 670 150 200 8/5/2021 629 150 200 8/4/2021 590 150 150 8/3/2021 87 150 150 8/2/2021 87 150 200 8/1/2021 447 150 200 7/31/2021 0 150 150 7/30/2021 0 150 150 7/29/2021 0 150 150 7/28/2021 0 150 150 7/27/2021 0 150 200 7/26/2021 0 150 200 7/25/2021 0 150 200 7/24/2021 0 150 200 7/23/2021 0 150 200 7/22/2021 0 150 200 7/21/2021 13 150 250 7/20/2021 124 150 200 7/19/2021 124 150 200 7/18/2021 120 150 200 7/17/2021 114 150 200 7/16/2021 667 150 200 7/15/2021 660 150 200 7/14/2021 657 150 200 7/13/2021 657 150 200 7/12/2021 651 150 200 7/11/2021 642 150 200 7/10/2021 635 150 200 7/9/2021 653 150 150 7/8/2021 51 150 150 7/7/2021 58 150 150 7/6/2021 44 150 150 7/5/2021 52 150 150 7/4/2021 48 150 150 7/3/2021 38 150 150 7/2/2021 38 150 150 7/1/2021 51 150 150 6/30/2021 62 150 150 6/29/2021 66 150 150 6/28/2021 66 150 150 6/27/2021 110 150 150 6/26/2021 60 150 150 6/25/2021 62 150 150 6/24/2021 57 150 150 6/23/2021 73 150 150 6/22/2021 84 150 150 6/21/2021 60 150 150 6/20/2021 79 150 150 6/19/2021 89 150 150 6/18/2021 75 150 150 6/17/2021 70 150 150 6/16/2021 77 150 150 6/15/2021 87 150 150 6/14/2021 60 150 150 6/13/2021 64 150 150 6/12/2021 87 150 150 6/11/2021 87 150 150 6/10/2021 75 150 150 6/9/2021 66 150 150 6/8/2021 53 150 150 6/7/2021 60 150 150 6/6/2021 60 150 150 6/5/2021 64 150 150 6/4/2021 58 150 150 6/3/2021 61 150 150 6/2/2021 61 150 150 6/1/2021 61 150 150 5/31/2021 73 150 150 5/30/2021 69 150 150 5/29/2021 82 150 150 5/28/2021 65 150 150 5/27/2021 69 150 150 5/26/2021 63 150 150 5/25/2021 70 150 150 5/24/2021 70 150 150 5/23/2021 85 150 150 5/22/2021 61 150 150 5/21/2021 70 150 150 5/20/2021 70 150 150 5/19/2021 73 150 150 5/18/2021 73 150 150 5/17/2021 66 150 150 5/16/2021 70 150 150 5/15/2021 71 150 150 5/14/2021 63 150 150 5/13/2021 51 150 150 5/12/2021 54 150 175 5/11/2021 60 150 175 5/10/2021 55 150 175 5/9/2021 59 150 175 5/8/2021 59 150 175 5/7/2021 59 150 175 5/6/2021 59 150 175 5/5/2021 67 150 175 5/4/2021 67 150 175 5/3/2021 70 150 175 5/2/2021 58 150 175 5/1/2021 63 150 175 4/30/2021 63 150 175 4/29/2021 64 150 175 4/28/2021 66 150 175 4/27/2021 53 150 175 4/26/2021 48 150 175 4/25/2021 58 150 175 4/24/2021 58 150 175 4/23/2021 67 150 175 4/22/2021 69 150 175 4/21/2021 74 150 175 4/20/2021 94 150 175 4/19/2021 94 150 175 4/18/2021 94 150 175 4/17/2021 103 150 175 4/16/2021 103 150 175 4/15/2021 90 150 175 4/14/2021 90 150 175 4/13/2021 77 150 175 4/12/2021 58 150 200 4/11/2021 58 150 200 4/10/2021 58 150 200 4/9/2021 58 150 200 4/8/2021 58 150 200 4/7/2021 58 150 200 4/6/2021 58 150 200 4/5/2021 68 150 200 4/4/2021 68 150 200 4/3/2021 57 150 200 4/2/2021 54 150 200 4/1/2021 60 150 200 3/31/2021 53 150 200 3/30/2021 52 150 200 3/29/2021 51 150 200 3/28/2021 48 150 200 3/27/2021 49 150 200 3/26/2021 65 150 200 3/25/2021 99 125 175 3/24/2021 75 125 175 3/23/2021 70 125 175 3/22/2021 76 125 175 3/21/2021 76 125 175 3/20/2021 76 125 175 3/19/2021 76 125 175 3/18/2021 76 125 200 3/17/2021 76 125 200 3/16/2021 825 125 200 3/15/2021 825 125 200 3/14/2021 825 125 200 3/13/2021 825 150 225 3/12/2021 825 150 200 3/11/2021 820 150 200 3/10/2021 820 150 200 3/9/2021 817 150 200 3/8/2021 813 150 200 3/7/2021 803 150 200 3/6/2021 788 150 200 3/5/2021 602 150 200 3/4/2021 461 150 200 3/3/2021 392 150 200 3/2/2021 450 150 200 3/1/2021 395 150 200 2/28/2021 392 150 200 2/27/2021 419 150 200 2/26/2021 417 150 200 2/25/2021 434 150 200 2/24/2021 437 150 200 2/23/2021 438 200 150 2/22/2021 373 200 150 2/21/2021 405 200 150 2/20/2021 405 200 150 2/19/2021 388 150 150 2/18/2021 0 150 200 2/17/2021 0 150 200 2/16/2021 0 150 175 2/15/2021 0 150 175 2/14/2021 0 150 175 2/13/2021 0 150 175 2/12/2021 0 150 175 2/11/2021 0 150 175 2/10/2021 0 150 175 2/9/2021 0 150 175 2/8/2021 0 150 175 2/7/2021 0 150 175 2/6/2021 0 150 175 2/5/2021 0 150 175 2/4/2021 0 150 175 2/3/2021 0 150 175 2/2/2021 0 150 175 2/1/2021 0 150 175 1/31/2021 0 150 175 1/30/2021 0 150 175 1/29/2021 0 150 175 1/28/2021 0 150 175 1/27/2021 0 150 175 1/26/2021 331 150 200 1/25/2021 331 150 200 1/24/2021 331 150 200 1/23/2021 331 150 200 1/22/2021 331 150 200 1/21/2021 331 150 200 1/20/2021 331 150 200 1/19/2021 331 150 200 1/18/2021 331 150 200 1/17/2021 331 150 200 1/16/2021 331 150 200 1/15/2021 331 150 200 1/14/2021 331 150 200 1/13/2021 331 150 200 1/12/2021 331 150 200 1/11/2021 688 150 200 1/10/2021 260 150 150 1/9/2021 0 150 150 1/8/2021 0 150 150 1/7/2021 0 150 150 1/6/2021 0 150 150 1/5/2021 0 150 150 1/4/2021 0 150 150 1/3/2021 0 150 150 1/2/2021 0 150 150 1/1/2021 0 150 150 12/31/2020 0 150 150 12/30/2020 0 150 150 12/29/2020 0 150 150 12/28/2020 0 150 150 12/27/2020 0 150 150 12/26/2020 0 150 150 12/25/2020 0 150 150 12/24/2020 0 100 150 12/23/2020 0 150 150 12/22/2020 0 150 150 12/21/2020 0 150 150 12/20/2020 0 150 150 12/19/2020 0 150 150 12/18/2020 0 150 150 12/17/2020 0 150 150 12/16/2020 0 150 150 12/15/2020 0 150 150 12/14/2020 0 150 150 12/13/2020 0 150 150 12/12/2020 1 150 150 12/11/2020 2 150 150 12/10/2020 1 150 150 12/9/2020 2 150 150 12/8/2020 9 150 150 12/7/2020 7 150 150 12/6/2020 13 150 150 12/5/2020 35 150 150 12/4/2020 20 167 150 12/3/2020 7 150 150 12/2/2020 11 150 150 12/1/2020 5 150 150 11/30/2020 5 150 150 11/29/2020 5 150 150 11/28/2020 5 150 150 11/27/2020 5 150 150 11/26/2020 5 150 150 11/25/2020 5 150 150 11/24/2020 5 150 200 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II 6 N Nrq v O Q N rI �_ O C a) N O O — O CU 00 E O N N N a _ c i v 4-v j � O O E 0 o O •� CL ca X d Ln p N •- \ (U d C Q N O \ hA a O iLn J Q 3 v 0 0 C71 a) N a 0 �--I C f0 3 J 7Ln 0 r..1 Q Q\ LQ CJl ai Q ° O U p O •� II E v'�i Q O x m a 2 C a� N 7 3 0 N d 06 o 0 F- Co 0) a n N 2 Q L ; 27 THE STATE October 6, 2021 "'ALASKA Mr. Andrew Ogg 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 Field Well Integrity/ Compliance Sent Certified Mail: Hilcorp North Slope, LLC 702103 50 0001 5545 4981 3800 Centerpoint Dr., Suite 1400 Anchorage, AK 99503 Re: Docket OTH-21-039 Investigation of Late Mechanical Integrity Test (MIT) Prudhoe Bay Unit W-44 (PTD 1891000) Area Injection Order (AIO) 4G Prudhoe Bay Unit (PBU), Prudhoe Oil Pool Dear Mr. Ogg: By email dated September 1, 2021, Hilcorp North Slope, LLC (Hilcorp) sent the August 2021 MIT Forms which included the passing state -witnessed MIT of W44 completed on August 8, 2021. Upon review, the Alaska Oil and Gas Conservation Commission (AOGCC) determined that the previous test was a passing state -witnessed MIT completed July 16, 2017. Area Injection Order 4G Rule 6 states "Subsequent tests must be performed at least once every four years thereafter (except at least every two years in the case of a slurry injection well)." AOGCC Industry Guidance Bulletin 10-02B dated August 9, 2017, allowed for efficiencies in testing and witnessing by allowing an MIT to be performed anytime during the anniversary month to satisfy the MIT due date. By AOGCC`s determination, Hilcorp should have completed the required MIT in the month of July 2021, making the test performed on August 8, 2021 late. AOGCC recognizes that an MIT can be requested to be delayed or postponed for numerous reasons and any agreement with AOGCC would have conditions and a new test schedule established. AOGCC records do not show any agreement to delay the test was established. Pursuant to 20 AAC 25.300, the AOGCC requests the following additional information be provided by Hilcorp regarding their operations and operation of PBU W-44. 1. 12 -month Tubing, Inner Annulus, and Outer Annulus (TIO) raw data (excel format) and pressure plot identifying TIO pressures, injection rate, injection temperatures, and any bleed events of W-44; Notice of Investigation — Late MIT W-44 Docket OTH-21-039 October 6, 2021 Page 2 of 2 2. A timeline of well events since a passing state -witnessed MITIA on July 16, 2017 to present, including correspondence with AOGCC, if any, on scheduling the MIT or postponing the test; 3. Full root cause analysis, including results and conclusions, addressing the failure to perform the required MIT during the due month of July 2021; and 4. Results of a review of each of the Hilcorp injectors authorized by AIO 4G specifically to the MIT due date and identification of any wells that are out of compliance with test dates. The information listed above should be provided to the AOGCC no later than November 5, 2021. The Commission reserves the right to pursue an enforcement action in this matter according to 20 AAC 25.535. Failure to comply with this request is itself a regulatory violation. Sincerely, Jeremy Pricey wKwi.ime wine Jeremy M. Price Chair, Commissioner Alaska Oil and Gas Conservation Commission cc: Timothy Mayers, US Environmental Protection Agency, Region 10 Jim Regg and AOGCC Inspectors Oliver Sternicki, Hilcorp Well Integrity Engineer 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. Lr) Ll Lr) r-� O 0 C3 Lr) M 0 ru C3 xcr BNiCeS to lees (check box, add fee as appropriate) Retum Receipt (hardcopy) $ ❑ Return Receipt (electronic) $ ❑ Certified Mail Restricted Delivery $ ❑ Adult Signature Required $ ❑ Adult Signature Restrlcted Delivery $ -A.2( 4-- ■ Complete items 1, 2, and 3. ■ Print your name and address on the reverse so that we can return the card to you. ■ Attach this card to the back of the mailpiece, or on the front if space permits. 1. Article Addressed to: sCo � � �/c v ; No erg,� IIIIIIIII 11111111111111111111111111111IINIIIII 9590 9402 4351 8190 1906 90 2. Article Number (Transfer from service label) 7021 0350 0001 5545 4981 PS Form 3811, July 2015 PSN 7530-02-000-9053 Postmark Here A. Signature X J E3 Agent ❑ Addressee B. Received 14 (Printed Name) C. a of Delivery rlt I D. Is delivery address different from item 1? ❑ Yes If YES, enter delivery address below: ❑ No 3Service Type ❑ Priority Mail Express® E Adult Signature ❑ Registered Mail - 0 Adult Signature Restricted Delivery ❑ Registered Mail Restricted ❑ Certified Mail® Delivery U.S. Postal Service'" Merchandise E] Collect on Delivery Restricted Delivery 0 Signature Confirmation- r-IInsured Mail CERTIFIED I Insured Mail Restricted Delivery Restricted Delivery MAIL° RECEIPT -. Domestic Mail Only w For delivery information, visit our wehcitP at Lr) Ll Lr) r-� O 0 C3 Lr) M 0 ru C3 xcr BNiCeS to lees (check box, add fee as appropriate) Retum Receipt (hardcopy) $ ❑ Return Receipt (electronic) $ ❑ Certified Mail Restricted Delivery $ ❑ Adult Signature Required $ ❑ Adult Signature Restrlcted Delivery $ -A.2( 4-- ■ Complete items 1, 2, and 3. ■ Print your name and address on the reverse so that we can return the card to you. ■ Attach this card to the back of the mailpiece, or on the front if space permits. 1. Article Addressed to: sCo � � �/c v ; No erg,� IIIIIIIII 11111111111111111111111111111IINIIIII 9590 9402 4351 8190 1906 90 2. Article Number (Transfer from service label) 7021 0350 0001 5545 4981 PS Form 3811, July 2015 PSN 7530-02-000-9053 Postmark Here A. Signature X J E3 Agent ❑ Addressee B. Received 14 (Printed Name) C. a of Delivery rlt I D. Is delivery address different from item 1? ❑ Yes If YES, enter delivery address below: ❑ No 3Service Type ❑ Priority Mail Express® E Adult Signature ❑ Registered Mail - 0 Adult Signature Restricted Delivery ❑ Registered Mail Restricted ❑ Certified Mail® Delivery ❑Certified Mail Restricted Delivery 0 Return Receipt for ❑Collect on Delivery Merchandise E] Collect on Delivery Restricted Delivery 0 Signature Confirmation- r-IInsured Mail O Signature Confirmation I Insured Mail Restricted Delivery Restricted Delivery (over $500) Domestic Return Receipt 26 THE S'I'A'1'E Alaska Oil and Gas ,"ALASKA Conservation Commission GOURNOR A11KE DUNLEAVY 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.alaska.gov October 2, 2020 Mr. Oliver Sternicki Well Integrity Engineer Hilcorp North Slope, LLC. 3800 Centerpoint Drive Anchorage, AK 99503 Re: Docket Number: AIO-20-005 Request to amend the maximum allowable inner annulus operating limits on injectors which operate under existing administrative approvals. Area Injection Orders 3C, 4G, 22F, and 24B Prudhoe Bay Unit (PBU) Dear Mr. Stemicki: By letter dated March 9, 2020, BP Exploration (Alaska) Inc. (BPXA) requested administrative approval to change the inner annulus (IA) maximum operating pressure on 36 wells. This was requested in parallel with a BPXA request to increase the IA operating pressure for producing wells under Conservation Order CO 492. After the initial request was received from BPXA, Hilcorp North Slope, LLC (HNS) acquired BPXA North Slope assets July 1, 2020 and became operator of the PBU. On July 29, 2020, AOGCC received an email from HNS stating "Hilcorp, as the new operator of the BPXA assets has reviewed and approve of the submitted request to the AOGCC pertaining to increasing IA NOL in GPB." AOGCC issued CO 492A on October 1, 2020 that increased the notification IA operating pressure from 2000 psi to 2100 psi for PBU wells not processed through the Lisburne Production Facility. In accordance with Rule 9 of Area Injection Order (AIO) 4G and 24B, Rule 10 of AIO 3C, and Rule 11 of AIO 22F, the Alaska Oil and Gas Conservation Commission (AOGCC) hereby GRANTS HNS's request for administrative approval to change the maximum IA operating pressure for the 36 wells to 2100 psi as detailed in the accompanying table. 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 October 2, 2020. oyu.in+u��m Jeremy „q�a> d.. Daniel T. ,.„�,,,,,. Jessie L. a4u,M,4M Wleule ru,xeona ,<rt�nss r,¢. Seamount,Jr. o.re:m3o.,oa: w,sn3 Chmielowskia,ba M. Price a"3mu,00x «mi.00'I.....ca3 13:I1:IBNbV Jeremy M. Price Daniel T. Seamount, Jr. Jessie L. Chmielowski Chair, Commissioner 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 web 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 frt 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 m whole or m 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 rum is not included in the period; the lase 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. AID # PTD Well AA Date AA max mandated pressure si) ff25OO 3C.001 1710380 A-03 12/19/2019 00 4E.024 1750690 NG1-04 4/29/2007 00 4E.032 1760140 NGI-OS 6/9/2008 00 4F.002 1810740 17-08 4/3/2015 2000 2100 46.009 1811770 11-07 12/12/2019 2000 2100 4F.006 1820260 13 17 12/7/2015 2000 2100 4F.008 1831700 14'27 5/23/2016 2000 2100 4G.001 1840280 09-25 8/2/2016 2000 2100 36.001 1880700 W-24 3/15/2016 2000 2100 4E.017 1931850 14'01 2/21/2007 2000 2100 4G.006 1940130 04.43 4/6/2017 2000 2100 4F.007 1961440 X-33 4/11/2016 2000 2100 4F.004 1972180 13-06 7/9/2015 2000 2100 3.024 1982060 R-11 1/25/2017 2000 2100 4F.005 1982140 S-25 10/2/2015 2500 2100 3B.008 1990530 S-11 3/6/2018 2000 2100 3B.003 1991250 X-24 8/2/2016 2000 2100 4E.020 1991310 17-15 3/17/2007 2000 2100 3.025 2000090 N-08 1/14/2011 2000 2100 3.029 2001570 B-22 4/28/2010 2000 2100 22F.001 2011130 5-107 1/7/2020 2000 2100 4F.001 2021240 PSI -09 3/6/2015 2000 2100 3.015 2051380 P-06 3/13/2007 2000 2100 4G.003 2051600 1331 9/1/2016 2000 2100 3B.006 2061050 2-19 2/14/2017 2000 2100 313.009 2080930 V-05 _ 11/14/2018 2000 2100 4E.039 2091390 0337 9/6/2011 2000 2100 313.002 2101010 S'41 8/2/2016 2000 2100 248.006 2111240 2-116 3/5/2019 2000 2100 46.008 2141640 R-22 2/15/2018 2000 2100 3.03 2150660 P-70 9/11/2015 2000 2100 3C.002 1880330 W'35 4/27/2020 2000 2100 4G.008 2141640 R'2ZA 7/23/2020 2000 2100 4G.008 2141650 R-22AL1 7/23/2020 2000 2100 4G.010 2021450 PSI o1 8/10/2020 2000 2100 4G.011 2050200 17-13A 8/10/2020 2000 2100 Bernie Karl K&K Recycling Inc. P.O. Box 58055 Fairbanks, AK 99711 George Vaught, Jr. P.O. Box 13557 Denver, CO 80201-3557 Gordon Severson 3201 Westmar Cir. Anchorage, AK 99508-4336 Darwin Waldsmith P.O. Box 39309 Ninilchik, AK 99639 Richard Wagner P.O. Box 60868 Fairbanks, AK 99706 I� �IZ0� U Cpl �L 25 BP Exploration (Alaska)Inc. Ryan Daniel, Well Integrity Engineering Team Lead Post Office Box 196612 Anchorage, Alaska 99519-6612 March 9, 2020 by 0 tk LCIL IVED Mr. Jeremy Price MAR 0 9 2020 Alaska Oil and Gas Conservation Commission 333 West 711 Avenue AOGC Anchorage, Alaska 99501 Subject: Request to amend defined inner annulus normal operating limits on injectors operating under administrative approval. Dear Mr. Price, BP Exploration (Alaska) Inc. requests an amendment to the injection well administrative approvals listed in Table 1 such that the inner anulus (IA) normal operating limits (NOL) are changed to 2100 psi. The request to amend the IA NOLs of the wells listed in Table 1 is in parallel with a request to amend CO 492 such that IA NOL can be increase to 2100 psi for the majority of development wells in the Prudhoe Bay field. For consistency across the field the intent is to change IA NOL for all injection wells excluding: Class I disposal wells, Lisburne Injection wells, Well 09-16 (PTD: 1770370). Upon review of the AIOs governing Class II injection wells operated by BPXA there is no defined IA NOL except in the case of some select administrative approvals that have been granted. These defined IA NOLs are listed in Table 1. ORIGINAL Table 1: Administrative Approval List 3C.001 1710380 A-03 12/19/2019 20011 2000 4E.024 1750090 NGI-04 4/29/2007 2500 2000 4E.032 1750140 NGI-05 6/9/2008 2500 2000 4F.002 1810740 17-03 4/3/2015 2000 2000 46.009 1811-,0 11-07 12/12/2019 20DO 2000 4F.006 1820260 13-17 12/7/2015 20DO 2000 4F.008 1831700 14-27 5/23/2016 2000 2000 46.001 1840280 09-25 8/2/2016 2000 2000 38.001 1880700 W-24 3/15/2016 2060 2006 4E.017 1931850 14-01 2/21/2007 2000 2000 4G.006 19401311 3 4/6/2017 2000 2000 4F.007 19G1440 X-33 4/11/2016 2000 2000 4F.004 1972180 13-05 7/9/2015 2000 2000 3.024 1982059 R-11 1/25/2017 2000 2000 4F.005 1982140 5-25 10/2/2015 2500 2000 38.008 1996530 S-11 3/6/2018 2000 2000 38.003 1991250 X -2d 8/2/2016 2006 2000 4E.020 1991310 1715 3/17/2007 2000 2060 3.025 21DD096 N-08 1/14/2011 2000 20DO 3.029 2001570 B-22 4/28/2010 2060 2000 22F.001 2111130 5107 1/7/2020 2000 2600 4F.001 2121249 PSI -09 3/6/2015 2000 2000 3.015 2051380 P36 3/13/2007 2000 2006 G.003 2051606 1331 9/1/2016 2006 2000 38.006 3061050 2-19 2/14/2017 12000 2000 38.009 21180930 V-05 11/14/2018 2000 2000 4E.039 1390 3-37 9/6/2011 2000 2000 38.002 2101010 S41 8/2/2016 2000 2000 248.006 2111240 Z-116 3/5/2019 2000 2000 46.008 2141540 P-22 2/15/2018 2006 20D0 3.03 150559 P-10 9/11/2015 20M 2000 If you have any questions, please call me at 564-5430 Sincerely, 4v— Ryan Daniel BPXA Well Integrity Team Lead Attachments: Technical Justification Technical Justification for Administrative Approval Amendment March 9, 2020 History and Status: BPXA is currently in the process of requesting an amendment to Conservation Order No. 492 rule 3(a) and 6(a) (Docket Number: CO -20-004) to facilitate the increase of IA NOL to 2100 psi for Prudhoe Bay field development wells excluding those processed through the Lisburne Processing Center and jet pump wells based on the following. Gas lift header pressure at many of the drill sites and pads in the Prudhoe Bay field (excluding wells processed through the Lisburne Process Center) regularly exceeds the 2000 psi IA NOL set for development wells. Gas lift compressor outlet pressures are commonly set at 2100 psi. Historical gas lift pressures can be seen in Figure 1 & 2 for reference. The legacy IA NOL value of 2000 psi was set to remain compliant with Conservation Order No. 492 rule 3(a) and 6(a). Prior to the installation and monitoring of wireless annulus pressure gauges this was not as large of a problem due to one IA pressure read being recorded via mechanical gauge daily per well. If a pressure read exceeded the 2000 psi NOL it was reported to Well Integrity and evaluated to determine if the excursion was SCP or not. Currently all wells in the Prudhoe Bay field have the inner annulus pressures monitored in real-time by either the EOA or WOA production center board operators. The board operators are notified with an alert when the IA pressure of a well exceeds the set NOL value of 2000 psi. This ensures a timely notification and response to any potential excursion event. With the utilization of the wireless annulus pressure gauge alerting it has become an ongoing problem where wells supplied with gas lift pressure are regularly setting off alerts due to the gas lift supply pressure exceeding the 2000 psi NOL and not due to SCP as intended. This excessive alerting has the potential to desensitize workers to possible hazardous occurrences. Increasing IA NOL from 2000 psi to 2100 psi for development wells would eliminate the majority of these false NOL excursion alerts and allow resources to be more focused on response and evaluation of probable SCP events. All development wells are included in this request in an effort to reduce the complexity of the IA NOL change and management across the Prudhoe Bay field. This reasoning for reduced complexity in management of IA NOLs extends to injection wells in the Prudhoe Bay field. Alignment with the change applied to development wells is important to minimize variability of IA NOLs and simplify the management of all wells. The majority of injection wells in the Prudhoe Bay field currently have IA NOLs set to 2000 psi. This 2000 psi NOL was applied by BPXA for consistency across the field and is not tied to a requirement in an Area Injection Order other than for specific Administrative Approvals on individual wells listed in Table 1 which is what BPXA is requesting amendment to. The intent is to change IA NOLs for all injectors to 2100 psi excluding Class I disposal wells, Lisburne Injection wells and Well 09-16 (PTD: 1770370). This increase of 100 psi to the IA NOL is well within the design parameters of injection wells across the Prudhoe Bay field and the IA NOL increase would not reduce the ability to identify possible annular communication in these wells. Figure 1- EOA DS Gas Lift Header Pressure EOA Gas Lift Pressure a3/1L'3013 L.. MD., S :21016 6/EryL5t3 B/a/SM3 IIMPP35 II/1)/2Y35 3/6/lN6 212VW16 OMe Figure 2- WOA Pad Gas Lift Header Pressure WOA Gas Lift Pressure 5/1/im6 6/ig101S il/t)/Im3 1/6/2016 —moa —ma —mos —mw —moa —mtt —D6 tl —m33 —DS l6 —0311 —a. —.Pad —DPM X wd —1 Pad —. PM —M Pod —XPM _ 11Pd vPad —s Pm —o Pad Ped w PM .PM Pad P.d Hilcorp North Slope, LLC Bo York, PBE Operations Manager 3800 Centerpoint Or, Suite 1400 Anchorage, Alaska 99503 July 31, 2020 Mr. Jeremy Price, Chair Alaska Oil and Gas Conservation Commission 333 West 711 Avenue Anchorage, Alaska 99501 RECEIVED By Jody Colombie at 7:55 am, Aug 06, 2020 Subject: Prudhoe Bay Well 17-13 (PTD# 205020) Request for an Administrative Approval to continue Water Injection Operations Dear Mr. Price, Hilcorp North Slope, LLC requests administrative approval for continued water injection only into Prudhoe Bay WAG well 17-13 with slow tubing by inner annulus communication. No increase to Maximum Operating Annulus Surface Pressure (MOASP) is required. 17-13 was flagged on 7/17/20 as having possible TAA communication while on produced water injection and was placed under evaluation at which time it was reported to the AOGCC. To confirm the primary and secondary barriers a passing AOGCC witnessed MIT -IA was conducted on 07/29/20 to 2339 psi while on water injection. Hilcorp North Slope, LLC has determined that well 17-13 is safe to operate in its current condition and requests an AA for water injection only based on the following: • IA pressure can be maintained below MOASP by managing the IA repressurization with periodic annular bleeds. • MIT -IA passed to 2339 psi. • IA and OA pressures will be monitored with wireless pressure gauges. If you have any questions, please call me at 907-777-8345 or Ryan Holt/ Andy Ogg at 659- 5102. Sincerely, 0iyn,uy aly,,.. cy eo vos Bo York 0ry c -Bo York a=us o=tumorp Naske LLC, ou=AlaSXa NOHI, Slap¢, email=LyorE�C,ilcor0 rom Date'. N20.08.031E514<-OBOP Bo York PBE Operations Manager Attachments Technical Justification TIO Piot Injection Plot Wellbore Schematic Prudhoe Bay Well 17-13 Technical Justification for Administrative Approval Request July 31, 2020 Well History and Status Well 17-13 is a WAG injector that was originally drilled in January 1985 and sidetracked in April 2005. The well went under evaluation on 7/17/20 for IA repressurization and passed all diagnostics including an AOGCC witnessed MIT -IA to 2339 psi with the well online on 07/29/20. Recent Well Events: 07/29/20 Online AOGCC MIT -IA Passed to 2339 psi. 07/18/20 PPPOT-T Passed 07/17/20 Anomalous IA repressurization reported to the AOGCC. 04/03/18 Online AOGCC MIT -IA Passed to 2451 psi Barrier and Hazard Evaluation The primary and secondary barriers systems consist of the tubing and production casing and associated hardware. A passing pressure test of the inner annulus to 2339 psi on 07/29/20, which tests both barriers, demonstrates competent primary and secondary barrier systems. Pressure on the inner annulus will be maintained below MOASP of 2000 psi when the well is on-line. Proposed Operating and Monitoring Plan 1. Water injection only 2. Record wellhead pressures and injection rate daily. 3. Submit a report monthly of well pressures and injection rates to the AOGCC. 4. Perform a 2 -year MIT -IA to maximum anticipated injection pressure. 5. IA MOASP= 2000 psi, OA MOASP= 1000 psi 6. The well will be shut-in and the AOGCC notified if there is any change in the wells mechanical condition. TIO Plot TIO Piot -Tbp On • Meed * Operable Not OPer ♦ Under Ewl •- MAN IA -MAN OA MAN -WA • MAN MOA O Temperetun Injection Plot G1 Wellbore Schematic KB REV -7- 17-13A BF Ell- TF KOF 9 Ss %.jI 1 ka e 9 $ 1Wa1 A3W 55� 1 I e ! UG 04 1 E0 r: 'T 1 2503' Minimum ID = 3.723" @ 10772- 4-112" HES XN NIP f}ry ORA PION 8Li1MANr WE LOO WA)(N115M) AN(3I L AI IOPR�R; W @ 111(%1' Note RN. 10 Rwmlm� OB lw hnlwewF aff SFf NI AI Op.W 2718 4 11100 11180 O amt. 2716' 4 11280. 113M O NWX)S 27710 4 11480. 11550 O 04619ttY.1 2 718 4 12100 1260 O 04MOM 2 70 4 12M 13w) O (Mma 5 2 718 4 13550 13700 0 041(19'05 7 7.6 4 j 130W 1400 0 0404'03 9 S'8" W : oSTOCJ( (C345.'OS) - 8187' _- IDil, O1 S7 ep1 O=3 858 I 10783' 2 CBG 261. LW BTC5 0.6276 -I- I 2238' 1 , 1.. -, F 3. 1 �9S6 A 1 7XPIi;,A- 8990' BS2 %7'BKRC]2%o1TP tA)AIGNGR 0.631 ) TOUT W XWV (17.1]A) Sl: 1 EE 5183 P9T0 _ 14164' 047E REV BY COAO.ENfS BY COMMFMS 01n"s OR6INAL COMPLETION TSVPERF CORRECTIONS WR0100 FM 4J60 ADDWSSSV SAFETY NOTE04013106 FaW CST 6 RNO 40ATEREV JC SFTY NOTE WAG ON M 03MM ORS/Rfl PHI: CORRECDONS 12011406 0:110107 TOiPJC PJC ORLG DRAFT CORRECTIONS 4 V7 i BG GOMIGC'TYJN -- - -- - -- .1? F X W 0.9813 41p'IIBS %N 414'. U•]7]5' �� 3'X6 BKR Z%PLTP W1 BS PACKOFF W AFL ,LOCKA O.4.: Ri.,;a1 F BAY L q �j 17.13A FeRW No AS W 50.029-21 200 01 W RISE 2523 46 FE A 51434' FNL BP W16,9W wawa) Hilcorp North Slope, LLC Bo York, PBE Operations Manager 3800 Centerpoint Dr, Suite 1400 Anchorage, Alaska 99503 July 31, 2020 Mr. Jeremy Price, Chair Alaska Oil and Gas Conservation Commission 333 West 7'h Avenue Anchorage, Alaska 99501 Subject: Prudhoe Bay Well PSI -01 (PTD# 202145) Request for an Administrative Approval to continue Water Injection Operations Dear Mr. Price, Hilcorp North Slope, LLC requests administrative approval for continued water injection into Prudhoe Bay well PSI -01 with slow tubing by inner annulus communication. No increase to Maximum Operating Annulus Surface Pressure (MOASP) is required. PSI -01 was flagged on 7/16/20 as having possible TxIA communication and was placed under evaluation at which time it was reported to the AOGCC. To confirm the primary and secondary barriers a passing AOGCC witnessed MIT -IA was conducted on 07/29/20 to 2577 psi while on water injection. Hilcorp North Slope, LLC has determined that well PSI -01 is safe to operate in its current condition and requests an AA for water injection based on the following: • IA pressure can be maintained below MOASP by managing the IA repressurization with periodic annular bleeds. • MIT -IA passed to 2577 psi. • IA and OA pressures will be monitored with wireless pressure gauges. If you have any questions, please call me at 907-777-8345 or Ryan Holt/ Andy Ogg at 659- 5102. Sincerely, Bo York Diaiaiy•....... eo Y' s re em.ime A'... 0.a. zoz000.w 17a1 11 oeaa' Bo York PBE Operations Manager Attachments Technical Justification TIO Plot Injection Plot Wellbore Schematic Prudhoe Bay Well PSI -01 Technical Justification for Administrative Approval Request July 31, 2020 Well History and Status Well PSI -01 is a gas cap seawater injector that was originally drilled in August 2002. The well went under evaluation on 7/16/20 for IA repressurization and passed all diagnostics including an AOGCC witnessed MIT -IA to 2577 psi with the well online on 07/29/20. Recent Well Events: 07/29/20 Online AOGCC MIT -IA Passed to 2577 psi. 07/16/20 PPPOT-T Passed 07/16/20 Anomalous IA repressurization reported to the AOGCC. 09/26/19 Online AOGCC MIT -IA Passed to 2197 psi Barrier and Hazard Evaluation The primary and secondary barriers systems consist of the tubing and production casing and associated hardware. A passing pressure test of the inner annulus to 2577 psi on 07/29/20, which tests both barriers, demonstrates competent primary and secondary barrier systems. Pressure on the inner annulus will be maintained below MOASP of 2000 psi when the well is on-line. Proposed Operating and Monitoring Plan 1. Water injection only 2. Record wellhead pressures and injection rate daily. 3. Submit a report monthly of well pressures and injection rates to the AOGCC. 4. Perform a 2 -year MIT -IA to maximum anticipated injection pressure. 5. IA MOASP= 2000 psi, OA MOASP= 1000 psi 6. The well will be shut-in and the AOGCC notified if there is any change in the wells mechanical condition. TIO Plot TIO Plm —�—Tbp — On / Rw I 0penble NM Open ♦ UMar Erel —MOp NANpN 0011 T t x 000. C> empereWn Injection Plot ELW 9.EV 1}1R' CSp, 66p. l -0D. D' 17400• H 1106' Min'num ID c 6.77V 0 8118' 7' NES RN NIPPLE r TBG.28t,A]63CDt.o=BYir'1-19jlf FEF ORATION SLMMR/ REF LOG. BNCS ON 06105102 ANGLEATTOPPEW 1609310' Note: Raley to Ftoduchon IB lm hiss n l ped d SIZE SPF MHEVAL OPVSgz M 3315 6 9310 9340 O 1112 3316' 6 9300 9370 O IM 3315 6 9416-9434 O 1111 3315 6 9446.9466 O 1111 3315 6 9490 9560 O 062 3316' 6 9570-9630 O O0/2 PSR• CSG, 4», L-60.O2.66r 02W Wellbore Schematic PSI -01 I SAFETY NOTES: WELL RFOUORES A SSSV. rLW260I-W..tLtlS6pl.O.6.27p 97,16' IY F.,�DATL�REV By_i- _-- COISEIRS�DAT[�REV By -i- --- COIREIRS� PRUD/OE BAYtNf MLL'PSWI PERRO W: 5DTi450 API W: 50-02923104 SEC 15 Tlt RISE 14WFW&701'FVA DATE Y OB6S02 _.. DAVKK OWDMW. CONPLETON BWIWt9' JVWMJ SETH1ECiCN VALVE F6Ni _- PERPB Od1720 A1551JMD F61L I1EC1gNVALVE _ i AODEPTNCOTIGN N j BO TNRAM, MM 1/6662 01.!X116 112062 JBIIP AODPEf60 126902 _ DR9M CTION _�_— PERFCWQiEC7ON SP E4pb-b-FAb$Mr 09/1MI1 IIBAAID A�DSSSVIUWFWNOTE Hilcorp North Slope, LLC Bo York, PBE Operations Manager 3800 Centerpoint Or, Suite 1400 Anchorage, Alaska 99503 July 31, 2020 Mr. Jeremy Price, Chair Alaska Oil and Gas Conservation Commission 333 West 7"' Avenue Anchorage, Alaska 99501 RECEIVED By Jody Colombie at 7:51 am, Aug 06, 2020 Subject: Prudhoe Bay Well PSI -01 (PTD# 202145) Request for an Administrative Approval to continue Water Injection Operations Dear Mr. Price, Hilcorp North Slope, LLC requests administrative approval for continued water injection into Prudhoe Bay well PSI -01 with slow tubing by inner annulus communication. No increase to Maximum Operating Annulus Surface Pressure (MOASP) is required. PSI -01 was flagged on 7/16/20 as having possible TxIA communication and was placed under evaluation at which time it was reported to the AOGCC. To confirm the primary and secondary barriers a passing AOGCC witnessed MIT -IA was conducted on 07/29/20 to 2577 psi while on water injection. Hilcorp North Slope, LLC has determined that well PSI -01 is safe to operate in its current condition and requests an AA for water injection based on the following: • IA pressure can be maintained below MOASP by managing the IA repressurization with periodic annular bleeds. • MIT -IA passed to 2577 psi. • IA and OA pressures will be monitored with wireless pressure gauges. If you have any questions, please call me at 907-777-8345 or Ryan Holt/ Andy Ogg at 659- 5102. Sincerely, oisiv,ny:�go.a ov eo vo,x Bo York —.I_�s uasm aq*,.,k xe Nonn sm>e.m.i W1111l1-co oa,e: soso oa oa rzse1a-oeoa Bo York PBE Operations Manager Attachments Technical Justification TIO Plot Injection Plot Wellbore Schematic Prudhoe Bay Well PSI -01 Technical Justification for Administrative Approval Request July 31, 2020 Well History and Status Well PSI -01 is a gas cap seawater injector that was originally drilled in August 2002. The well went under evaluation on 7/16/20 for IA repressurization and passed all diagnostics including an AOGCC witnessed MIT -IA to 2577 psi with the well online on 07/29/20. Recent Well Events: 07/29/20 Online AOGCC MIT -IA Passed to 2577 psi. 07/16/20 PPPOT-T Passed 07/16/20 Anomalous IA repressurization reported to the AOGCC. 09/26/19 Online AOGCC MIT -IA Passed to 2197 psi Barrier and Hazard Evaluation The primary and secondary barriers systems consist of the tubing and production casing and associated hardware. A passing pressure test of the inner annulus to 2577 psi on 07/29/20, which tests both barriers, demonstrates competent primary and secondary barrier systems. Pressure on the inner annulus will be maintained below MOASP of 2000 psi when the well is on-line. Proposed Operating and Monitoring Plan 1. Water injection only 2. Record wellhead pressures and injection rate daily. 3. Submit a report monthly of well pressures and injection rates to the AOGCC. 4. Perform a 2 -year MIT -IA to maximum anticipated injection pressure. 5. IA MOASP= 2000 psi, OA MOASP= 1000 psi 6. The well will be shut-in and the AOGCC notified if there is any change in the wells mechanical condition. TIO Plot TIOPIm tT g On ■ ■eetl ♦ N.10 Ngl Opw ♦ MANU.dJeI i—MAN IAA MAN 0A MAN OOA MAN OOOA - TempertNrt Injection Plot Wellbore Schematic TACE = I Ills, 5K clw Rff LOO BHOS ON CLOS92 YVELL14FAD=13 SW 5K FMC7 Nolo: Refer D Roduclion 08 fn helorcal perl date PSI -01 ACTUATOR= WEWAL Op%MW KB I3_EV = 52 10' 1318' 6 OF &EV = 34 50' O IMAM 1318• 6 9340-9370 KOP= 1111692 1316' 6 9416-9434 0 fAv Angle = 36 Q 3477 13C 6 94489468 O 11/1602 Da1urnw. 9819 6 9490 - 9560 O 062092 1318' DoWm.TVD= 6500'SS 9.570 - 9630 O 0621102 �$7A•CSC.ea,L-EO,D•1x 4OD' - 6106•__ 'nun IDs 6.770" e 8119' 7" NES RN NIPPLE _ FEWORAT10N S~RY Rff LOO BHOS ON CLOS92 ANGLEAT TOPPEW. 1809310' Nolo: Refer D Roduclion 08 fn helorcal perl date SIZE SFF WEWAL Op%MW DATE 1318' 6 9310-9340 O IMAM 1318• 6 9340-9370 O 1111692 1316' 6 9416-9434 0 1111692 13C 6 94489468 O 11/1602 139r 6 9490 - 9560 O 062092 1318' 6 9.570 - 9630 O 0621102 WW LSC, 47X.L80, D=8.861• 6266' wID 6W rLNf,20o, L-00..0781 Eq. U�e.xxe- 67'11• SAFM NOTES: WELL REOUARES A SSSV. SItIGYGOA-1 f11EC1DN VALVE, IOVIYA) �. "-Fm riN OAl HJECTDNVALVE,M sr ("viol DAZE REV BY ' COMMENTS I -DATE - -REV BY 1 COVEN PRLDHOE 6AYLW 080002 018MM2 NIt"2 DAVrKK ORCJ4AL COMPI.FDON TMWKK'PERFS CC4NK xO DEPTH CORRECTDN 09/161119 JMOMID SE7211ECiDN VALVE FISH 01W7120 _ 1ASSOMD FHt911EC19NVALVE I 1V1007 2AWI Je ADDPERFORAT6 " CORREC7DN I 02nW11 WWMD MMD (ADDDDED SSSV SAFElYAg1E _ _ j NEIL 25HH PERMR Ab:/1021450 API No: 5002223104 SEC /S Tt1 R15E 1482FNLA TOt'FYA 6P E�pbtlbn (AYMu) Hilcorp North Slope, LLC Stan Golis, PBW Operations Manager 3800 Centerpoint Dr, Suite 1400 Anchorage, Alaska 99503 July 21, 2020 Mr. Jeremy Price, Chair Alaska Oil and Gas Conservation Commission 333 West 71h Avenue Anchorage, Alaska 99501 Subject: Prudhoe Bay Well R -22A (PTD# 214164) and lateral R-22AL1 (PTD# 214165) Request for an Administrative Approval to continue Water Injection Operations Dear Mr. Price, Hilcorp North Slope, LLC requests an amendment to AIO 4G.008 for continued water injection into Prudhoe Bay well R -22A and lateral R-22 AL1. No increase to Maximum Operating Annulus Surface Pressure (MOASP) is required. R -22A/ R-22AL1 has operated under AIO 4G.008 since 2018 after exhibiting anomalous IA repressurization while on miscible gas injection. At the time there was no repressurization seen when on water injection and service was limited to water injection only. On 07/17/20 R -22A/ R-22AL1 was reported to the AOGCC for showing signs of slow IA repressurization while on water injection. To confirm the primary and secondary barriers a passing AOGCC witnessed MIT -IA was conducted on 07/20/20 to 2754 psi while on water injection. Hilcorp North Slope, LLC has determined that well R -22A/ R-22AL1.is safe to operate in its current condition and requests an AA for water injection based on the following: • IA pressure can be maintained below MOASP by managing the IA repressurization with periodic annular bleeds. • MIT -IA passed to 2754 psi. • IA and OA pressures will be monitored with wireless pressure gauges. If you have any questions, please call me at 907-564-5231 or Ryan Holt/ Andy Ogg at 659- 5102. Sincerely, t, Stan Golis PBW Operations Manager P'sl BP Exploration (Alaska) Inc. Ryan Daniel, Well Integrity Engineering Team Lead Post Office Box 196612 Anchorage, Alaska 99519-6612 December 09, 2019 Mr. Jeremy Price, Chair Alaska Oil and Gas Conservation Commission 333 West 7'" Avenue Anchorage, Alaska 99501 Subject: Prudhoe Bay Well 11-07 (PTD # 1811770) Administrative Approval Request Dear Mr. Price, by 0 BP Exploration (Alaska) Inc. requests an Administrative Approval (AA) for continued water injection into Prudhoe Bay well 11-07. No increase to normal operating limit is required. Well 11-07 (PTD # 1811770) is a produced water injector that previously operated under Administrative Approval 4G.004 for IAxOA communication. The well was worked over in October 2019 to resolve the IAxOA communication by installing new 7" casing and 4.5' tubing. Post rig work over and prior to placing the well on injection, an AOGCC witnessed MIT -IA passed to 3,216 psi and MIT -T passed to 2,671 psi on 11/04/19. The well was placed on injection on 11/06/19 and shortly thereafter was made Under Evaluation on 11/11/19 after it exhibited anomalous Inner Annulus repress urization. While the well was online, an AOGCC witnessed MIT -IA was performed and passed to 2,708 psi on 11/16/19 confirming the well has two competent barriers to formation. The well does not show IAxOA communication and 4G.004 has been canceled. Wireless gauges have been installed on DS -11 wells that allow for real time monitoring of IA and OA pressures. BPXA has determined that well 11-07 is safe to operate in its current condition and requests an AA for water injection based on the following: IA pressure can be maintained below NOL by managing the IA repressurization with periodic annular bleeds. MIT -IA passed to 1.1 times maximum anticipated injection pressure. IA and OA pressures will be monitored with wireless pressure gauges. If you have any questions, please call me at 907-564-5430 or Ryan Holt at 659-5102 Sincerely, Ryan Daniel BPXA Well Integrity Engineering Team Lead DEC 10 2019 AOGCC Attachments Technical Justification TIO Plot Injection Plot Wireless Gauge Plot Wellbore Schematic Cc: Doug Cismoski Lau/Holt FS2 Operations Team Leader Travis Alatalo Ryan Daniel Oliver Sternicki Travis Smith Prudhoe Bay Well 11-07 Technical Justification for Administrative Approval Request December 09, 2019 Well History and Status Well 11-07 (PTD # 1811770) is a produced water injector that previously operated under Administrative Approval 4G.004 for IAxOA communication. The well was worked over in October 2019 to resolve the IAxOA communication by installing new 7" casing and 4.5' tubing. Post rig work over and prior to placing the well on injection, an AOGCC witnessed MIT -IA passed to 3,216 psi and MIT -T passed to 2,671 psi on 11/04/19. The well was placed on injection on 11/06/19 and shortly thereafter was made Under Evaluation on 11/11/19 after it exhibited anomalous Inner Annulus repressurization. While the well was online, an AOGCC witnessed MIT -IA was performed and passed to 2,708 psi on 11/16/19 confirming the well has two competent barriers to formation. The current IA repressurization rate is —95 psi/hr, stabilizing at 1030 psi with a tubing injection pressure of 1375 psi. The well no longer shows IAxOA communication post rig work over. Recent Well Events: 11/16/2019 Online AOGCC MIT -IA Passed to 2708 psi. 11/11/2019 Well Under Evaluation for anomalous IA repressurization. 11/6/2019 Well placed online. Offline AOGCC MIT -IA Passed to 3216 psi. MIT -T passed to 2671 psi. MIT -OA 11/4/2019 passed to 1153 psi. 10/26/2019 CDR2 RWO to run new 7" casing and 4.5" tubing completed. 9/18/2019 CMIT-TxIA Failed, LLR=2.5 gpm. Barrier and Hazard Evaluation The primary and secondary barriers systems consist of the tubing and production casing and associated hardware. A passing pressure test of the inner annulus to 3216 psi on 11/04/19, demonstrates competent primary and secondary barrier systems. Pressure on the inner annulus will be maintained below the normal operating limit of 2000 psi when the well is on-line. Proposed Operating and Monitoring Plan 1. Water injection only 2. Record wellhead pressures and injection rate daily. 3. Submit a report monthly of well pressures and injection rates to the AOGCC. 4. Perform a 2 -year MIT -IA to 1.1 x maximum anticipated injection pressure. 5. The well will be shut-in and the AOGCC notified if there is any change in the wells mechanical condition. O a 0 g a 8 'Qog$o'moz°3� 111 *10+++ ' I v kug{85 el mmw,.w,o k r $ A R R d 8& 3 S. S R R e ' I v kug{85 el Y 0 a 0 Y V d .L ��'n GZI'JOO 'l s �'. .� N _ .� ti .. - O .: 0�®© Y a 0 d rn R c� N N d d L] Fmc —�E67 95N'TBG STUB 60' � 11-07 M9X An6b- 32'Q Nar I2WCONDl1CTOR 141 OB09A MD • 9313• 191 89. H10, OsWM TVD = $am, 55 9 • 19121' �i->.9•cso. Tz9.La9 BTc.o-tz.3ar j-je6B'__. Minimum ID = 3.856" @ 8418' 7^ X 4.1/2" HES TNT PKR 9-518.05O,L-BOLTCXOTO50O95LTCBM 7621• 7-CS0.269,L20VAMTOPHQD•8318•-7 607W TOP OF 7-LNR H 6062• 412.134RRATCHUTCHASSY.10.3.919-�--{ 8389' 1-12' TBG, 1299, L20 VAM TOP. 6576'- 9t520pLD•3.95e• 4� 12•TBG STUB l SS70' ' PERFORATIONSLWMAR'Y -- REF LOG: BRCS ON 0505182 ANGLE AT TOP PERF: IV @ 9159 Wk Rckrb Pm01c99n DB brNWtkel er109b SVE SPF INTERVAL _ r �2-74• 8 1 9150-9175 O 2-718• B 9205.9225 O 115' 1 0296-9312 O 9-516' CSG, 179, 50095 LTC BTRS, D - SAW- 612V D= 3.958• 1-12' TBG, SAFETY NOTES: WELL REQHI9ES A SSSV WHEN ON ME ••• Sr GRP FROM W LEGE 6663' TO PNR Q 8150•. TBG TAI, PARTED@ 6771' DUfBNG O408 RW O ISEE ASM — 1 Hi s%NP_D•3 air 7972' — 95A' x 7- HE S IN T PKR, 0-590V 8070' l'WLEG.0.6202- 6082' 1, —71 HOR A TESACK SLV, o•e91r 9-5M-MLLDU7V4MOW(TU07ST) 9287•-BJ31� p82-- _ I-ja-1rz• HES % W. D - 3 81r 6115' n�7'%1-IQ'HEB TN7 PKR.O •J.e56' w HEsXw.ID-3e1r- 86671'—1-1?F�%NP,D-J.Dtr 6677" —7'%1- 12' SXR S3 PKR D - 3.87V 8612' —/-12'H5XFP,D-3.513- PB1D 9137 r LNR,2B9, L-0 NSCC..O3e39PGD-8176' 6172' DATE REV BY COMMEMB PATE REV BY COYMENI9 M920R2 R36 ORDNALCOMPLE7DN 1120119 JNIAID ADPERFS 75RSR2 R2E5 SDEl1TACN 1I-0 S 01NIA9 MES AM 1O 0 N-COR2 RWO 11MV19 _ MD DRLGHOCORRECTDNS 11/1119 TIllMD FINALODEAPPROVAL - -- -- ION' PRUDHOE BAYUNR WELL 1147 PERIAR W: 1!11710 API W: 50028-2068740 BP EXPId-t001Ak9M) TBG )8V 20 by BP Exploration(Alaska)Inc. Ryan Daniel, Well Integrity Engineering Team Lead Post Office Box 196612 Anchorage, Alaska 99519-6612 December 09. 2019 Mr. Jeremy Price, Chair Alaska Oil and Gas Conservation Commission 333 West 7'h Avenue Anchorage, Alaska 99501 Subject: Prudhoe Bay Well 11-07 (PTD # 1811770) Request for Cancellation of Administrative Approval 4G.004 Dear Mr. Price, BP Exploration (Alaska) Inc. requests cancellation of Administrative Approval 4G.004. The approval, originally issued February 16, 2017, was for continued water injection with inner annulus by outer annulus communication. The well recently had a rig work over which was completed on October 26, 2019 where new 7" casing was run resolving the inner annulus by outer annulus communication. Post rig work over the inner annulus began showing anomalous repressurization when on water injection. An Administrative Approval request will be submitted for permission to continue operating 11-07 with TAA communication. If you have any questions, please call me at 907-564-5430 or Ryan Holt at 659-5102. Sincerely, � /J Ryan Daniel BPXA Well Integrity Engineering Team Lead P• +L— 16-4 16..0 DEC 10 2019 AOGCC 19 BP Exploration (Alaska) Inc. Attn: Well Integrity Coordinator, PRB-20 Post Office Box 196612 Anchorage, Alaska 99519-6612 June 07, 2019 Mrs. Jessie Chmielowski =RENEE Alaska Oil and Gas Conservation Commission JUL 0 9 2019 333 West 7th Avenue /'� Anchorage, Alaska 99501 !`/� i®lap'� l� C Subject: Prudhoe Bay Unit Well 16-14 (PTD # 2060030) Application for Cancellation of NO Administrative Approval 4G.007 Dear Mrs. Chmielowski, BP Exploration (Alaska) Inc. requests cancellation of AIO Administrative Approval 4G.007 dated September 18, 2017. The administrative approval was for continued WAG injection with tubing by inner annulus communication. Well 16-14 was rotary side tracked in March 2019 under PTD #2181170 and was completed with new production tubing. The well no longer exhibits annular pressure communication therefore it is requested to cancel Administrative Approval 4G.007. If you have any questions, please call me at 564-5430 or Ryan Holt/ Adrienne McVey at 659-5102. Sincen Ryan, Danie- BPXA Well Integrity & Compliance Team Leader Attachments: Wellbore Schematic Cc: Doug Cismoski Bill Isaacson Meredyth Richards Ryan Holt / Adrienne McVey Aras Worthington Well Schematic TFWE NO WELLHEAD` VFTCO GRAY; 16-14C SAFETYNOTES: WELL REWIRES A SSSV WHEN OM ACTUATOR- BAILER 'S ' 9ry,_ WELL ANGLE > 70'@ 10619"- MA% OLS: 15Y OKB. ELEV = 70 10597'. "'CHROME TBG O LRR- REF ELEV• 9617' 5 740 C 0324019 BF. ELEV 24 10655 NA KdP= uarj 2195' I +.12•He9xHr. o-secI- I I FF MtN[A1pN= 46•Q1779B'{ _J Ds06R MD- 10280'1, 22 7211, L -0O BTC, __— . 7329• 9-SAI'%i'WFD LTP-TEBACK SLEEVE 2.341' D=1I D MPHR rIGR,D+5.190• 9-SV8'SLBWl4P5TOCK(03W2t19) -'-7499*_ 'rr-SR-CSG. 47 LL808TC.10-"or —7499•_' ML-LOUIWNDDWIIb14CI 149W-1513' �- T' TOC PER CBL LOG 0320997-659' -- ♦I 10012'J�4-12'9,83 %YiP.D-9,813' Minimum ID = 3.813" @ 2103' 4-112" HES X NIPPLE 10040'—7'%4-V2-HESTNTPKR,1D-3856' y 10074' J-!4.12'HES%N6,D-3,813• 10123• 7•%1-HRD-E ZXP LIP W76EBACK SLEEVE 6 NFD HCR, ID=4.250- 10132' +4-/2'VAEG.D-3.941' /-10175' -ELMO IT LOGGED 0320119 4-1YC L6O II00. 13CM44 YAM TOP. h 10132' 01520p1.ID-3959' 4_10154' �5'X41R'%O,D=)900' NCC TnACPO1IT CLVC.0 - 2A70' PSTD- 161820' 4-12' LNR, 12 66, 13 -CR HTTC. 0152 bpl, D - 3 950' - 16906- 0327.116 1 JMO DATE RFV BY COMMENTS PRUDHOE BAY UNR 04.NNI9 JDWJMO OPENED FRAC SLEEVES WELL. 16-14C 043299 JNWMD ADDED BF ELEV PEXIM M. 210 n7 OM1M19 DOWJND- FNAL ODE APPROVAL API Nn- S"70-7057043 ON19H9 JNUJ40 REF ELEV UPDATE SEC 24, TION, R1 SE, 1530 FNL 8 529' F0A ' 9P ! %pEr4lbn (LY9N4) NO DEPT) i. SEAT SZ ACTUAL SZ OIG DA IE T LNR 360 L-00 VAM TOP HC, 10296' i 21 26 10331 NA 10399 NA $-740 C 032"19 5.740 C 0320119 0363 bpf D - 6 21G- 25 10509 NA 5 740 C 0324019 24 10655 NA 5.740 C 032MIO 23 IONS NA 5 740 C 0324019 22 11405 NA 5 740 C 032M19 ' 21 20 11515 NA 11914 NA 5.740 C 0320119 5.740 C 032M19 r # 19 12024 NA 5740 C 032"19 16 12362 NA 5 740 C 032M19 17 12492 NA 5140 C 0312099 16 15 12850 NA 12959 NA 5140 C 03MIS 5 740 C 0320!19 4' r 14 13401 NA 5 740 C 0328119 1 13 13510 NA 5140 C 03IM19 > ♦ 12 13952 NA 5740 C 032m9 11 14061 NA 5.740 C 032m19 10 1M59 NA 5.740 C 0324019 9 a 14569 NA 15051 NA 5 740 C 032M19 5.740 C 0324079 r 1 15159 NA 5.740 C 0320119 r 6 15642 NA 5.740 C 0320119 5 11161 NA 5.140 C 0320119 4 16109 NA 5 740 C 0320719 a 3 18219 NA $ 740 C 032"19 r 2 16618 NA 5.740 O 031!"19 PSTD- 161820' 4-12' LNR, 12 66, 13 -CR HTTC. 0152 bpl, D - 3 950' - 16906- 0327.116 1 JMO DATE RFV BY COMMENTS PRUDHOE BAY UNR 04.NNI9 JDWJMO OPENED FRAC SLEEVES WELL. 16-14C 043299 JNWMD ADDED BF ELEV PEXIM M. 210 n7 OM1M19 DOWJND- FNAL ODE APPROVAL API Nn- S"70-7057043 ON19H9 JNUJ40 REF ELEV UPDATE SEC 24, TION, R1 SE, 1530 FNL 8 529' F0A ' 9P ! %pEr4lbn (LY9N4) BP Exploration (Alaska) Inc. Aras Worthington, Well Integrity Engineer Post Office Box 196612 Anchorage, Alaska 99519-6612 February 8, 2017 rdtiCIVSD FEB u8 2018 by 0 Mr. Hollis French AOGCC Alaska Oil and Gas Conservation Commission 333 West 7'" Avenue Anchorage, Alaska 99501 Subject: Prudhoe Bay Well R -22A (PTD # 2141640/2141650) Request for an Administrative Approval for continued water Injection Operations Dear Mr. French, BP Exploration (Alaska) Inc. requests an Administrative Approval (AA) for continued water injection into Prudhoe Bay Well R -22A. The well exhibits slow tubing by inner annulus communication, historically this has been prevalent while the well is injecting gas. However, the well passed a MIT -T to 2,567 psi on 5/19/2017 and an MIT -IA to 3,761 psi on 3/27/17, indicating the tubing and production casing are competent barriers. In summary, BPXA has determined that Prudhoe Bay well R -22A is safe to operate as stated above and requests Administrative Approval for continued water injection operations. If you have any questions, please call me at 564-4102 or Jack Lau/ Adrienne McVey at 659- 5102. Sincerely, Aras Worthington BPXA Well Integrity Engineer Attachments Technical Justification TIO Plot Injection Plot Wellbore Schematic Cc: Louis Romo Lau/McVey FS1 Operations Team Leader Matt Bergene Ryan Daniel Prudhoe Bay Well R -22A Technical Justification for Administrative Approval Request February 8, 2018 Well History and Status Well R-22 was initially drilled in September 1983 as an Ivishak producer. In June 1991, a RWO was completed to replace the tubing. The well was converted to an injector in 1998. In January 2016 a CTD sidetrack was performed completing the well as a multi -lateral Sag injector. Since the well was put on injection post -CTD it has injected only MI. While injecting MI the well exhibits IA repressurization. After diagnosing the repressurization it appears to be tubing by inner annulus communication to MI when the well is online. In January 2017, a caliper log indicated that the tubing was in good condition, 3 joints with 20- 23% wall loss and 264 joints with 0-20% wall loss. The well passes all pressure tests with fluid but exhibits IA repressurization when injecting MI. An LDL was run on 5/18/17 and a potential leak was identified. A patch was set over the potential leak, but it did not reduce the tubing by inner annulus communication. This patch will be removed prior to putting the well on injection. The well is due for a AOGCC witnessed MIT -IA. After the approval of this AA the well will be put on injection under evaluation and a AOGCC witnessed MIT -IA will be performed. The well most recently passed an MIT -T to 2,567 psi on 5/19/17, an MIT -IA to 3,761 psi on 3/27/17, as well as a PPPOT-T to 5,000 psi on 4/1/17. Recent Well Events: > 11/19/17: Patch set from 8,280 - 8,315' MD over potential anomaly, Pulled TTP from 10,011' MD, IA repressurization rate did not change after setting the patch > 05/19/17: Set TTP @ 10011' MD, MIT -T Passed to 2567 psi > 05/18/17: Ran LDL - TxIA Leak to MI — no definitive anomalies > 04/01/17: PPPOT-T Passed to 5000 psi > 03/27/17: MIT -IA Passed to 3761 psi > 03/25/17: PPPOT- T Passed; -IC Failed > 01/28/17: Set TTP @ 10000' MD, MIT -T Passed to 3775 psi, MIT -IA Passed to 3648 psi, Pulled TTP > 01/08/17: Caliper Tubing 264 its 0-20% 3 its 20-23% > 12/21/16: Pulled EVO from 9917' MD, Set WRP @ 10616' MD, MIT -T Passed to 3493 psi, CMIT-TxIA Passed to 3634 psi, MIT -IA Passed to 3711 psi > 12/20/16: Set EVO @ 9917' MD, MIT -T Passed to 3615 psi, CMIT-TxIA Passed to 3590, MIT -IA Passed to 3708 psi Barrier and Hazard Evaluation The primary and secondary barriers systems consist of the tubing and production casing and associated hardware. A passing pressure test of the tubing to 2,567 psi on 5/19/17 and of the casing to 3,761 psi on 3/27/17 demonstrates competent primary and secondary barrier systems. Pressure on the inner annulus will be maintained below the normal operating limit of 2000 psi when the well is on-line, and the outer annulus will be maintained below the normal operating limit of 1000 psi when the well is online. Proposed Operating and Monitoring Plan 1. Water injection only. 2. Record wellhead pressures and injection rate daily. 3. Submit a report monthly of well pressures and injection rates to the AOGCC. 4. Perform a 2 -year MIT -IA to maximum anticipated injection pressure. 5. The well will be shut-in and the AOGCC notified if there is any change in the wells mechanical condition. Well R -22A TIO and Injection Plots ■ ■ 11111 m zsw zua 2200 NOD iwo 1600 1600 :~ ` 1'f0 iC0 q Acs Irl 6CG AA 111317 11.TTI7 IZI VI7 122517 rm ab ISD ,W 140 40 10 02MIF TIO Plot + Tby t to —A— CIA OOA + OOOA On ■ Bleed ♦ Operable + Not Oper ♦ Under Eval Temperature -UATOR= BAKER 3. E.EV = 75.04 ELEV = 39.71' '_ _ 3200' Arm= 120°10781' m MD= 10495' mTVD= 6600 SS MNXCMR_O, , D= VA' GSC 720 I .M RTS n a Minimum In = 1 92n" ® 11986' SHORTY DEPLOYMENT SLV LNRf !- LMT, 9-30, L-80 STL, �.1003C r bpC. D 2.992^ WI71(11@9114) 10058'-10069' 7DPOrT NRI—FI-01-3T 4-112' TBG, 1264. NT-13CR-80. 10165 .0152 bpt, D - 3-958' �?55' CSG, 479, L -8O 8Uff, D = 8.681' I� 10380" .W 260, L -0O 9UTT..0383 bpL. D - 6.276' PEiFORATDN SUMMARY ---� REF LOG. __OH%w%w14 ANGLE AT TOP PERF. WA Note: Refer b RoducWn 08 for tbbrmal pert data SVE SPF MERVAI Oprd8gz SHOT SO7 PORr R -22A 5 2-318' SLOT 11306-12532 1 SLTD 12!31114 R 23A Lt RA 2-318' SLOT 11207-12523 SLID D1MIS 4 R-2 2 A SAFETY MAX DLS 39.7 07 1'..'L•'4-112' CHROME Ll Tec•• 2O2Y_ a-tlr OTS RaO �. D = 3.813' ST MD TVD 45K13 LTP w 1116 NSA (01128/17) TY PE VLV LATCH PORr DATE 5 3092 3090 Dbtt' RA 0 03110!96 4 5940 5425 DAM R5 0 06110191 3 6292 1174 143rom ALLY R4 0 11/16116 2 9666 8410 DAM RA 0 0611051 1 10032 8516 'OMY M 0 03/10/98 -alAw I -LMT VMtJlltUj17JU7J14I "STA 13 - D(TE ED PACKING & COVERED BY PATCH 10000' 45K13 LTP w 1116 NSA (01128/17) 10007' _-_.�..__.- 4170' 6KR DEPLOY SLV. D = 3-00' -.._... 10011' 1--�2-7fa^ __. % NP, D _— 10020• . {al/r TIFS%NP, D-2.812' 10034• H3-112•x3-114'%O.1O-2.786- +amo"_( BENNO K+3.961 CT LNR K 1 7ul Al -J!Lw a(R SN5 NP, D - 3.813' I BEHIND 10137-{0-5ie• % 7^ _ _Tp a HGR r) = C T LNR 10163' a -1/r PKR SVAJ NPS t4LL®TO 3.BD• (121031117 BENNO 10168' 4-IQ-V%AT =3656- CT LUR 1 10164'-Jt3LDTTL000E 0611641 MLLOU i wNJDW (1L -22A) 10483' - 10493- A 11205' 112636• SFDRTY DELCY SLV. D- 1.9211• I TZ27CCT ------------------ 2-5hT'SLTD UNI, 12526• ` 4.79, L-8017511, 7C e.6O, 11291• ``1�2a.A .0O39 W, D=1.995• Lind -- 2.70'FLOW-170L1 BLLLT 11299' 2-3/e'SLTD Lii3, 4.7p,L-001}{511, 12534 1.0039 bpC, D =1,9951 - DATE FEV BY COMMENTS DATE REV 6Y COMMENTS 69019183 ALAR ORCINALCOMPLETION 05123/17 LLl'1 SO%J( PLUG(05/20'17) 660/2/81 0.16 M PO 297 1117 PULLED %% FtLiu (11113711) 11/25117 6TW SET wFD PATCH (17/ 19117) 0110&15 46faC, CTD MULTILAT (R -22A 0 Li) 01023115 TBUME) FO64LCCEAFPRDVAL 1217116 S0 RA -1 R.IJGISFT WRP(1211321/16) 02114117 CJWJ D FULLED VYWSEr LTPw/PrSA PRBAHOE BAY LNT.._ WELL R -22A IL7 FT:TddT W: 21416401 2141650 AS No. 50029-2100501 (60) SFC 32, T12K R13F, 257 FSL 6 2337' FFL BP 6lploratlo8 (Aleekal 17 BP Exploration (Alaska) Inc. Ryan Daniel, Well Integrity Engineering Team Lead Post Office Box 196612 Anchorage, Alaska 99519-6612 August 28, 2017 Chair Hollis French Alaska Oil and Gas Conservation Commission 333 West 71 Avenue Anchorage, Alaska 99501 RECEIVED by SEP 07 2011 P f'�OGV�//0ps 0 Subject: Prudhoe Bay Well 16-14B (PTD #2060030) Request for an Administrative Approval for WAG Injection Operations Dear Mr. French, BP Exploration (Alaska) Inc. requests an Administrative Approval (AA) for water alternating gas (WAG) injection into Prudhoe Bay well 16-14B. No increase to normal operating limit (NOL — formerly MOASP) is required. Well 16-14B was placed under evaluation on May 5, 2017 due to IA repressurization while injecting MI. After monitoring the well through bleed events the tubing by IA communication was confirmed and the well was made not operable on June 2, 2017. The IA pressure stabilizes under NOL and will not require bleeds during normal operations. Wireless pressure gauges have been installed on DS 16 wells allowing for monitoring IA and OA pressures in real time. Obtaining an AA to continue MI injection in 16-14B would enable completion of the current MI cycle in 16-14B and then move uphole for the 6th cycle of MI injection, with cumulative incremental response in the offset producers estimated at approximately 150 bopd. In summary, BPXA has determined that Prudhoe Bay well 16-14B is safe to operate in its current condition passing an MIT -IA to 1.1 times maximum anticipated injection pressure. In addition, the IA pressure will be monitored in real time with wireless gauges. BPXA requests an AA for WAG (including MI) injection operations. If you have any questions, please call me at 907-564-5430 or Jack Lau/ Adrienne McVey at 659-5102. Sincerely, Ryan D BPXA We ntegrity Engineering Team Lead Attachments Technical Justification TIO Plot Injection Plot Wireless Gauge Plot Wellbore Schematic Cc: Doug Cismoski Lau/McVey FS2 Operations Team Leader Danielle Ohms Ryan Daniel Oliver Sternicki Michael Hibbert Todd Sidoti Prudhoe Bay Well 16-14B Technical Justification for Administrative Approval Request June 26, 2017 Well History and Status Well 16-14B is a horizontal MIST injector drilled and completed in Zone 2 in March 2006. The well supports 6 active offset Producers. The plan for this well was to have six sets of perforated injection intervals, with a CIBP set to isolate lower perforations each time. MI is injected into each set with each "plug -pert -MI injection" cycle lasting 1- 2 years before moving uphole. The well was in the middle of the 5th MI cycle when IA repress urization occurred. The well has been not operable since June 2, 2017. Recent Well Events: > 03/06/06: Rig ST complete MIT -T Passed to 4000 psi, MITIA Passed to 4000 psi > 06/09/06: AOGCC MITIA Passed to 2500 psi > 06/25/07: OART complete no BUR > 07/09/07: Set new MCX SSSV @ 2193' > 12/15/09: MITIA Passed to 4000 psi > 06/01/10: AOGCC MIT -IA Passed to 2500 psi > 12/03/10: PPPOT-T Passed to 5000 psi > 12/06/10: Oper call in IAP @ 2300 psi > 12/08/10: MIT -IA Passed to 3750 psi > 05/07/12: Pulled SSSV > 05/30/12: Set SSSV > 11/22/13: PPPOT-IC Passed > 04/11/14: MIT -IA Passed to 4000 psi > 04/20/14: Pulled MCX > 05/09/14: Set MCX > 05/24/14: AOGCC MIT -IA to 3200 psi Passed > 05/07/17: MIT -IA passed to 3195 psi > 05/09/17: PPOT-T passed to 5000 psi > 06/23/17: Plug set @ 9793' MD, MIT -T passed to 2582 psi, MIT -IA passed to 2682 psi > 07/27/17: MIT -IA passed to 3850 psi Barrier and Hazard Evaluation The primary and secondary barriers systems consist of the tubing and production casing and associated hardware. A passing pressure test of the inner annulus to 3,850 psi, which tests both barriers, demonstrates competent primary and secondary barrier systems. Pressure on the inner annulus will be maintained below the normal operating limit of 2000 psi when the well is on-line. Proposed Operating and Monitoring Plan 1. WAG injection (including MI). 2. Record wellhead pressures and injection rate daily. 3. Submit a report monthly of well pressures and injection rates to the AOGCC. 4. Perform a 2 -year MIT -IA to 1.1 x maximum anticipated injection pressure. 5. The well will be shut-in and the AOGCC notified if there is any change in the wells mechanical condition. TIO Plot Well: 16.14 —Tubing — IA —0A —On r Bleed 1 Underfval Not Operable Temperature Injection Plot Well: 16-14 3,Om � 25,606 2'500 '�' 20,0OO s —WHIP 2,0WT ;- — 961 – 15,000 PW 1,500 —Mi 10.ODD q —GI 10()0 Q — Other 5,000 — On 0N5117 03'12117 01317 03'25117 04Y1217 4517 WTV (WM17 041317 05f07117 514117 52117 OSS!" 0&'04117 Minirllum ID = 3.725' @9793' 4-112" HES %N NIPPLE �a-5r5 ['Sc,47P, r+ea,D=asst• --I 9772' 4 -Ire T8G 12.BP, L -8D TCA 0/521* D= 3.958' 1 9806' 4-117 LM 12.6A, LdO, O = 3.Vbr PE FOR471DN SLIAMKRY RPF LOG MAD CT ON 02A ANGLE AT TOP PEW 91"4@11541' 2 L'S TREE- 4 Dt6.OW VIELLHPAD= VETOO GRAY 6 ACTUATOR= BAMER 2-7/S MCS. dk = - - _ _ AT C BF. M"= 40.43 13400 13425 KOP= - -_. —._ OF" A1D MAIC • 9T a 13355' 2415" o4mmw_ s" C Nt TVD- 88001405 13475 13500 113'5 2715 C'SC, 728, L-04 D=12.74T 2076' _ Minirllum ID = 3.725' @9793' 4-112" HES %N NIPPLE �a-5r5 ['Sc,47P, r+ea,D=asst• --I 9772' 4 -Ire T8G 12.BP, L -8D TCA 0/521* D= 3.958' 1 9806' 4-117 LM 12.6A, LdO, O = 3.Vbr PE FOR471DN SLIAMKRY RPF LOG MAD CT ON 02A ANGLE AT TOP PEW 91"4@11541' 2 L'S 6 11750 11782 O 2-7Ar 6 11968- 120W O 2-7/S G 12440 125.'!0 C 2 41Y 6 13400 13425 C 24fY8 1,5425 1.7450 C 2415" 8 13450 13475 C 24/7 6 13475 13500 C 2715 1 6 14150-14250 C 16-146 OB14NfETYNOT6B: WELL REQNRESASS6VW"E ML WELL ANGLE I M Q10/89'. AS OE V211M, PO8918L.E SOLIDS IN TOP Of LM DUE TO NIL L ING ON r 1 1 1 1 1 7 2193' j—{4-12. 43XNP D-3.B1T 8773'&b'8'%/"dKR fMltBl'INi'{D=6.25' --_U" 1 L4. f2'IE4xw D-3B13•� 9665 TX4-Ire BKRS311IOt D*5875• �iig� alrertsxNP.D=3e13-j 9799' �-1/C FFi XN 11P. De 3725' 9795 7'X6'BMZXPLNR7CIPP(Rwl '1833ACK SLV, 0-625- VBW lBWH4-la-Hn, D = 3.955 �^ ELADTT NOT LOGGED - 961 O 9615 7'40 SP GM FLO(-LCC, LNR: CR w 15' R9 PACKDTF W. D - 4250' 9927 Y X+v2 xo, D = 395P WILL NIIIOOW 14114L11 M78'-8111' IPBM F i 162211 I 2 FRLHDE UAY WI V%ELL 16148 AR W W029-20570-02 W F rP IoraOon (Abs Ra( 16 RECEIVED bap BP Exploration (Alaska) Inc. MAR 2 9 2017 Ryan Daniel, BPXA Well Integrity Engineering Team �� Post Office Box 196612 Anchorage, Alaska 99519-6612 0 March 24, 2017 Ms. Cathy P. Foerster Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage, Alaska 99501 Subject: Prudhoe Bay Field. Well 04-43 (PTD # 1940130) Request for Administrative Approval to Continue Produced Water Injection Operations Dear Ms. Foerster, BP Exploration (Alaska) Inc. requests approval to continue produced water injection operations into well 04-43. A leak detect log on 02/23/16 found that well 04-43 had a production casing leak at 7255' and tubing leaks at 1578' and 4980'. These leaks were repaired with an IA cement squeeze per Sundry # 194-013 in June of 2016. The annulus cement top was logged at 450' on 08/6/16. A passing MIT -IA to 2366 psi was conducted on 10/7/16 and a passing MIT-T to 2500 psi was conducted on 8/6/16, indicating the success of the repair and that the tubing and production casing are competent. For continued operation of the well the inner annulus operating pressure shall be maintained below the Normal Operating Limit of 2000 psi. In summary, BPXA believes well 04-43 is safe to operate as stated above and requests administrative approval for continued produced water injection operations. If you have any questions, please call me at 748-1140 or Adrian McVey/ Jack Lau at 659-5102. Sincerely, Ryan Daniel BPXA Wells Integrity Engineering Team Lead Attachments Technical Justification TIO Plot Injection Plot Wellbore Schematic State of Alaska MIT Form — attached or emailed Cc: Doug Cismoski Bill Isaacson McVey/ Lau FS2 Operations Team Leader Bernhard Stechauner Ryan Daniel Well 04-43 Technical Justification for Administrative Approval Request March 24, 2017 Well History and Status Well 04-43 (PTD # 1940130) had a production casing leak at 7255' and tubing leaks at 1578' and 4980' which were repaired with cement squeezes per Sundry # 194-013 on 6/3/16 and 6/28/16. The post squeeze MIT -IA and MIT-T passed demonstrating competent tubing, production casing and cement. A neutron water flow log with shut in temperature warmback passes was conducted on 9/24/16 and showed there was no upward movement of fluid in the IA between the tubing punch holes and the PC leak. Recent Well Events: ➢ 02-19/16: Passing PPPOT-T/IC both passed ➢ 02/23/16: LDL identified tubing and PC leaks ➢ 06/03/16: 1st stage of IA cement squeeze completed. ➢ 06/28/16: IA cement top logged @ 5840' ➢ 06/28/16: 2"d stage of IA cement squeeze completed ➢ 07/24/16: MIT -IA passed to 2275 psi ➢ 08/06/16: SL set TT plug, passing MIT-T to 2500 psi, pull TT plug ➢ 09/24/16: WFL confirmed no flow behind pipe ➢ 10/07/16: Passing MIT -IA to 2366 psi Barrier and Hazard Evaluation The primary and secondary barriers systems consist of the tubing and production casing, associated hardware and cement. A passing pressure test of the inner annulus to 2366 psi and the tubing to 2500 psi, demonstrates a competent primary and secondary barriers systems. Pressure on the inner annulus will be maintained below the normal operating limit of 2000 psi when the well is on-line. Proposed Operating and Monitoring Plan 1. Allow water injection only. 2. Record wellhead pressures and injection rate daily. 3. Submit a monthly report of well pressures and injection rates to the AOGCC. 4. Perform a 2-year MIT -IA and MIT-T to maximum injection pressure. 5. Maintain IA pressure below 2000 psi normal operating limit. 6. The well will be shut-in and the AOGCC notified if there is any change in the well's mechanical condition Well 04-43 TIO Plot / Well 04-43 Injection Plot 21731"'A751 "V41,15 1e` 5 221 122,15 3,22,15 iDLI'S Z,t_,1 361t �4c 1( Z627,16 12716 df,N16 MIS f, '4 16 1131 121D16 0,1017 03t4Z1, 2M TN) Plot 180 160 f Tbg 140 IA 12tI: —k— OA a OOA 's 400A 8D ` — On 60 Bleed 4 + Operable + Not Oper 1 Under Eval Temperature Prod,'Inj Plot 3, al 3,DM —WHIP 25M — SW — PW ZDMT — td! 1,5M —GI 1 — Other —On T17JEE = ? VMB-LWAD = MCEVOY ACTUATOR= AXFL§iM— I, KB, ELEV = 64 BE ELEV = KOP= 1013 Max Angle = 56 @ 12625' Datum IwID = 12630I Datum TV = 88W SS 04-43 Wellbore Schematic 04-43 1 MFE" WTEB: L_ 32* T TOC IN rrt 2066' j-j3-112-CAMCO06SSSVNPr)=2.812- 4M - 7979' CTM CUT SHEATH WLED P+j (08/02116), V = 2-W Minimum ID = 2.205" @ 8030' 2-718" OTIS XN NIPPLE 3-la-TBG-COLECL7#.QT800,.0091W,D--3.06- 79W 2-7/8-TBG,6.5#,L-80,.00579bpf,K)=2.441' 1--j 803V PERFORATION SLAWARY REF LOG: U51T ON 03(10094 ANGLE AT TOPP94-- 56- 012669 Wte-- Refer tD ProductiDn OB for hisftwir-W pert data SVE SPF KTERVAL Opn/Sqz j DATE 2' 6 12668 - 12676 0 06M"7 2" 6 126M - 12708 0 06/0Q07 21 6 12720 17740 0 08f04J07 2- 6 12750 - 12770 0 06104W 2' 6 12700 - 128DO 0 06A"7 sw b Izw IAV64 G UtIrZ4W (f, 'l$111) 1—i 12982' 5-1/2"CSG, 17#, L 30, ID TO 'L4�- 42�3TCTM 1--IT13G PUNCH (07I06f16) �ELM - 7960* - SLO MG PUNCH (05J2811 6) 1 7999- H3-112' X2-718-XO.0-2441- 79W 7gr LOCATM D= 2 17T I BOW H5-112*x3-ARFaDWPAKRPKRID=3.366"7� I BOD5' N3-SEALBOFtEEXTENSKX*K)=3.00(r I INDEXING WJL E SHDE, ID = 2,375- 2-7M'0TK)(NMPwih0GO. 0=22M* (PF;d0R TO SEFTING PLUG - SEE VAI-L. FILE) 8036' j-j2-718-UA.ESM0EW-EG.ID=2.44' F8-1-0-2 7-C-T M I - TF r--R- -8-m- -C B-P-(-O&-v —1, 1-6)- 1283T 1-45T TOP OF SAND PLUG (10,10109) I DATE JREVBYJ 0OWENTS DATE I REV BY CON&HIM I b2t2lmd I 4wammal r(AIP1 FTM I MlA116 I Lf17M 14 IrAdTA AM I R tr-q R*CJH(RO/l QW25(94 �LAST WORKOVER408&/251116 JTGIAU CORIECTEDMI) O&IN01 09t08116 JDfJJMD CORRECTIONS TO FISH ID/14109 7 LVPJC :SAND PLUG (I(VIO/09) 05/3R/16 LACIJMD! SET CBPfCMT FETM�G 07114116 L4LLED JCFIJKC: RSK SET CMr RFT, MI -LED PF4JDHOE BAY UW VVELL b4-43 PERPJT M. 194-0130 AR W! t0029224430D 1`1 1N R15F- 56' FR. & 460' M BP Exploration (Alaska) STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION Mechanical Integrity Test Submit to: iim.regQAalaska.aov: AOGCC.lnsoectorsDalaska.cov: Phoebe. brooksCalaska.00v OPERATOR: BP Exploration (Alaska), Inc. FIELD / UNIT / PAD: GPB /PBU / 04 DATE: 10/07/16 OPERATOR REP: AOGCC REP: NOT WITNESSED chits. wallace0alaska. gov Well 04-43 Pressures: Pretest Initial 15 Min. 30 Min. 45 Min, 60 Min. PTD 1940130 Type Inj I W Tubing 1130 1128 1129 1128 Type Test P Packer TVD 5881 BBL Pump 0.3 IA 740 2500 2400 2366 Interval 0 Test psi 1500 BBL Return 1 0.2 OA 293 303 303 302 Result P Notes: Internal MIT -IA for AA application Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBLPump IA Interval Test psi BBL Retum OA Result Notes: Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBLPump IA Interval Test psi BBL Retum OA Result -4- 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 Parker TVD BBLPump IA Interval Test psi BBL Retum OA Result Notes: Well j Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBLPump 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 Notes: 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 Form 10-426 (Revised 01/2017) PBU GPB 04-43 MIT's.xlsx STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION Mechanical Integrity Test Submit to: iim.reag0alaska.aov: AOGCC.Insvectors(@alaska.aov: Dhoebe.brooks(Malaska.aov OPERATOR: BP Exploration (Alaska), Inc. FIELD / UNIT / PAD: GPB /PBU / 04 DATE: 08/06M6 OPERATOR REP: AOGCC REP: NOT WITNESSED chds.wallace(Malaska.aov Well 04-43 Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD 1940130 Type Inj N Tubing 320 2472 2313 2242 Type Test P Packer TVD 5881 BBLPump 1.4 IA 3 5 4 3 Interval 0 Test psi 1500 1 BBL Return 5.8 OA 40 43 44 44 Result P Notes: Internal MIT-T for AA application Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test PackerTVD BBLPump 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 BBLPump 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 nterval 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 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 Notes: TYPE INJ Codes W = Water G=Gas S = Slurry 1 = Industrial Wastewater N = Not Injecting TYPE TEST Codes INTERVAL Codes P = Pressure Test I = Initial Test O = Other (describe in Notes) 4 = Four Year Cycle V = Required by Variance O = Other (describe in notes) Result Codes P = Pass F = Fail I = Inconclusive MIT Form 10426 (Revised 01/2017) PBU GPB 0443 MIT's.xlsx 15 BP Exploration (Alaska) Inc. Aras Worthington, Well Integrity Engineer Post Office Box 196612 Anchorage, Alaska 99519-6612 February 2, 2017 Ms. Cathy P. Foerster Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage, Alaska 99501 RECEIVED 0 Subject: Prudhoe Bay Well P1-21 (PTD # 1930590) Request for Administrative Approval Dear Ms. Foerster, BP Exploration (Alaska) Inc. requests an Administrative Approval (AA) for continued water alternating gas (WAG) injection into GPMA well P1-21 after an inner annulus cement repair. A sundry was approved on 9/15/2016 for an IA cement job to repair a PC leak in the 7-5/8" casing. The final cement top, confirmed by SCMT on 1/18/17, in the IA is 2590'. The well passed a MIT -IA to 3,696 psi on 1/8/17 as well as a MIT-T to 3,793 psi on 1/18/17. In summary, BPXA has determined that GPMA well P1-21 is safe to operate as a WAG injector following the cement repair. If you have any questions, please call me at 564-4102 or Jack Lau/ Adrienne McVey at 659- 5102. Sincerely, Aras Worthington BPXA Well Integrity Engineering Attachments Technical Justification TIO Plot Injection Plot Wellbore Schematic Cc: Doug Cismoski Lau/McVey GPMA Operations Kaity Burton Ryan Daniel Aras Worthington Team Leader Prudhoe Bay Well P1-21 Technical Justification for Administrative Approval Request February 2, 2017 Well History and Status Well P1-21 had a PC leak identified on 4/18/16. The remaining value of the well was assessed and it was determined that if MI could be injected into the well then the repair would be justifiable. The job was executed on 1/3/17. The SCMT was performed on 1/18/17 showing a top of cement in the IA @ 2590'. The well passed a MIT -IA to 3,696 psi on 1/8/17 as well as a MIT-T to 3,793 psi on 1/18/17. Recent Well Events: > 07/06/98: State witnessed MITIA @ 2500 psi Passed > 03/22/00: Bled OA 1200 psi - 800 psi (gas & APack); Bled IA 2450-2350 (gas) > 07/02/02: AOGCC MITIA Passed to 2380 psi > 07/02/06: AOGCC MITIA Passed to 2300 psi > 04/20/07: Notified AOGCC of high IAP, thought to be due to increased rate and thermal effects > 07/22/10: MIT -IA Passed to 2300 psi > 07/28/10: AOGCC MIT -IA Passed to 2300 psi > 05/26/14: MIT -IA Passed to 2300 psi > 06/03/14: AOGCC MIT -IA Passed to 2500 psi > 11/07/14: PPPOT-IC Passed to 3500 psi > 05/29/15: MIT-OA Passed to 1200 psi > 01/20/16: PPPOT-T/IC Both Passed > 01/23/16: Caliper 4-1/2" tbg 241 jts 0-20%, 45 jts 20-37% > 02/19/16: MIT -IA Failed w/ LLR of 0.6 bpm @ 1900 psi > 04/18/16: PC leak found @ 7652' ELMD > 10/16/16: Set CBP @ 1084T MD, set squeeze packer @ 10822' MD pre cement squeeze > 10/17/16: MIT-T Passed to 2385 psi > 01/03/17: Cement job was pumped with coiled tubing. > 01/08/17: MIT -IA Passed to 3696 psi > 01/17/17: Set TTP @ 10929' MD > 01/18/17: MIT-T Passed to 3793 psi, Pulled TTP from 10929' MD. SCMT found TOC @ 2590'. Barrier and Hazard Evaluation The primary and secondary barriers system consists of the tubing and production casing and associated hardware. A passing pressure test of the inner annulus to 3,696 psi, which tests both barriers, demonstrated competent primary and secondary barrier systems. Pressure on the inner annulus will be maintained below the normal operating limit of 2500 psi when the well is on-line. Pressure on the outer annulus will be maintained below the normal operating limit of 1000 psi when the well is on-line. Proposed Operating and Monitoring Plan 1. Allow water and gas (WAG) injection service. 2. Record wellhead pressures and injection rate daily. 3. Submit a monthly report of well pressures and injection rates to the AOGCC. 4. Perform a 2-year MIT -IA and MIT-T to maximum injection pressure. 5. The well will be shut-in and the AOGCC notified if there is any change in the well's mechanical condition. 6. Perform temperature warmback log and Water Flow log after well has been put on injection to verify no flow behind pipe. Well P1-21 TIO Plot --9- Tbg 10 IA oA OOA OOOA 34822115 052:VIS W2115 07441 � 09124,15 1625n5 11-1251+15 12f26t15 Olf26F16 02f2616 O&'2&16 "12&16 <�16 OtWMIV -1 IAhi6 €}&,WI6 WrA16 101,31t16 iZ01116 OVUM? • Well PI-21 Injection Plot 2200 2 100 2,-XG 1,9w 1,400 1.3W 1,200 CO '.000 900 3w IOU 500 sm 4w MID 2w i W, 01,- IMP sw --pw ml G1 Oft- -0. TREE = FMC %-JELJ.tIFJND= cw ACT TOR= AXB.9ON is- BF. ELEV KOP= 1289 Wx Angle = 46- M62 biw M= 9800' SS 1 10-314- CSG, 45.5i J-55, D = 9.953r (—{ Mp2 Minimum ID = 3.725" @ 1092V 4-1112" PARKER SWN NIPPLE P1-21 %1 222oV 4-112• CAMOO TRCF-4A SSSV, D = 3.812" 2,590' TOC — SCMT 1/18/17 GAS LIFT WCHELS 'STA!162-BBBC13YE r 1081G 4-vr2 PAwER S1N5 iVE D = 3.813' 10874' - j 7-5M- X 4-12• TW HB8P WP D = 10812' 4-tf2• PAlaSH2 7VM6 Fip D = 3.813 10l28' 41l2" PATa®2 StYIMI Fp D = 3.72! 4-1r2. 7r3G. 12A0, L-84, 0AIS2 6pf, iS= 3.95$' �101i3' 10064' 4 1!2" WLEG, O- �.00" 10958' ELJMTTLOGGlDO7f18/03 PERFORATION SLAN^RY BEF LOG DPF;VNEUIDENS ON 05005l93 ANGLE ATTOP PEW 37 @ 11107 Now: Refer to Production DS for hislodcal pert data SIZE SPF MERVAL OpnISQz DATE 3-3/8" 6 11032 -11042 0 09123(04 3-3f8' 6 11050-11090 0 0902304 3-38" 6 11102 - 11112 O 000504 3-3/8" 4 11124 - 11134 0 05113►93 3-318" 4 11151-11168 0 05013M 3-318" 6 11170 -11190 0 02 O5194 3-308' 4 11191-11251 O 09130S3 3-318" 4 11271 - 11361 0 M13193 3-318" 6 11375-11400 0 07/18f03 I POWK CNYYREUW VVE3.L: PI-21 PE14K No: 9900590 API Ne: 50-0129-22363-00 Sec.16, T12K R14E, 5149.72 Fa 2894-96 FNL OATE REV BY COMMENTS CATE REV BY I COMBOS 05l1ow OIMNAL COTMPI MON 10/27110 RLWPJC TT CEPrH OORABCITON (7118/93) 08112JO1 RN'EP cORf76MIONS 10118//6 BWJkU SET C8RCMT RETMIG PUNCH 07/18103 Bikt ADD FEW 01N5117 MZIJI D C84WTW IA (01f03/17) OBQ5104 PAMAK PBS COREOMM 01/11117 JCFIJ D Lt1MCMFFET&CHFISETFISF 0%23/04 JRA/TLP ADDP6RF ! Explara8on (Alaska) 10f04l10 RLWSV I SAFEKY NOTE 14 BP Exploration (Alaska) Inc. Aras Worthington, Well Integrity Engineer Post Office Box 196612 Anchorage, Alaska 99519-6612 February 7, 2017 Ms. Cathy P. Foerster Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage, Alaska 99501 RECEIVED FEB 'J 9 2017AOGCC Subject: Prudhoe Bay Well 11-07 (PTD # 1811770) Request for an Administrative Approval for continued water Injection Operations Dear Ms. Foerster, BP Exploration (Alaska) Inc. requests an Administrative Approval (AA) for continued water injection into Prudhoe Bay well 11-07. The well exhibits slow inner annulus by outer annulus communication. However, the well passes a MIT -IA to 2,404 psi, indicating the tubing and production casing are competent barriers. Outer annulus operating pressure will be maintained below Normal Operating Limit (NOL — formerly called MOASP). In summary, BPXA has determined that Prudhoe Bay well 11-07 is safe to operate as stated above and requests Administrative Approval for continued water injection operations. If you have any questions, please call me at 564-4102 or Jack Lau/ Adrienne McVey at 659- 5102. Sincerely, 'z ' Aras Worthington BPXA Well Integrity Engineer Attachments Technical Justification TIO Plot Injection Plot Wellbore Schematic Cc: Doug Cismoski Lau/McVey FS2 Operations Team Leader Ann Marie Chamansingh Ryan Daniel Prudhoe Bay Well 11-07 Technical Justification for Administrative Approval Request February 7, 2017 Well History and Status Well 11-07 was drilled in Jan 1982 as a producer and converted to injection in 1984. In August 1992, it was sidetracked. The old well name was changed to 11-07PB1 in the database and the new sidetracked well was called 11-07. The well has been injecting both seawater and produced water since 1984. In May 2006, the well failed a MITIA. In May 2007, a caliper log indicated a possible hole at 7,328' and 83% to 76% corrosion in four locations from 6,023 to 7,705'. The well passed a CMIT-TxIA. The well operated under a waiver for its rapid tubing by IA communication. The well was allowed to operate with a dispensation until the end of 2007. A RWO restored tubing integrity in April 2008 but the well was SI from November 2008 until November 2011 due to flow line repairs. Since 2011 the well has mostly been online injecting seawater or produced water. The well is currently injecting produced water. The well most recently passed both an MIT -IA to 2,404 psi as well as a PPPOT-IC to 3500 psi on 1 /22/17. Recent Well Events: > 01/17/08: AA AIO 4E.010 Cancelled > 03/17/08: PPPOT-T Passed to 5000 psi, PPPOT-IC Passed to 3500 psi, cycled LDS > 03/27/08: Set fasdrill plug @ 8780' > 03/28/08: Reset fasdrill plug @ 8775, CMIT-TxIA Passed to 3500 psi, > 03/28/08: Jet cut TBG @ 8720' > 04/02/08: CMIT-TxIA Passed to 3500 psi, MIT-OA Passed to 2000 psi > 04/09/08: CMIT-TxIA Passed to 4000 psi > 04/17/08: Rig MIT -IA Passed to 4000 psi > 04/26/08: MITIA Passed to 2250 psi > 05/03/08: AOGCC MIT -IA Passed to 2250 psi > 10/14/11: Verified sealed conductor > 04/03/12: MITIA Passed to 2400 psi > 04/15/12: AOGCC MITIA Passed to 2320 psi > 04/21/13: DSO re -torque flange and notified SRT for gravel removal > 02/04/16: PPPOT-T & IC Passed > 02/06/16: MIT -IA Passed to 2463 psi > 02/23/16: AOGCC MIT -IA Passed to 2458 psi > 01/22/17: MIT -IA Passed to 2404 psi, PPPOT-IC Passed Barrier and Hazard Evaluation The primary and secondary barriers systems consist of the tubing and production casing and associated hardware. A passing pressure test of the inner annulus to 2,404 psi, which tests both barriers, demonstrates competent primary and secondary barrier systems. Pressure on the inner annulus will be maintained below the normal operating limit of 2000 psi when the well is on-line, and the outer annulus will be maintained below the normal operating limit of 1000 psi when the well is online. Proposed Operating and Monitoring Plan 1. Water injection only. 2. Record wellhead pressures and injection rate daily. 3. Submit a report monthly of well pressures and injection rates to the AOGCC. 4. Perform a 2-year MIT -IA to maximum anticipated injection pressure. 5. The well will be shut-in. and the AOGCC notified if there is any change in the wells mechanical condition. Well 11-07 TIO and Injection Plots MEIS S2?'1116 MIS LITA 4SIS 0417,16 501:16 (61516 N2 '16 91216 006. 6 n- loq F2116 MCI M2116MOM 116 laoj16 1�1&1636; 5 6 1,225117 1122% 20 2.7k 2,0K, i10 low SCE U 21 MT :% A , 16 wta,16 w ffif 11 97�A 06TV6 V51 51516 0612-16 NXIS u,"ID16 C ems 39211 � 6 lulfi,16 1 M6 1,1316 a TIO Plot -4— Tbg A— 1A (OVA A OOOA —On I Reed * Operable + Not Oper * Under Eval —Temperature Pw 4_G1 0 — Offf —00 i'M O2120192 RIS CfdGkokL CO1MPtMM 1111i?'4$ ?1P.NC 06"32 NM SU)EMCK(11'-bM) 111IMS GMDPJC 0+Y11M MES RIMO 02/14/11 WAM 0504M JNA/PX F TT STM(4/17 08 Wi( )) 05/29M RiC1PJC CORFEMM 0625108 #RrJPJC: OF&G "iS 13 RECEIVED �� BP Exploration (Alaska) Inc. Ryan Daniel, Well Integrity Engineer Team Leader ��" �� Post Office Box 196612 �� Anchorage, Alaska 99519-6612 August 22, 2016 Ms. Cathy P. Foerster Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage, Alaska 99501 Subject: Prudhoe Bay Well 13-31A (PTD # 2051600) Request for Administrative Approval to Continue Water Injection Operations Dear Ms. Foerster, BP Exploration (Alaska) Inc. requests approval to continue water injection operations into Prudhoe Bay well 13-31A (PTD # 2051600). Well 13-31A exhibits slow inner annulus (IA) repressurization of approximately -15 psi/day while on gas injection. However, a pressure test of the inner annulus passed to 3000 psi on 08/13/2016, indicating two competent barriers to formation. If continued operation of the well is granted, the inner annulus operating pressure shall be maintained below the MOASP of 2000 psi and limited to water injection operations only. In summary, BPXA believes Prudhoe Bay well 13-31A is safe to operate as stated above and requests administrative approval for continued water injection operations. Any continued signs of slow IA repressurization will be managed with periodic annular bleeds. If you have any questions, please call me at 748-1140 or Jack Lau/ Adrienne McVey at 659-5102. Since) Ryan Dfaniet BPXA Well Integrity Engineering Team Leader Attachments Technical Justification TIO Plot Injection Plot Wellbore Schematic Cc: Doug Cismoski Lau/McVey FS3 Operations Team Leader Kristine Odom Ryan Daniel Prudhoe Bay Well 13-31A Technical Justification for Administrative Approval Request August 22, 2016 Well History and Status Prudhoe Bay injection well 13-31A (PTD # 2051600) shows slow signs of IA repressurization while on gas injection. An MIT -IA to 3000 psi performed on June 23, 2016 initially failed due to increasing IA pressure. However, the wellhead temperature (WHT) increased 14 degrees during the pressure test. A subsequent shut in MIT -IA performed on August 13, 2016 passed to 3000 psi, demonstrating competent tubing and production casing. Inner and outer annulus operating pressure is maintained below MOASP. Recent Well Events: > 01/24/14: MITIA Passed to 4000 psi > 02/08/14: AOGCC MITIA Passed to 2500 psi > 08/24/15: PPPOT-T & PPPOT-IC Both Passed > 06/23/16: MIT -IA Failed to 3000 psi (due to IA increasing/WHT increased 14 degrees) > 08/13/16: MIT -IA Passed to 3000 psi Barrier and Hazard Evaluation The primary and secondary barriers systems consist of the tubing and production casing and associated hardware. A pressure test of the inner annulus passed to 3000 psi, demonstrating competent primary and secondary barrier systems. Pressure on the inner annulus is maintained below the normal operating limit of 2000 psi when the well is on-line. Proposed Operating and Monitoring Plan 1. Allow water injection only. 2. Record wellhead pressures and injection rate daily. 3. Submit a monthly report of well pressures and injection rates to the AOGCC. 4. Perform a 4-year MIT -IA to maximum injection pressure. 5. The well will be shut-in and the AOGCC notified if there is any change in the well's mechanical condition. Well 13-31 A TIO Plot 13 31 , 10 flag 4EW m zcm Tbg A —GA . OOA —0. DA. Stad/Ed AIW2015 a/8/'AIG TIO GAd Well 13-31A Injection Plot (1 year) 35CAP 34W 7.3CO 3%0 3.100 3.000 2WO two 2.7w 2.6M 2 500 2,4M 2 3M 2.AD 2.1W 20W 1,9W aim 1 T00 1.5m I AM 1,300 7 200 1, Toot O00 9W sw 7io M ]CAP 400 3t 0 20O 7W 'S,aG !4,l�it !3000 2 0LO !i 000 Ow 190OO IS00O 17.OW IG.C40 15,OW. t 14 W0 S !}Oar 12.000 1t.Lw 10.000 3,WW Ow ',LW &.ODO 5.0M 1,000 3.000 2Oa 1,a10 — WBIP — sw — pw —GI — 00. Ort Date St t/FM wsrm5 6 fl+2016 '..�Ri°ad flog kl Gdd _i L-9 kw. (Toga C— Yak. % O8/22/2015 Y 1.942 T1 = 4-1t6" <M 5M VYfi1FFAEk= FlMC ACTUATOR-- BAKERC f]Itfi. iLv = 82.3' BF, ELE V = KC}F Kbx Angie = 100' Q 12946' Datum 6D 11838, Datum TVD - Mw SS I4-112' TUG, 12.6#, L-80 TC4, .0152 bpf, D= 3.958'..I-� ' 21' _ 9-518` C-W�, AGO NT-80, Ill = 8.835' 3r,27' j Minimum U) =1.731- @ 11701' SEAL ASSY wlNO GO PERFOPATIONSJAOA*RY WF LOG MWTS ON OVUM ANGLEATTOPFERF: 29' @ 11975 Note: Refer to Roducton DB for Nstorcal pert data SELF SFF KrERVAL OpnlSgz DATE 1 5W � 6 1197sa- 000 , O 05t18t15 13233- 1325e O 05118/15 1.5e 6 13258 - 132K O 0 IV15 1-9t166 13390-1367C> O 121240r05 1-Gilf? ii " 1_i190- 1.'#'i7r• n 1204M5 3-112" TBG, 9.3#, L-80 TCi, .0087 bpf, D = 2.992" ]-A 11725' JTOC (12108105) ( 11u J 12"0, 5 112' CSG. 17#, L-8O. ID SAFETY NOTES: H2S READINGS AVERAGE 125 ,,,, pprn WHEN ON Mi_ WELL REQUIRES A SSSV WHEN ON UL —WELL ANGLE > --70' 12056"" —2V—„ 3 1 s-tar nra x, ta= t etas- T9w 8976' 5-1r1- PAHKrH bW5 NP, MILLED ID S 112' OTIS XN NP. NILLE D D = 4.75' 11570•` 3-1/2'F4�Sxnp D=28/3 11591' 84CR KBF�22 ArJCiKJ14 sa°A L Assv , D = 2.9$- 11 2• �5 M2- X 3 if2" 118A61 3 WR D - 2 78' 1161T �-{:i trl" FEs X sriP, D = 2 75' KB L NR T0P PK:;k D - 1.8I7 1169V 11701' SEAL ASSY +rlNOCaO. D- 1,731' 11704 2.70- B DEDBiOY SLV, D = 225- 11725' MILLOUT VMM 0W (13-31Ay 118i4' -1184D PBro H 1389T`- 2-3/8" LW 4.7#, L-80 STL, .0039 bpf, D = 1 995" 13528 DATE REV BY CONNE TS DATE Thy BY I CONR434TS CWITi4 ORIGINAL COMPLETION 05rvl5 JTO ku JAUP04VS(ClUl#-18-15) 12XMMS NUB MO (PRECTD SOTRCIQ 12112JOS NORINC7 CTO SIDETRACK (13-31A) 01102R16 KS&nLH DRLG DRAFT CORTtECTIDNS -- (17169111 01t1611? MBJJbU A#4.ANb ADDED SSSYSAFETY NUT AnnFnD 7.%-AFFrY NDTF FR DHOE BAY 1.HT VYR I 13-31A PEHMT No 02051600 AR Na: 50-029-22459-01 SFC 14, T10K R14F, 1579' FSL & 142T FEL BP Ekpbralion (Alaska) 12 Wallace, Chris D (DOA) From: AK, GWO SUPT Well Integrity <AKDCWellIntegrityCoordinator@bp.com> Sent: Wednesday, August 31, 2016 12:49 PM To: Wallace, Chris D (DOA) Subject: RE: NOT OPERABLE: Injector P2-09 (PTD #1980660) Awaiting Administrative Approval Attachments: Copy of MIT-T GPMA P2-09 5-24-16.xls; Copy of MIT -IA GPMA P2-09 5-15-16.xls Chris, Please see attached MIT forms. The maximum anticipated injection pressure on MI is 3300 psi. The MIT -IA conducted on 5/15/16 passed with a final pressure of 4208 psi. Using the 5/15/16 pressure test as the anniversary would seem to make the most sense, if following the proposed operating and monitoring plan which calls for a 2 year MIT -IA & MIT-T to maximum anticipated injection pressure. Adrienne will be back on the slope today. Thanks, Jack From: Wallace, Chris D (DOA)[mailto:chris.wallace@alaska.govl Sent: Wednesday, August 24, 2016 7:46 AM To: AK, GWO SUPT Well Integrity Subject: RE: NOT OPERABLE: Injector P2-09 (PTD #1980660) Awaiting Administrative Approval Jack, Adrienne, We are progressing the AA application dated August 8, 2016. 1 have on file the witnessed MITIA from 07/03/2016 to 2397 psi (that is not referenced in the AA application) I do not have the referenced passing MITIA of 05/15/2016 to 4208 psi or the referenced MITT of 05/24/2016 to 3687 psi. Please provide these results on the AOGCC excel form to the distribution list. Also, what is the maximum injection pressure expected on WAG? Is it BP's intention to redo the MITIA to 2500 psi or is it your intent that the witnessed MITIA of 07/03/2016 to 2397 psi satisfies the AA requirement and sets the anniversary date as 07/03/2016? Thanks and Regards, Chris Wallace, Sr. Petroleum Engineer, Alaska Oil and Gas Conservation Commission, 333 West 7ch Avenue, Anchorage, AK 99501, (907) 793-1250 (phone), (907) 276-7542 (fax), chris.wallace@alaska.sov 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: AK, GWO SUPT Well Integrity [mailto:AKDCWellIntegrityCoordinator@bp.com] Sent: Monday, July 11, 2016 2:51 PM To: AK, OPS GPMA OSM; AK, OPS GPMA Field O&M TL; AK, OPS LPC DS Ops Lead; AK, OPS LPC Board Operator; AK, OPS PCC Ops Lead; AK, OPS LPC DS Operator; Cismoski, Doug A; Daniel, Ryan; AK, RES GPB East Wells Opt Engr; AK, RES GPB West Wells Opt Engr; Burton, Kaity; Wallace, Chris D (DOA) Cc: AK, GWO DHD Well Integrity; AK, GWO Projects Well Integrity; AK, OPS FF Well Ops Comp Rep; McVey, Adrienne; Regg, James B (DOA); Hibbert, Michael; Janowski, Carrie; Montgomery, Travis J; Munk, Corey; Obrigewitch, Beau; Pettus, Whitney; Sternicki, Oliver R; Tempel, Troy; Worthington, Aras J Subject: NOT OPERABLE: Injector P2-09 (PTD #1980660) Awaiting Administrative Approval All, Injector P2-09 (PTD #1980660) is nearing the end of its 28 day Under Evaluation period. An Administrative Approval is required for continued operation. The well is reclassified as Not Operable until an AA is obtained. Work Completed: 1. Operations: POI Under Eval — DONE 06/15/16 2. E-line: Waterflow Log — DONE 06/23/16; no indication of channeling 3. Slickline: Install MCX Injection Valve — DONE 06/23/16 4. DHD: AOGCC-witnessed MIT -IA —PASSED 07/03/16 Thanks, Adrienne McVey Well Integrity Superintendent — GWO Alaska (Alternate: Jack Lau) 0:(907)659-5102 C: (907) 943-0296 H: 2376 Email: AKDCWellintesrityCoordinator@BP.com From: AK, D&C Well Integrity Coordinator Sent: Tuesday, June 14, 2016 5:17 PM To: AK, OPS GPMA OSM; AK, OPS GPMA Field 0&M TL; AK, OPS LPC DS Ops Lead; AK, OPS LPC Board Operator; AK, OPS PCC Ops Lead; AK, OPS LPC DS Operator; Cismoski, Doug A; Daniel, Ryan; AK, D&C Wireline Operations Superintendent; AK, D&C Well Services Operations Superintendent; AK, RES GPB East Wells Opt Engr; AK, RES GPB West Wells Opt Engr; Burton, Kaity; 'chris.wallace@alaska.gov' (chris.wallace(abalaska.gov) Cc: AK, D&C DHD Well Integrity Engineer; AK, D&C Projects Well Integrity Engineer; AK, OPS FF Well Ops Comp Rep; AK, D&C Well Integrity Coordinator; McVey, Adrienne; 'Regg, James B (DOA) (jim.regc0alaska.gov)' (jim.regg@alaska.gov); Hibbert, Michael; Janowski, Carrie; Montgomery, Travis J; Munk, Corey; Obrigewitch, Beau; Pettus, Whitney; Sternicki, Oliver R; Tempel, Troy; Worthington, Aras J Subject: UNDER EVALUATION: Injector P2-09 (PTD #1980660) Waterflow Log All, Injector P2-09 (PTD #1980660) underwent a coiled tubing IA squeeze on 05/09/16, in order to repair a production casing leak. An MIT -IA to 4208 psi passed on 05/15/16, and an MIT-T to 3687 psi passed on 05/24/16, demonstrating two competent wellbore barriers. The well is reclassified as Under Evaluation. Once online and stable, a waterflow log will be conducted. Pending satisfactory results, an Administrative Approval will be pursued, and an AOGCC-witnessed MIT -IA performed, prior to reclassifying the well as Operable. Plan Forward: 1. E-line: Waterflow Log 2. Slickline: Install MCX Injection Valve 3. DHD: AOGCC-witnessed MIT -IA Please reply if in conflict with proposed plan. Thanks, Adrienne McVey Well Integrity Superintendent — GWO Alaska (Alternate: Jack Lau) 0: (907) 659-5102 C: (907) 943-0296 H: 2376 Email: AKDCWellintesrityCoordinator@BP.com From: AK, D&C Well Integrity Coordinator Sent: Saturday, June 27, 2015 5:39 PM To: AK, OPS GPMA OSM; AK, OPS GPMA Field 0&M TL; AK, OPS LPC DS Ops Lead; AK, OPS LPC Board Operator; AK, OPS LPC DS Operator; Cismoski, Doug A; Daniel, Ryan; AK, D&C Wireline Operations Team Lead; AK, D&C Well Services Operations Team Lead; AK, RES GPB East Wells Opt Engr; AK, RES GPB West Wells Opt Engr; Gerik, Bob G; Igbokwe, Chidiebere; 'chris.wallace@alaska.gov' Cc: AK, D&C DHD Well Integrity Engineer; AK, D&C Well Integrity Coordinator; AK, D&C Projects Well Integrity Engineer; AK, OPS FF Well Ops Comp Rep; Morrison, Spencer; Regg, James B (DOA) (iim.reCIg@alaska.gov) Subject: NOT OPERABLE: Injector P2-09 (PTD #1980660) MIT -IA Failed All, Injector P2-09 (PTD #1980660) had a failing MIT -IA on June 27, 2015. The failing test proves a lack of two competent barriers and the well is reclassified as Not Operable and will be added to the Not Operable Injector report. The well shall be shut in and freeze protected as soon as possible and remain shut in pending further diagnostic work. The plan forward: 1. APE: Evaluate for LDL or secure Please call with any questions. Thank you, Kevin Parks BP Alaska - Well Integrity Coordinator GWGlobal Wells Organization Office: 907.659.5102 WIC Email: AKDCWellintegrityCoordinator@bp.com STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION Mechanical Integrity Test Submit to: jim.regg(dalaska.gov: doa.aogcc.prudhoe.bay(cDalaska.gov: phoebe.brooks(o)alaska.gov: tom.maundercDalaska.gov OPERATOR: FIELD / UNIT / PAD: DATE: OPERATOR REP: AOGCC REP: BP Exploration (Alaska), Inc. PBU/GPMA/P2 05/24/16 Adreienne McVey Packer Depth Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. Well P2-09 I Type In'. I W TVD 1 8,845' Tubin 749 3786 3668 3590 Interval p P.T.D. 1980660 T e test P Test psi 221.3 Casin P/F F Notes: Pumped 2.76 bbls ambient diesel to catch pressure OA 10 10 10 9 Well P2-09 I Type In'. I W I TVD 1 8,845' Tubing 3,568 3,814 3,742 3,683 3,629 Interval O P.T.D. 1980660 1 Type test I P I Testpsil 2211.25 Casing P/F P --i- Notes: Pumped 0.5 bbls ambient diesel to catch pressure OA 10 10 10 9 10 Engineering review determined MIT was a pass, less than 75 psi loss in final 15 minutes Well I Type lnj.1 I TVD I Tubing Interval P.T.D.1 I Type testl I T.Stp.il Casing P/F Notes: OA Well T In'. I TVD Tubing Interval P.T.D.1 I Type testl I Test psil Casing P/F Notes: OA Well T e In'. TVD Tubing Interval P.T.D.1 I Type testl I Test psil 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 T = Test during Workover 0 = Other (describe in notes) Form 10-426 (Revised 06/2010) Copy of MIT-T GPMA P2-09 5.24-16.xis STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION Mechanical Integrity Test Submit to: iim.regg cDalaska.gov: doa.aogcc.prudhoe.bav(o)alaska.gov: phoebe.brooks(c alaska.gov: tom.maunder(d)alaska.gov OPERATOR: FIELD 1 UNIT / PAD: DATE: OPERATOR REP: AOGCC REP: BP Exploration (Alaska), Inc. PBU/GPMA/P2 05/15/16 Adrienne McVey Packer Depth Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. Well P2-09 Type In'. W TVD 8,845' Tubin 2007 2420 2431 2416 1 Interval O P.T.D. 1980660 Type test P Test psi 221.3 Casin 1126 4387 4245 4208 P/F P Notes: Pumped 3.18 bbls ambient diesel to catch pressure OA 8 10 11 10 Bled back 2.9 bbls diesel Well I Type In'. I TVD Tubing Interval P.T.D. I Type test I I Test psil Casing P/F Notes: OA Well I Type In'. I TVD I Tubing Interval P.T.D. I Type test I Test psi Casing P/F Notes: OA Well Type In'. TVD Tubing Interval P.T.D. Type test I Test psil Casing P/F Notes: OA Well I Type In'. I TVD I Tubing Interval P.T.D. I Type testl I Test psil 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 = Initial Test 4 = Four Year Cycle V = Required by Variance T = Test during Workover O = Other (describe in notes) Form 10-426 (Revised 06/2010) Copy of MIT -IA GPMA P2-09 5.15-16.xis 11 'CHC E I V E D by BP Exploration (Alaska) Inc. A U G 16 2016 Ryan Daniel, BPXA Well Integrity Engineering Team Lead Post Office Box 196612 AOGCC Anchorage, Alaska 99519-6612 August 08, 2016 Ms. Cathy P. Foerster Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage, Alaska 99501 Subject: Prudhoe Bay Field. Pt McIntyre Oil Pool, PTM P2-09 (PTD # 1980660) Request for Administrative Approval to Continue WAG Injection Operations Dear Ms. Foerster, BP Exploration (Alaska) Inc. requests approval to continue WAG injection operations into well P2-09. P2-09 previously had a production casing leak at 6410' which was repaired with a cement squeeze per Sundry # 315-598 on 12/17/15 and per Sundry # 316-203 on 05/09/16. The annulus cement top was logged at 5501' on 05/24/16. A passing MIT -IA to 4208 psi was conducted on 05/15/16 and a passing MIT-T to 3687 psi was conducted on 05/24/16, indicating the success of the repair and that the tubing and production casing are competent. For continued operation of the well the inner annulus operating pressure shall be maintained below the Normal Operating Limit of 2500 psi. In summary, BPXA believes well P2-09 is safe to operate as stated above and requests administrative approval for continued WAG injection operations. If you have any questions, please call me at 748-1140 or Adrian McVey/ Jack Lau at 659-5102. Sincerely, Ryan Daniel BPXA Wells Integrity Engineering Team Lead Attachments Technical Justification TIO Plot Injection Plot Wellbore Schematic Cc: Doug Cismoski Bill Isaacson McVey/ Lau LPC Operations Team Leader Kaity Burton Ryan Daniel Well P2-09 Technical Justification for Administrative Approval Request August 08, 2016 Well History and Status Pt McIntyre injection well P2-09 (PTD # 1980660) had a production casing leak at 6410' which was repaired with a cement squeeze per Sundry # 315-598 on 12/17/15 and per Sundry # 316-203 on 05/09/16. After the first IA squeeze was conducted a pressure test of the IA showed a 0.6 gpm liquid leak rate at 4000 psi and a leak detect log showed a leak at the IA cement top. The second IA squeeze was conducted on 5/09/16 to remediate the failing MIT -IA. The post squeeze MIT -IA and MIT-T passed demonstrating competent tubing, production casing and cement. A neutron water flow log with shut in temperature warmback passes was conducted on 6/23/16 and showed there was no upward movement of fluid in the IA between the tubing punch holes and the PC leak. MI benefits to producers in the 122-09 pattern over PWI only assuming one bulb per year for the next five years are: Year 1 — 185 BOPD Year 2 — 173 BOPD Year 3 — 157 BOPD Year 4 — 137 BOPD Year 5 — 110 BOPD Recent Well Events: ➢ 12/17/2015: IA cement squeeze completed. ➢ 12/24/2015: IA cement top logged @ 6062'. ➢ 02/21/2016: MIT -IA leak rate= 0.6gpm @ 4000 psi. LDL found leak at IA cement top. ➢ 05/09/2016: IA cement squeeze completed. ➢ 05/15/2016: MIT -IA passed to 4208 psi. ➢ 05/24/2016: MIT-T passed to 3687 psi. ➢ 05/24/2016: IA cement top logged @ 5501' ➢ 06/23/2016: Neutron water flow log and temperature warmback passes show no flow behind pipe. Barrier and Hazard Evaluation The primary and secondary barriers systems consist of the tubing and production casing, associated hardware and cement. A passing pressure test of the inner annulus to 4208 psi and the tubing to 3687 psi, demonstrates a competent primary and secondary barriers systems. Pressure on the inner annulus will be maintained below the normal operating limit of 2500 psi when the well is on-line. Proposed Operating and Monitoring Plan 1. Record wellhead pressures and injection rate daily. 2. Submit a monthly report of well pressures and injection rates to the AOGCC. 3. Perform a 2-year MIT -IA and MIT-T to maximum injection pressure. 4. Maintain IA pressure below 2500 psi normal operating limit. 5. The well will be shut-in and the AOGCC notified if there is any change in the well's mechanical condition. Well P2-09 TIO Plot H2 09 1 IU Pkv m Tbg IA OA OGA 000 On X 07/25/201� y 4.522 Well P2-09 Injection Plot 2.300 2200. 2,100 aw 900 &00 1.700 1,600 1,500 1,400 1.300 1100 1, 100 1.000 900 No ,D GM 500 400 300 200 100 061 8.5m 7 504} 000 6 500 6,000 5,500 5,000 - mll, 4,500 Sw Rv a` px 4.000 GI 3500 On 3 000 2.500 2,0M 1,500 low 500 Date Stanf&W W2015 8AV2016 pA w % ibi Ged Log Seale To ao" C— V k. x 071MA15 Y 2.%7 P2-09 Wellbore Schematic TREE = 4-1116" CNV VVELLMiAD-- FMC ACTUATOR BAKER C KB B.EV = %53' BF EEV = KOP = 1400 Max Angle- = 56" @ 11550 Datum @D= 11909 Claium TVO= 8800' SS 9-508" CSG, 400, L-80 SUTT-14 D = 8 835" --� !A CMT SOZIff)C (OSt09116) 5478' TBG PLINC H (041287161) 5 -r - %92' I A TOC (12117015) H -5N8' I -W TBG PUNCH (11118115) -? 1184T - 11852' Minimum ID = 3.725" @ 11943' 4.1t2" HES XN NIPPLE - 4-10 TBG, 12.6#, L-80 BTC-M. 0152 W, D = 3.958" PERF=0RAITGN SUhWRY Fill LOG. SPERRY SUN DUAL GR ON SM - 518498 ANGLEATTOPPtw 52'012119 Nnl defer 10 Production DB for lusbrical perf data SIZE SFF ". NIIHZVAL Opn1Sgz . SHOT SQZ 3-308' 6 3'12044 - 12064 S 106fl&w 0&029098 3.3t8' 6 '*12116-121 C '07111M 3-308" 6 ?'12254 - 12284 C 07111M 2-11W 6 ^'12304 - 12324 C OX11012 �.tr1 n are- 1 rvu Litt Vtlti. t.. FLti AV'A=ir6"a :ilt}12l t PB M 124= 7' CSG, 26N, L -80 OTC M. 0383 6pf. D - 6.276' 12509' _/\ /r :1SAFEiY ROTES: WELL REQUIRES A SSSV 2012 9-W HES CBIERH+ - �2040' A-1J2' CAMCU BAD-O rf D = 3 612" GAS LFT AMPDRELS STJ MD I ND MV; TYPE JVLVJ LATCH PORT 1 4553 4MI 1 43 i KBCr2-I S DW NTT 1 0 t 2 11832 8807 35 jKBG2-LS,.Dw Nf 0 1 'STA#2 BEHIND CEMENT 11899' !- f 7" BKR S 3 PEM PKR D - 3 875- 1193z 1-i4-1l2-"#sx P.D=3.813" 1 11843' ! 14-1r1- rca XN W, t/= J rla' 11lbb' 4 1P2 YVLEG, IG = 4-00 11958' a Mo rT Lace osn 1196 12079' 1-{rwRKE;jaw DATE REV BY COMMENTS CATE ' REV BY COMNEWS POINT L%WFYREUNIT WR1 P2-09 PERWF No. 99806W AR Pb: 54025-22876.00 SEC 11, T12K R14E, 17 FSL & 1OBT FVH- 05113M M3E INITMI-COMPLETION Gswji6 voiks C8POCmTFiFrnRGFtarN(4rmu) 11/11114 W PJC UEPTH SHIFIM PHOOFW MMS 05010016�TFAIJ V\ CW SQZ (051091161 1S2J15 7J1 LCJM) THdi FUNC1f & f751 I { 1 T/18 19t" 15) 05024l16 DSOJMD FISH C8HCJ4fi FiS {5119175 12w-M5 JMY Ti N L ®F1SH (11027115) 05/27/16 VW RJSHM P&I OEBF45 PAST TT 1ZWJ15 Rf0 SET CDP & CMT PETAINER (11129115) BP Exploration (Alaska) 02016M6 DM:S1 CMT K {12(17015) — J 10 by BP Exploration (Alaska) Inc. Ryan Daniel, Well Integrity Engineer Team Leader Post Office Box 196612 Anchorage, Alaska 99519-6612 0 July 27, 2016 Ms. Cathy P. Foerster RECEIVED Alaska Oil and Gas Conservation Commission JUL 29 2016 333 West 7t" Avenue Anchorage, Alaska 99501 AOGCC Subject: Prudhoe Bay Well 09-25 (PTD # 1840280) Request for Administrative Approval to Continue Water Injection Operations Dear Ms. Foerster, BP Exploration (Alaska) Inc. requests approval to continue water injection operations into Prudhoe Bay well 09-25 (PTD # 1840280). Well 09-25 exhibits manageable slow inner annulus (IA) repressurization of approximately —10 psi/day while on water injection. However, a pressure test of the inner annulus passed to 2550 psi on 06/24/2016, indicating two competent barriers to formation. If continued operation of the well is granted, the inner annulus operating pressure shall be maintained below the MOASP of 2000 psi. In summary, BPXA believes Prudhoe Bay well 09-25 is safe to operate as stated above and requests administrative approval for continued water injection operations. The slow IA repressurization will be managed with periodic annular bleeds. If you have any questions, please call me at 748-1140 or Jack Lau/ Adrienne McVey at 659-5102. Sincerely, Ryan Daniel BPXA Well Integrity Engineering Team Leader Attachments Technical Justification TIO Plot Injection Plot Wellbore Schematic Cc: Doug Cismoski Lau/McVey FS2 Operations Team Leader Bernhard Stechaunder Ryan Daniel Prudhoe Bay Well 09-25 Technical Justification for Administrative Approval Request July 15, 2016 Well History and Status Prudhoe Bay injection well 09-25 (PTD # 1840280) shows slow signs of IA repressurization while on water injection. A recent MIT -IA passed, demonstrating competent tubing and production casing. Inner and outer annulus operating pressure is maintained below MOASP. Recent Well Events: > 03/18/14: AOGCC MIT -IA to 2500 psi Passed > 07/22/15: PPPOT-T Passed to 5000 psi > 08/11/15: MIT -IA Passed to 2500 psi > 06/24/16: MIT -IA Passed to 2550 psi Barrier and Hazard Evaluation The primary and secondary barriers systems consist of the tubing and production casing and associated hardware. A pressure test of the inner annulus passed to 2550 psi, demonstrating competent primary and secondary barrier systems. Pressure on the inner annulus is maintained below the normal operating limit of 2000 psi when the well is on-line. Proposed Operating and Monitoring Plan 1. Allow water injection only. 2. Record wellhead pressures and injection rate daily. 3. Submit a monthly report of well pressures and injection rates to the AOGCC. 4. Perform a 4-year MIT -IA to maximum injection pressure. 5. The well will be shut-in and the AOGCC notified if there is any change in the well's mechanical condition. Well 09-25 TIO Plot Ul 1 -i "I Hoc 1.iT9f1 � rLr�• �� ". � n ....,5 09"Y1iS5 10A><k't5 Ntit9'S5 . D.. 0711VNIS 7/1YMIG RYaod PlCt TO QW Cn VaM. x 06aTYrM Y /,AD L90C Y� 1.600 1.5W 1400 1 300 12m 11m LL*C� �4 nd 6m SC@ 400 2,k 100 go Well 09-25 Injection Plot 1 1 3+15 07127tt5 M'1U15 OW2415 OW115 02115 MMIS SMAFS 11.@,95 111ff15 1113N15 iYs, 18 .. t,'�G1tiLt6 QMc^5116 W416 U,-2ei6 U&11; 03"2tt6 044U16 "'I&76 %W!16 0516'16 fli3&OG 0&'13M6 .2d'f6 07,'112% lie SMd/E.a OMMA15 1i11oad flat 10000 `... t7CIO tog Scale 5.000 LToQphoad 0 C— Vane x a.Om y ?,OOO 6 ODD — tam sw — PW g — M — Gt 50w c — Oris 0n 4.tC30 3 OX, 2 Qk3 t --MC- GEN 3 Vrtl LHEA D - FMC SAFETY NOTrg H2S READINGS AVFRAGr 126 AC"LkA-0R= AX-ELSON Mm WHFN ON MI. WELL REQUIRES A SSSV 09-25 WHEAF ON Mt. I�§—EEV BF E--Ev KOP = 930' wv 9 --5-V --- Q-, '3',-7-00' �20- Dw,�,ri IVC 129DO' rrwrl WO 580U, 551 I 10, CDllMcTcp.. ? 3-1'8- CSG, 12N z--80 B'C 10 = '2.34?- 2585 ;Minimum 10 a 1726" @ 12927' 4 -1/2" OTIS X N NIPPLE I5-1.7TSC0,170 L-130-raj, '-J_1251r M32 *1, ID = A a92' 70l'3F7'LNR -4 12W* 14 112' -1512, 12 60 - sc -c' 0 152 npf, ID = 3958 3-S18' CSQ, 470 L-80 BTC, 10 - 8 681 - f--! I I --J PEA --DRAT ICIN St HFI OG ffK'M ON 041C12MI4 A NG-F- AT TOP FEW 510- @ 12967' s"t %rrr to ",oduction DO tar hs:wlr-al per' data SOF S;L} IN 34�6 �IZ67 17 0 3- 3'2* 5 -C-35 - ,3075 0 1 (WEAE 3-308' 5 0 1 1 930719f 3-3084 4 1:3197 0 1 1 0&27t95 7" LNR 249— # i " SC 137C, 0371 Opf, 10- S, 184* 113445' FTI) 13450- 12483' 12517' J-j 9- 54 X 5- V2' 1,ES Tlr :A<R ID = 3.870' - �la X 4- 1 �llzy 0 12 - �� 4-1 rZHES X W ID - Z La--j DA-C �. FEV ey CONWUN-5- UA 1- REV 3,Y COMNUNITS 04t,07164:PUWANXORIGINAL COMPLETION W#?tto NOES RFWO OW08VO if aJC EP-C CRAFT CORRiCTIC"Als W! 11; 7 1 W4JMD A DDID -12S SA F-7Y VD-E =29f "DHDP�JC F NA L. CR L 0 T1N5 I U " V 0 DBI FJC 'V PKR CORR-EGTiON m" 41, MVID AWED SSSV SAFETY 40,77 x 71 I t2' -ES XN IJR 0 - 3 VVLEG, IC T' MARK-IR JCI',F wi LNR 1-04 10 - PIRLIDt'OLUAY UNIT ME— N 2S PFRMT flz ',,0Af)M AP tk, SC 129 21083 00 S� 12 71 CN R15E 17119 88 FEL 4188 97 Ft'A- SP Explwat ion (Aias kal • Dave Lachance Vice President Alaska Reservoir Development September 8, 2015 Via Hand Delivery Cathy P. Foerster Commission Chair Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, Alaska 99501 BP Exploration (Alaska) Inc. 900 East Benson Boulevard P.O. Box 196612 Anchorage, AK 99508 USA Direct 907 564 4855 Mobile 907 538 1719 Main 907 564 5111 dave.lachance@bp.com SEP 0 8 2015 r� Re: Docket Numbers: AIO 15-032 AIO 15-033 and CO 15-09, Prudhoe Oil Pool BPXA Post -Hearing Written Response to Commission Requests Consolidated Application for Amendment of Prudhoe Oil Pool Rule 9 and Modification of Prudhoe Bay Unit Area Injection Orders AIO 3A and AIO 4F Dear Chair Foerster: BP Exploration (Alaska) Inc. (BPXA) submits, on behalf of itself and ExxonMobil Production Inc., as applicants in the above referenced matter, the enclosed written response to Commission requests directed to BPXA during the hearing on August 27, 2015. Please note that the portion of our response contained in the Confidential Appendix is confidential, and BPXA requests that such information be held confidential pursuant to AS 31.05.035(d), 20 AAC 25.537(b), and AS 45.50.910 et seq., as well as Section 11.4 of the Prudhoe Bay Unit Agreement. The Confidential Appendix is enclosed in a separate envelope and marked confidential. S' cerely, Dave P. Lachance Vice President, Reservoir Development Attachment BPXA Post -Hearing Response to Commission Requests Application to Amend POP Rule 9 and Modify AIOs Page 2 September 8, 2015 cc via email: Ernesto Daza, BPXA (ernesto.daza@bp.com) John Dittrich, BPXA Oohn.dittrich@bp.com) George Lyle, Guess & Rudd (glyle@guessrudd.com) Chris Wyatt, BPXA (chris.wyatt@bp.com) Gilbert Wong, EMAP (gilbert.wong@exxonmobil.com) Gerry Smith, EMAP (Gerry.b.smith@exxonmobil.com) Steve Luna, EMAP (charles.s.luna@exxonmobil.com) Brian Gross, EMAP o.brian.gross@exxonmobil.com) Jon Schultz, CPAI (Jon.Schultz@conocophillips.com) Eric Reinbold, CPAI (Eric.W.Reinbold@conocophillips.com) John Evans, CPAI (John.R.Evans@conocophillips.com) Phil Ayer, CUSA (pmayer@chevron.com) Angie Bible, CUSA (abible@chevron.com) RECEIVEU SEP 0 8 2015 AOGCC Docket Numbers: AIO 15-032, AIO 15-033 and CO 15-09, Prudhoe Oil Pool AOGCC Consolidated Application for Amendment of Prudhoe Oil Pool Rule 9 and Modification of Prudhoe Bay Unit Area Injection Orders AIO 3A and AIO 4F Post -hearing Response to Commission Questions INTRODUCTION At the hearing on August 27, 2015, on the referenced application by BP Exploration (Alaska) Inc. (BPXA) to the Alaska Oil and Gas Conservation Commission (AOGCC or Commission), the Commission asked BPXA to submit, post -hearing, responses to Commission requests for the following: 1. Analysis of a full field model (FFM) run or runs depicting the optimal start-up time for Prudhoe Oil Pool (POP) major gas sales (MGS) that is indifferent to specific project considerations; and 2. Analysis of a FFM run depicting the point in time when the BTU value of fuel gas usage is greater than the BTU value of the oil it's producing. (BPXA interprets this request by the Commission as a request for a comparative analysis of incremental oil recovery and incremental fuel gas usage resulting from pushing back the start-up of major gas sales, expressed in barrels of oil equivalent.) This submittal addresses each of these requests. OPTIMAL MGS START-UP DATES INDIFFERENT TO SPECIFIC PROJECT CONSIDERATIONS INTRODUCTION The classic petroleum engineering text book approach to greater ultimate recovery of an oil field with an original gas cap is to first target the oil for development while re -injecting the produced gas to maintain reservoir pressure. In this text book approach to hydrocarbon recovery, it is only after oil production is no longer economically viable that the gas is produced from the reservoir and sold. The logic behind this text book approach to hydrocarbon recovery is that if gas is sold too early the reservoir will lose pressure before oil production is optimized, and as a result total hydrocarbon recovery will be less than otherwise. This is how development of the POP has proceeded for 38 years. The POP has recovered significantly more oil than it would have without gas re -injection. However, the POP is entering a stage in which this simple text book approach to hydrocarbon recovery no longer reflects the complexities of POP development. That's because field development needs to consider several significant factors uniquely applicable to the POP: (1) availability of necessary infrastructure to support a gas export project; (2) fuel gas consumption; (3) facility life considerations; and (4) that the POP has acted similar to a gas field for more than two decades. For example, in a scenario in which a gas export project is available before oil development becomes un- economic, but would not be available at a later date, greater ultimate hydrocarbon recovery can only be achieved by proceeding with gas sales. The Alaska LNG Project is moving forward on a timeline targeting gas production for major gas sales from the POP potentially in 2025. There are no other gas sales projects proposed for sales of POP BPXA Post -Hearing Submission Page 1 of 7 gas sooner than that date or at a later date. Since oil production and gas re -injection consumes fuel gas that could otherwise be sold and contribute to hydrocarbon recovery, by adjusting for fuel gas consumption, if a major gas sales project moves forward in 2025 greater ultimate recovery will likely occur through gas sales prior to oil development becoming un-economic. POP operations currently consume —400 MMSCFD, or approximately 25 million barrels oil equivalent (BOE) per year, of fuel gas to sustain oil production, whereas fuel gas requirements will be substantially reduced during major gas sales. As facilities age, equipment performance and reliability are factors that can impact production and ultimate hydrocarbon recovery. Oil production began from the POP in 1977 and with a MGS start-up in 2025 much of the Prudhoe Bay Unit production facilities will have been in operation for 50 years. Additionally, the landscape of existing supporting infrastructure and delivery systems is likely to change with time. The Commission's approval of BPXA's application in this matter is a necessary and critical step in trying to make POP major gas sales, through a large project such as the Alaska LNG Project it would support, successful. SUMMARY AND CONCLUSIONS Depending on the assumptions that are made, ultimate hydrocarbon recovery from the POP could potentially increase by up to 100 million BOE (MMBOE), less than 1 % of ultimate hydrocarbon recovery, if a comparable MGS project were to commence operations in 2040 rather than 2025 in the reference case. This is premised on the assumption that a POP MGS project is available at that time and advances, and that all necessary facilities, infrastructure and delivery systems have the same remaining capability at project start-up as the 2025 MGS reference case. However, there are unknown factors that could significantly undercut these assumptions including that a MGS opportunity may not be available, which would reduce overall potential hydrocarbon recovery by approximately 3.6 billion BOE. As mentioned, the Alaska LNG Project timeline targets potentially beginning operations in 2025 and if so then gas sales from the POP are estimated to total 22.4 TCF of gas, increasing ultimate hydrocarbon recovery from the POP by between 3.5 and 3.6 billion BOE. Even though there is a potential for slightly greater hydrocarbon recovery with a later MGS date, the complexity and significant financial commitments required to advance a MGS project of this magnitude and the risk of significantly lower ultimate recovery more than offset any potential gain. A later MGS start-up also increases the uncertainty that the project can deliver a full 30-year project life due to declining oil production and revenues which underpin the project, and due to increasing project risk from aging facilities which could reduce project life and thus ultimate recovery, reducing the potential incremental recovery relative to a 2025 start-up. A. BPXA'S FFM RUNS 1. ASSUMPTIONS AND RISKS BPXA (as an individual working interest owner and not as operator) used its proprietary FFM tool (FFM Tool) to build FFM runs to assess the impact of starting MGS from the POP within a range of start-up dates: 2025, 2030, 2035 and 2040. BPXA used the following assumptions in running each case: BPXA Post -Hearing Submission Page 2 of 7 0 0 • Assumption: A project similar to the current AK LNG project is available to start-up at each of the different 5 year increments. Risk: A gas sales project is not available for POP major gas sales at a later date. Therefore, any additional recovery that may be assumed to be recovered by pushing back the start date for a project (<0.1 billion BOE), must be balanced against the risk of not recovering any of the gas (>3.5 billion BOE). • Assumption: All PBU oil and gas process facilities and TAPS are fully available for oil transportation and gas production for the length of the total production period with a 30 year MGS project period in all cases. Risk: Facilities used to produce the oil and gas will age over time and typically operate outside optimum design basis parameters, reducing the ability to recover the oil and gas indicated in the profiles. While the FFM runs account for well breakage and repair, it does not account for impacts due to facility or pipeline availability or performance, including TAPS.' As the facilities age, it is more likely that major equipment performance and reliability will affect oil and gas production. Directionally, there will be an increasingly greater impact on the gas sales cases with later start-up dates. The production profiles provided are not adjusted for any performance reduction factors associated with later major gas sales dates. 2. MODEL RUN PROFILES a. GAS DELIVERIES PROFILES The POP gas sales profiles (excluding COZ) for the 2025 (Reference Case), 2030, 2035 and 2040 start-ups are shown in Figure 1 in the Confidential Appendix to this submittal. The shape of these gas delivery profiles are similar, however, as start-up dates are extended, the plateau length decreases, from 21.0 to 19.6 years. The cumulative amount of gas delivered for sales decreases with each increment of extended start-up, from 22.4 TCF (2025 Start-up) to 20.9 TCF (2040 start-up), due to increased fuel gas consumption (see Table 1). b. OIL PRODUCTION PROFILES The POP liquid hydrocarbons (oil + NGLs) profiles for the oil reference case, and the 2025 (gas reference case), 2030, 2035 and 2040 start-ups are shown in Figure 2 in the Confidential Appendix to this submittal. Due to the drop in reservoir pressure at the onset of gas sales, oil production profiles correspondingly decline at a faster rate at the onset of gas sales, followed by a period of slower rate of decline. Liquid hydrocarbon recovery for the various cases is detailed in Table 1 and Table 2. c. FUEL GAS USAGE PROFILES Fuel gas is mainly consumed in the POP to generate electricity, heat fluids and facilities, pump fluids, and most significantly, compress the dry residue gas for reinjection. When gas sales begin from the POP, fuel usage will decrease as less compression is needed to send gas to the GTP rather than to re -inject the gas. As reservoir pressure declines and active well counts decrease over time, less fluid will be heated, pumped and compressed, and fuel usage will decrease further. These effects are accounted for in the FFM run forecasts of fuel gas usage shown in Figure 3 in the Confidential ' The FFM Tool is capable of performing this analysis, but BPXA has not run such cases. BPXA Post -Hearing Submission Page 3 of 7 0 • Appendix to this submittal. The figure shows that a later start of gas sales results in higher total fuel usage. Once gas is used for fuel it is no longer available for gas sales; therefore, later start of major gas sales results in lower gas sales volumes. Total Hydrocarbon Profiles Figure 4 in the Confidential Appendix to this submittal shows oil and gas sales profiles combined into total hydrocarbon BOE profiles, assuming 1 barrel of oil is equivalent to 5.8 thousand standard cubic feet (MSCF) of gas. The POP BOE rate profiles in Figure 4 are the same as the oil reference case until the start of major gas sales, when total BOE production increases dramatically. Although gas sales rates are on plateau for approximately 20 years, total BOE delivery declines over that period due to declining oil production rates. At the end of the major gas sales plateau period, total BOE delivery rates drop more rapidly as both oil and gas sales rates are declining. B. ASSESSMENT OF ULTIMATE RECOVERY 1 . END OF FIELD LIFE Two methods to evaluate the end of field life (EOFL) were used in this study to evaluate ultimate hydrocarbon recovery: 1. Common gas sales project length 2. Common minimum total hydrocarbon production rate Ultimate hydrocarbon recovery for the suite of MGS start-up dates sensitivities are evaluated against each of the EOFL methodologies. 2. FULL FIELD MODEL PRECISION The resolution of the model is —+/- 10 Million barrels of oil recovery, and —+/- 30 Million BOE on gas sales, and —+/- 40 Million BOE of hydrocarbon recovery. FFM model precision was determined by running a series of simulation runs that were identical, except for a small perturbation to the inputs. The model precision quoted was determined from the range of this series of results. If simulation results from model runs of different scenarios are within these ranges of recovery, the impact of the sensitivity is not discernible from the uncertainty, and should not be used to inform decisions or rank scenarios. 3. UNACCOUNTED FOR RISKS TO ULTIMATE RECOVERY The following analysis does not account for two significant risks. These risks have a greater probability of occurrence as a MGS project start-up extends beyond 2025. 1. A major gas sales project may not be available to ship gas from POP at a later date. Therefore, any additional recovery that may be assumed to be recovered by a later project (<0.1 billion BOE), must be balanced against the risk of not recovering and selling any of the gas (>3.5 billion BOE). 2. Facilities used to produce the oil and gas will age and operate outside of the maximum efficiency range which could affect performance and reliability over time, reducing the ability to recover both the oil and gas indicated in the profiles. Infrastructure and delivery systems BPXA Post -Hearing Submission Page 4 of 7 0 • could also impact oil and gas deliverability later in POP field life. While the FFM Tool and the cases run by BPXA account for well breakage and repair, they do not account for impacts due to facility or pipeline availability or performance, including TAPS.2 Directionally, however, it is safe to say that there will be a disproportionately greater impact on the gas sales cases with later start-up dates. C. ULTIMATE RECOVERY COMPARISON 1. RECOVERY AT A COMMON PROJECT LENGTH Table 1 shows the recovery of oil and gas, fuel usage, and total hydrocarbon recovery assuming a 30- year MGS project life; for example, the 2025 start-up case has an EOFL in 2055 and the 2040 start-up case has an EOFL in 2070. The EOFL of the Oil reference case is 2055. The table shows that hydrocarbon recovery is fundamentally maximized by achieving an MGS project, as the remaining hydrocarbon recovery from 2025 forward increases by more than four -fold for all MGS scenarios relative to the Oil Reference case. Among the MGS scenarios, the table shows that oil recovery increases, with greater fuel gas consumption and less gas sales, with a later MGS project. In addition to greater oil recovery prior to start of major gas sales, additional oil recovery is achieved on the tail of the profile due to possible field life extension. This additional oil recovery is balanced against the additional fuel consumed during the oil production period and on the tail. These results assume that wells and facilities will last for the duration of production in each scenario. These un-risked recovery profiles show that the increase in ultimate total hydrocarbon recovery with later start-up of major gas sales from 2025 to 2030 is about 0.05 B BOE or 50 MMBOE. Extending the start of major gas sales from 2025 to 2040 increases total hydrocarbon recovery by approximately 0.1 B BOE or 100 MMBOE. A volume of 100 MMBOE is only about 0.5% of the total expected hydrocarbon recovery. TABLE t: UNRISKED RECOVERY OF OIL, GAS, FUEL AND TOTAL HYDROCARBONS FROM THE POP FROM 2025 TO 30 YEARS AFTER THE MGS START-UP, SENSTIVITIES TO PBU MGS START-UP DATES. Unrisked Recovery from 2025 to 30 years after MGS Start -Up Case Oil Gas Sales Fuel Gas total Hydrocarbons (Billion STB) (TCF) (TCF) (Billion BOE) Oil Reference 1.07 - 3.68 1.07 Gas Reference - 2025 MGS 0.79 22.43 2.40 4.65 2030 MGS 0.93 21.92 3.08 4.71 2035 MGS 1.05 21.35 3.61 4.73 2040 MGS 1.14 20.96 4.15 4.75 2. RECOVERY AT A COMMON TOTAL HYDROCARBON RATE Assessment of EOFL at a common total hydrocarbon production rate is often used to estimate the economic life of a project. The ultimate hydrocarbon recovery is determined by assessing the 2 As noted earlier, the FFM Tool is capable of performing this analysis, but BPXA has not run such cases. BPXA Post -Hearing Submission Page 5 of 7 0 • cumulative hydrocarbon recovered at the same total hydrocarbon rate for each case, instead of a fixed date. The cut-off rate assumed for this evaluation is 100 MBOE/D, and does not represent BPXA's view of the actual field economic limit which will depend on oil and gas prices and other future economic conditions which cannot be accurately predicted now. This total hydrocarbon rate is consistent with the rate limit used in the 2007 Blaskovich report commissioned by the AOGCC. Figure 5 in the Confidential Appendix to this submittal shows the total hydrocarbon production rate as a function of the total cumulative hydrocarbon recovery. The optimal recovery case is the one achieving the highest cumulative recovery at a given cut-off rate. However, Figure 5 indicates that after the field comes off plateau, the recovery curves lie on top of each other. This means that after gas plateau ends, the cases have similar ultimate hydrocarbon recovery for almost any common hydrocarbon production rate cut-off. Table 2 shows the recovery of oil and gas, fuel usage, and total hydrocarbon recovery assuming a common hydrocarbon rate cut-off of 100 MBOE/D. The data indicates that oil production is greater with MGS than the oil reference case by about 60 million barrels (MMbbls) using the common rate cut-off, rather than -280 MMbbls with a common end date, due to a significant extension of field life. The data in Table 2 also shows that the maximum difference in ultimate hydrocarbon recovery between the 2025 start-up case and other cases is 70 MMBOE, which approaches the resolution of the model for total hydrocarbon recovery (—+/- 40 MMBOE), without making any adjustments for facility life and project availability risks. According to the common total hydrocarbon rate EOFL metric, there is little discernible difference in total hydrocarbon recovery between the different MGS start dates cases, within the resolution of the FFM runs. TABLE 2: UNRISKED RECOVERY OF OIL, GAS, FUEL AND TOTAL HYDROCARBONS FROM THE POP FROM 2025 TO 100 MBOE, SENSTIVITIES TO PBU MGS START-UP DATES. Unrisked Recovery from 2025 to 100 MBOE/D Cut -Off Case Oil Gas Sales Fuel Gas Total Hydrocarbons (Billion STB) (TCF) (TCF) (Billion BOE) Oil Reference 0.72 - 1.91 0.72 Gas Reference - 2025 MGS 0.78 22.16 2.35 4.60 2030 MGS 0.93 21.72 3.04 4.67 2035 MGS 1.05 21.03 3.55 4.68 2040 MGS 1.13 20.35 4.03 4.64 OIL RECOVERY VERSUS FUEL GAS USAGE Using the data in Table 1, the comparative incremental oil recovery and incremental fuel gas burned by pushing back the start-up of MGS, can be approximated. Figure 6 shows that the incremental oil recovered by a later start of MGS from 2025 to 2030 is —140 MMBOE, and the corresponding additional fuel burned is about —120 MMBOE. If POP MGS start-up occurs from 2035 to 2040 the BOE increase in fuel gas consumption surpasses the additional oil recovery. BPXA Post -Hearing Submission Page 6 of 7 0 4,000,000 160,000 3,500,000 140,000 120.000 3,000,000 0 m of 100,000 m t 2 2,500,000 60,000 � d ar 2,000,000 r 5 60,000 c 3 40,000 1,500,000 20,000 1,000,000 c 500,000 PBU MGS Recovery 2025 to 2030 ......__..----- Incremental Recovery Due to Five Year Delay of MGS • OII ■ Fuel (BOE) IPau FFM uncertainty 2025 to 2030 2030 to 2035 2035 to 2040 2030 to 2035 2035 to 2040 FIGURE 1: INCREMENTAL OIL RECOVERY AND FUEL GAS BURNED BY EXTENDING THE START OF MGS FOR FIVE YEAR PERIODS. ERROR BARS REPRESENT PRECISION OF FFM RUN PREDICTIONS FOR ULTIMATE RECOVERY. BPXA Post -Hearing Submission Page 7 of 7 by � • BP Exploration (Alaska) Inc. 900 E. Benson Boulevard Anchorage, AK 99508 P.O. Box 196612 Anchorage, AK 99519-6612 September 8, 2015 Via Hand Delivery ECO M E SEP 0 8 2015 Cathy P. Foerster Commission Chair A0GGV Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, Alaska 99501 Re: Docket Numbers: AIO 15-032, AIO 15-033 and CO 15-09, Prudhoe Oil Pool BPXA Post -Hearing Comment to Commission regarding a Sunset Provision Consolidated Application for Amendment of Prudhoe Oil Pool Rule 9 and Modification of Prudhoe Bay Unit Area Injection Orders AIO 3A and AIO 4F Dear Chair Foerster: BP Exploration (Alaska) Inc. (BPXA) submits the following comment for the Commission's consideration in this matter. The Commission's announcement during the hearing on August 27 that it is inclined to include a Sunset provision in its final order in this matter came as a surprise and source of concern for BPXA and ExxonMobil. While our companies are aware of similar provisions in some parts of our lower 48 operations', the inclusion of a Sunset clause in an AOGCC Order for a pool rule order approving the request for a modification to the existing gas offtake rate is unprecedented and would undermine the certainty of supply from the Prudhoe Bay field that is needed to progress the Alaska LNG Project by BPXA, the State of Alaska, and the other parties. As we testified at the hearing, the Alaska LNG project is not expected to begin operations until approximately 2025. The reason a rate increase is being requested at this time is to provide certainty of supply amongst the parties, the export market, and the lending community. An order with a limited term -of any duration could significantly hinder the progress of the Alaska LNG Project because the long-term basis for gas sale contracts would be uncertain. As we presented in both the written materials and verbally during the hearing, the best way for the Commission to help ensure greater ultimate recovery of oil ' For example, it is not uncommon in states similar to Kansas for its Conservation Commission Orders to include a termination clause such as the following in its orders: "This Order shall remain in effect until amended, changed, or modified by order of the Commission." However, a more specific Sunset provision generally would be based on operational considerations versus a simple time limit. For instance, certain Orders might terminate "at that point in time when no remaining well in the field is capable of producing in excess of 'Y' Mcf/d of gas or "y" bbls/d of crude oil, unless modified by further order of the Commission to terminate sooner". BPXA Post -Hearing Comment to Commission Regarding a Sunset Clause Application to Amend POP Rule 9 and Modify AIOs Page 2 September 8, 2015 and gas from the Prudhoe Bay Unit Prudhoe Oil Pool is to exercise its statutory authority to facilitate the project moving forward to the fullest extent possible. Moreover, it is important to note that the inclusion of a Sunset provision in the Commission's order is not necessary because the Commission has the existing statutory power to call an investigation to re-evaluate any existing Order and either issue an emergency suspension of that provision or undertake a full hearing on the issue. Therefore, inclusion of a Sunset clause would provide little or no benefit to the Commission at the considerable cost of stifling certainty for long-term gas supply commitments. Sincerely, /,D-7 Dave n uyl Regional Manager BP Exploration (Alaska) Inc. 0 Dave Lachance Vice President Alaska Reservoir Development September 8, 2015 Via Hand Delivery Cathy P. Foerster Commission Chair Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, Alaska 99501 BP Exploration (Alaska) Inc. 900 East Benson Boulevard P.O. Box 196612 Anchorage, AK 99508 USA Direct 907 564 4855 Mobile 907 538 1719 Main 907 564 5111 dave.lachance0bp.com RECEIVED SEP 0 8 2015 AOGCC Re: Docket Numbers: AIO 15-032, AIO 15-033 and CO 15-09, Prudhoe Oil Pool BPXA Post -Hearing Submission of Redacted Confidential Presentation for Public Record Consolidated Application for Amendment of Prudhoe Oil Pool Rule 9 and Modification of Prudhoe Bay Unit Area Injection Orders AIO 3A and AIO 4F Dear Chair Foerster: BP Exploration (Alaska) Inc. (BPXA) submits, on behalf of itself and ExxonMobil Production Inc., as applicants in the above referenced matter, the enclosed redacted version of BPXA's confidential presentation to the Commission during the hearing on August 27, 2015. The enclosed presentation has been redacted to remove confidential data, consistent with our discussion with the Commission during the hearing, so that it may be included in the public record in this matter. Si cerely, Dave P. Lachance Vice President, Reservoir Development Attachment BPXA Post -Hearing Submis3Ton of Redacted Confidential Presentation Apublic Record Application to Amend POP Rule 9 and Modify AIOs Page 2 September 8, 2015 cc via email: Ernesto Daza, BPXA (ernesto.daza@bp.com) John Dittrich, BPXA Oohn.dittrich@bp.com) George Lyle, Guess & Rudd (glyle@guessrudd.com) Chris Wyatt, BPXA (chris.wyatt@bp.com) Gilbert Wong, EMAP (gilbert.wong@exxonmobil.com) Gerry Smith, EMAP (Gerry.b.smith@exxonmobil.com) Steve Luna, EMAP (charles.s.luna@exxonmobil.com) Brian Gross, EMAP O.brian.gross@exxonmobil.com) Jon Schultz, CPAI(Jon.Schultz@conocophillips.com) Eric Reinbold, CPAI (Eric.W.Reinbold@conocophillips.com) John Evans, CPAI (John.R.Evans@conocophillips.com) Phil Ayer, CUSA (pmayer@chevron.com) Angie Bible, CUSA (abible@chevron.com) Redacted Version for Public Record CONFIDENTIAL PRESENTATION The data in the following presentation contains BPXAs own engineering, geological and geophysical analysis and interpretation of PBU data, as well as other sensitive commercial information. BPXA requests that this information be held confidential pursuant to AS 31.05.035(d), 20 AAC 25.537(b) and AS 45.50.910 et seq., as well as Section 11.4 of the Prudhoe Bay Unit Agreement. (Please note that the slides also include some non - confidential narrative carried over from the public session for presentative purposes.) L / Hu(J. u5t LU I :D bp RECEIV,ED SEP p 2015 AOGCC • Support Rule 9 Application for amendment of CO 341 D Rule 9 for the Prudhoe Oil Pool (POP) 0 Technical justification for increasing the maximum allowable gas offtake from 2.7 to 4.1 BCFD Address several topics of interest for the AOGCC Support Application for AlO Modification of AlO 3A and AlO 4F Technical justification for request to inject CO2-byproduct into the POP for Enhanced Recovery and Pressure Maintenance 0 by The Major Gas Sales (MGS) Reference Case (3.3 BSCFD) and the Maximum Allowable Gas (MAG) Sensitivity Case (4.1 BSCFD) both demonstrate significant additional hydrocarbon recovery from POP as a result of major gas sales Results of the MGS reference case demonstrate that POP is capable of delivering: Approximately 22 Trillion Standard Cubic Feet (TSCF) of hydrocarbon sales gas or 3.8 billion Barrels of Oil Equivalent (BOE) A gas sales plateau length of 20+ years Continued oil development and production The MAG sensitivity case produces an equivalent ultimate hydrocarbon recovery of between 17.7 and 17.8 billion BOE's An increase in Rule 9 gas offtake to an annual average of 4.1 billion standard cubic feet per day (BSCFD) is consistent with good oil field engineering practices; and positions the Prudhoe Bay Unit working interest owners to access of the MGS opportunity afforded by the Alaska LNG Project, and therefore should be approved 9 Integrated subsurface, well, pipeline and facility model World class history match from 1977 to Present Examples of Uses: Facility optimization Activity planning Lean and Miscible gas injection Gas Cap Water Injection (GCWI) Gas Sales Development planning Reservoir Model Grid :uration Redacted Confidential Information • Redacted Confidential Information 11 1) Oil Reference Case a) Active development drilling program b) Rig workovers for well repair c) Continued Gas Cap Water Injection (GCWI) d) Normal annual TAR events and facility downtime 2) MGS Reference Case and MAG Sensitivity Case a) Same drilling program as Oil reference case b) Rig workovers for well repair c) Continued Gas Cap Water Injection (GCWI) d) 1 /1 /2025 gas sales startup with a 1 year ramp e) Annual average supply to AKLNG GTP inlet (w/CO2): I MC,� RAfAf AI'1(P �'ACP nn,4('- ' L 2.7 BCF/D 33.6_BCF/D f) Normal annual TAR events and facility downtime g) GTP by-product (CO2) injected into Eileen West End (EWE) h) Convert apex gas injectors to producers i) Add gas perforations j) Project length 30 years U • by 0 • Forecasted liquid volumes reflect ongoing development activity • Field production continues to decline with substantial development and optimization • Recovery approaches 4.5 billion stb's more than originally predicted in 1977 of 9.7 billion stb's Redacted Confidential Information C] POP Voidage (Oil, Water, Gas) 10000 woo soon — (� 4500 7 4 < C- T00D D W m 5000 4000 o O (� ame V 5000 a L Z 4000 O r 3500 w +(1) C5 3000 (6 U. 2WW 3000fy M 1000 0 2500 Jan•75 Janm Jan-85 Jan-90 30115 JI 100 J11•05 Jan.10 Jan-15 Jan•20 Jan-25 ®QO, I4M W �Qgi ffw d �Qw, nvWd - NCPVD PRES e POP has acted like a gas field from early in its development 85% of reservoir volume produced is gas. • Objective of gas sales is to turn the dominant remaining phase into recovered hydrocarbons. I] Alaska LNG Project has advised gas supply to the GTP must be maintained, under normal operations, at rate of —3.5 BSCFD annual average untreated gas GTP feed rate of —3.5 BSCFD rate allows for 0.4 - 0.5 BSCFD for in -State demand and —2.7 BSCFD LNG facility inlet demand 0 POP's total gas offtake would also include lease fuel and minor North Slope sales sales and Miscible Injectant NO used outside of the POP in Prudhoe Bay Unit satellites. 4.1 BSCFD allows PBU flexibility - to supply the full GTP feed rate in the event of supply disruptions from other fields, to accommodate improved Alaska LNG Project facility performance and to allow operational flexibility RequirementsGas Offtake POP Offtake — POP Offtake — KA(_C Rnferonr-o nnnr_ cor +„+„ Case (Normal Case Operations) * Higher supply rate due to higher CO2 concentrations in POP than in other fields Gas Offtake Produce gas from existing well stock Optimize offtake with: Targeted re -completion for gas Injector to producer conversions Two redundant offtake points at Central Gas Facility (CGF) Upgrade select equipment to ensure reliable gas delivery AKLNG Project participants are designing the GTP to return the CO2 byproduct to PBU Conceptual CO2 receipt and distribution system 1 rnnes CO2 Control Module 0 CGF 0.5 miles CO2 from GTP APEX PL �- 1 miles) GC-2 ....� GC-1 3 miles 2 miles 5 miles GC-3 by ti VALVE VDDL�L# -. 1 -...vw�.uN- CO2 Receipt and Injection EWE is the most promising option. Injection into Eileen West End (EWE) through new pipeline to existing wells at well pads W and Z • Additional CO2 injection options outside POP will be evaluated for additional enhanced recovery opportunity • Backup capability could be FS2 and the Apex injectors • POP MGS Reference Case Offtake Profile Qgariwvtati ivnni irl g nt nl i�1"'lifinsr�mntinn m ID 0 POP MAG Sensitivity Case Offtake Profil, Redacted Confidential Information • ® Results of MGS reference case demonstrate POP is capable of delivering planned plateau gas supply for approximately 20 years. ® Total gas supply from POP over project period is comparable for MGS reference and MAG sensitivity cases Redacted Confidential Information • • POP pressure declines about 100 psi / year in the MGS reference case during the plateau period, but remains sufficient to sustain the planned gas supply. • POP pressure decline slightly greater in the MAG case, but still remains ,i Iffir.iPnt to �i ��tain nlannarl ryac ci inr�ly Redacted Confidential Information 0 Cumulative curves include gas recovery in BOE totals Redacted Confidential Information 14 • 0 Key Prediction Results -BOE Production • Redacted Confidential Information • The net total BOE recovery increase from POP due to MGS is —3.6 Billion BOE. • Cumulative oil during major gas sales is decreased by <300 million bbls, due to pressure impacts, but greatly offset by increased BOE's from gas sales. • The MGS reference and MAG sensitivity cases demonstrate the substantial increased hydrocarbon recovery from POP due to MGS compared to the Oil Reference case 20.0 18.0 IT-1( W m 14.0 c 0 in 12.0 ►.o 2.0 w ■ Gas Sales ■ Remaining Oil+NGL Produced Oil+NGL to 1/1/2015 Reference Oil Case MGS Reference Case i MAG Sensitivity Case 11 —3.5-3.6 billion BOE's additional HC recovery from POP due to MGS. I • M The current field activity prepares for MGS: Active drilling program Rig workovers to maintain healthy well stock Continued Gas Cap Water Injection (GCWI) Active non -rig well work programs Waterflood and MI management ^° BPXA and the other unit owners will continue to actively manage field optimization of the depletion strategy to enhance field performance into the future • Additions o0`it = tart Sensitivity ....... ..... Redacted Confidential Information by q The Alaska LNG schedule basis is for a 2025 start-up. It is unknown when or if other major gas sales opportunities will w come Later initiation of gas sales by more than 5 years will decrease recovery, as fuel gas impacts become larger than oil impacts Later gas sales increases risk of facility life impacts on recovery (not accounted for in profiles). • PBU FFM used to test sensitivity to injection of PTU gas into POP starting in 2023 at rate of —800 MMSCFD. Inject 0.6 TCF of PTU gas into POP. In 2025 PTU and POP deliver gas to GTP Results: Negligible net impacts to oil recovery POP oil rates decrease during PTU gas injection Additional pressure provides some compensating oil benefits Redacted Confidential Information 2 • byy The Major Gas Sales (MGS) Reference Case (3.3 BSCFD) and the Maximum Allowable Gas (MAG) Sensitivity Case (4.1 BSCFD) both demonstrate significant • additional hydrocarbon recovery from POP as a result of major gas sales Results of the MGS reference case demonstrate that POP is capable of delivering: Approximately 22 Trillion Standard Cubic Feet (TSCF) of hydrocarbon sales gas or 3.8 billion Barrels of Oil Equivalent (BOE) A gas sales plateau length of 20+ years Continued oil development and production The MAG sensitivity case produces an equivalent ultimate hydrocarbon recovery of between 17.7 and 17.8 billion BOE's An increase in Rule 9 gas offtake to an annual average of 4.1 billion standard cubic feet per day (BSCFD) is consistent with good oil field engineering practices; and positions the Prudhoe Bay Unit working interest owners to access of the MGS opportunity afforded by the Alaska LNG Project, and therefore should be approved 20 by Objective Requesting modification to AIO 3A and 4F for the POP Explain technical benefits and implications of injection CO2 into POP Summary CO2 handling limitations impact CO2 injection development options POP is injecting a similar amount of CO2 under current field operations EWE is the most promising location for CO2 injection within the POP Additional CO2 from outside sources generates negligible changes to POP reservoir outcomes BPXA has studied and anticipates that the PBU working interest owners will continue to evaluate potential locations where CO2 injection may be economically beneficial for enhanced recovery and pressure maintenance GTP Gas Supply & CO2 By-Productr*9, Volume • Total GTP supply in the MGS reference case assumes 25% of gas delivered from non -POP sources. • Currently POP produces and injects —800 MMSCFD of CO2 as part of field operations • The AlO modification requests approval to inject GTP CO2 By - Product (POP CO2 plus an estimated —40 MMSCFD from PTU). • Estimated GTP CO2 By -Product: • POP —3.1 TCF • PTU — 0.3 TCF • Total — 3.4 TCF Redacted Confidential Information Redacted Confidential Information 22 0 CO2 handling limitations Corrosion mitigation limits CO2 concentrations in equipment Increased CO2 concentration impacts equipment operational efficiency (turbines, flares, de -hydration) Gas liquefaction must have very low concentrations CO2 for LNG processing. GTP CO2 processing capacity is expected to limit overall inlet gas CO2 concentrations. Current modeling assumptions Wells shut-in upon reaching 25 mole% CO2 - The GTP will have a CO2 handling limit 0 by 14 The PBU FFM was used to determine the most promising location in the POP for GTP CO2 by-product injection for total hydrocarbon recovery Injection areas investigated: Eileen West End (EWE) Flow Station 2 Area (FS-2) Gas Cap — behind GCWI Injectors za • • CO2 Injection Location, POP Recovery Redacted Confidential Information EWE is the most promising location for CO2 injection for total hydrocarbon recovery EWE CO2 injection limits migration to high gas recovery areas z{ • Foe Date View Polnl Gne spectum Dlspiry WellsHelp 11 a 01 J042025 111 AK LNG. 100% CO2 IsEM CO2YMOle FnaO. ! 2025 R M J E R 1 f m 16 C Is L3 « 11 a � as 14 as to n u . d:.... u:�si..... a 0, FYe DYa VlMPOW Grld ecnm Dla TMM r Fxe Dale Vlea Pone Gnd Spec"em DlaPlaY Welt Help Sp Plry Wells NeID �1-Q - file Data View Polnl Gild SPeclrum Dlaplty Welb Help 14.J ....•,.«�.:......., lime, 01 JW2055 r. ,..>-....,..,..._..-.m,-..�.......,.- �.,,..-:--�.�...o..w...,.- 01 .IAH-1055 . ""•" Time. 01FJAM2045 1 -Y AK LNG. 100% CO2 In FVA z ,AK LNG 100%CO2 IR FS2 TAKING. 100%CO2NGncap bF EV1/E - 2055 \ `D2YMeMF`aebn FS-2 - 2055 CO2YMOIeFrwOOR Gas Ca - 2055�r`-�� @Id OpeeMyp20 G- tea- p- i _- ----_ � ,GHd ODeeMy dSO i T ` s Mqw Y:. hpC J u } ■■■■■■■yyy O- L1� 'ry 11 pa { 9 ( V H \ I L X fa ea 05 oa �aaN, .. � � 01 °6 i Blue indicates higher CO2 concentrations dditional Topic of Inte re - .. � a -,en..s-i,.*D-,.v,.itv.....,t,o,,--I.ni .ection,of CO2 from T PBU FFM used to test sensitivity of reservoir to additional 0.3 TCF CO2 removed from PTU gas Same total BOE recovery as MGS reference case within model resolution Injection of CO2 removed from PTU gas into POP creates no discernable change to ultimate hydrocarbon recovery from POP Redacted Confidential Information 27 UA Additional Topic of Interest " Alternate CO2 Usage in PBU - Studies • CO2 Injection Lab Studies e- Point McIntyre Borealis Orion • Tools developed for CO2 injection benefit prediction EOS models tuned to CO2 lab data Type patterns Type pattern scale -up tools (COBRA) Compositional full field models • Continuing to perform development studies to evaluate potential use of CO2 within PBU • WE Redacted Confidential Information To achieve upside all CO2 handling limitations need to be removed. High side assumes MI injection discontinued in 2015 with no additional FOR recovery. 29 �J i II 41 Summary CO2 handling limitations impact CO2 injection development options POP is injecting a similar amount of CO2 under current field operations EWE is the most promising location for CO2 injection within the POP Additional CO2 from outside sources generates negligible changes to POP reservoir outcomes BPXA has studied and anticipates that the PBU working interest owners will continue to evaluate potential locations where CO2 injection may be economically beneficial for enhanced recovery and pressure maintenance :�o • E R All opinions, assessments and analyses (including forward looking or predictions of future activities) in this presentation are those of BP Exploration (Alaska) Inc., in its capacity as an individual working interest owner in the Prudhoe Bay Unit. The PBU FFM consists of three parts: (1) historical PBU operational data; (ii) a set of reasoned assumptions about future PBU activities; (items (1) and (ii) are collectively referred to as the "FFM Inputs"); and (iii) a BPXA proprietary and trade secret process consisting of software code and algorithms owned by or licensed to BPXA (the "FFM Tool"). Full Field Model runs (sometimes referred to as cases or scenarios) are generated by inputting the FFM Inputs into the FFM Tool. FFM runs are meant to be predictive of future circumstances or consequences that could occur, depending on the FFM Inputs. Because of the proprietary and trade secret processes that BPXA employs in the use of the FFM Tool, it is not possible to derive • the details of PBU operational or technical data (e.g., specific geological data) from FFM runs. BPXA uses the FFM Tool to generate FFM runs for both itself and, upon request, for the PBU working interest owners. All references in this testimony to the FFM (or to PBU FFM) are a reference to FFM Inputs plus the FFM Tool. Colombie, Jody J (DOA) From: Schultz, Jon S <Jon.Schultz@conocophillips.com> Sent: Friday, September 04, 2015 2:28 PM To: Roby, David S (DOA) Cc: gilbert.wong@exxonmobil.com; Luna, Charles S (charles.s.luna@exxonmobil.com); pmayer@chevron.com; abible@chevron.com; john.dittrich@bp.com; glyle@guessrudd.com; chris.wyatt@bp.com; Reinbold, Eric W; Evans, John R (LDZX); Foerster, Catherine P (DOA); Seamount, Dan T (DOA); Ballantine, Tab A (LAW); Colombie, Jody J (DOA); Wallace, Chris D (DOA) Subject: RE: Supplemental information on CO2 disposal (dockets: AIO 15-032, AIO 15-033, and CO 15-09) Mr. Roby, Thank you very much for your note and opportunity to clarify our disposal request. The 2015 EPA Guidance supports CO2 disposal in Class 11 wells except where "the primarypurpose [is] long-term storage ... [and] there is an increased risk to USDWs ... ", and only where Class II regulatory tools cannot manage the increased USDW risk (2015 EPA Guidance, at 2 and note 1, emphasis in original) (quoting 40 CFR 144,19). Accordingly, the Commission's authority to authorize Class II CO2 disposal, as supported by the 2015 EPA Guidance, is broad. That said, CPAI's request for the Commission to authorize disposal is narrow and tailored to the circumstances you describe in your note below. Specifically, CPAI requests that the Commission authorize CO2 disposal in Class II wells only where, as you state, an "enhanced recovery project is no longer viable." If an enhanced recovery project is viable, the CO2 would be injected and used for enhanced recovery. As we stated in our Comments and testimony, the working interest owners have done considerable work examining potential enhanced recovery opportunities; we will continue this work in advance of projected AKLNG start-up in 2025. We hope this clarification assists the Commission's consideration of our request. Please advise if CPAI can provide any further information or clarification. Responsive to your last question, CPAI does not request at this time that the Commission leave the record open beyond Sept. 8. Thank you very much. Regards, Jon Schultz ConocoPhillips Alaska Manager, Greater Prudhoe Area Office: +1-907-265-1315 Mobile: +1-907-227-8708 From: Roby, David S (DOA) fmailto:dave.roby(o)alaska.gov] Sent: Friday, September 04, 2015 12:07 PM To: Schultz, Jon S • CC: Obert.wona(&exxonmobil.com; Luna, Charles S (charles.s.luna@exxonmobil.com); pmayer@chevron.com; abible@chevron.com; john.dittrichftp.com; glyle@quessrudd.com; chris.wyattftp.com; Reinbold, Eric W; Evans, John R (LDZX); Foerster, Catherine P (DOA); Seamount, Dan T (DOA); Ballantine, Tab A (LAW); Colombie, Jody J (DOA); Wallace, Chris D (DOA) Subject: [EXTERNAL]Supplemental information on CO2 disposal (dockets: AIO 15-032, AIO 15-033, and CO 15-09) Mr. Schultz, Thank you for your letter dated September 3, 2015, in response to the AOGCC's request at the August 27, 2015, hearing on gas offtake from PBU that ConocoPhillips explain how the AOGCC has authority to approve CO2 disposal in Class II wells as opposed to requiring that CO2 disposal be conducted in Class VI CO2 sequestration wells. We are, frankly, reading and interpreting the April 23, 2015, EPA memo quite differently than you are. The memo clearly states that CO2 injection for enhanced recovery purposes is a Class II operation, which the AOGCC concurs with, however what you're proposing is CO2 disposal and by our reading of the EPA memo that can only be done as a Class II operation if it is using Class II wells that were formerly used for enhanced recovery operations but the enhanced recovery project is no longer viable. Injection of CO2 into a disposal interval or into a deep portion of the Ivishak aquifer where injection would not contribute to enhanced oil recovery would not fall into the narrow definition of when the EPA says that Class II wells can be used instead of Class VI wells for CO2 disposal. Unless you have something directly from the EPA that clearly shows that our interpretation of their memo is incorrect I'm afraid I will have to recommend that the Commissioners reject your application for authorization of CO2 disposal at this time. If you have such a document please submit it, if you do not but would like to ask the EPA to weigh in on this matter on the record we'd be willing to keep the record open for a reasonable amount of time to allow them to do so. Please advise before COB Tuesday September 8`h if you'd like us to keep the record open and if so for how long. Regards, Dave Roby Sr. Reservoir Engineer Alaska Oil and Gas Conservation Commission (907)793-1232 • ConocoPhillips Alaska September 3, 2015 Catherine P. Foerster, Commission Chair Alaska Oil and Gas Conservation Commission 333 W. 7th Ave #100 Anchorage, Alaska, 99501-3539 RECEIVED SEP 0 3 2015 ,A®GC Jon Schultz Manager Greater Prudhoe Area P.O. Box100360 Anchorage, AK 99510-0360 Phone:907-265-1315 RE: Docket Numbers: AIO 15-032, AIO 15-033, CO 15-09 — Prudhoe Bay Unit ConocoPhillips Alaska, Inc. (CPAI) Supplemental Submission Re AOGCC Authority to Authorize Disposal of Gas Treatment Byproducts, Principally Comprising Carbon Dioxide, In Class II Wells Dear Commissioner Foerster, At the August 27, 2015 hearing in the above referenced matter, the Alaska Oil and Gas Conservation Commission (Commission) requested that CPAI provide supplemental information regarding the Commission's authority to approve disposal of gas treatment byproducts, principally comprising carbon dioxide (CO2), in Class II PBU wells (Supplemental Submission). More specifically, at the August 27 hearing, the Commission received into the record an April 23, 2015 guidance letter from the United States Environmental Protection Agency (EPA) Director of the Office of Ground Water and Drinking Water, referencing key principles related to transition of Class II to Class VI wells (2015 EPA Guidance, attached). The Commission requested that CPAI explain how the 2015 EPA Guidance supports the Commission's authority to authorize CO2 disposal in Class II wells. 1. Background: Underground Infection Control Program Under the Safe Drinking Water Act, EPA is authorized through the Underground Injection Control (UIC) program to regulate the injection of fluids into underground wells in order to ensure underground sources of drinking water (USDWs) are not impaired. EPA's UIC regulations govern the siting, construction, operation and closure of six "classes" of underground injection wells - referred to as Class I through Class VI - which vary according to the potential for the class of injected fluid to impact USDWs. See 40 C.F.R. § 144.6. The two UIC well classes pertinent to the Commission's inquiry in this matter are: • Class II - Class II wells are primarily used by the oil and gas industry to inject fluids either for enhanced recovery (ER) or exploration and production waste disposal. • • CPAI Supplemental Submission Re Commission Authority to Approve CO2 Disposal in Class II Wells Page 2 of 4 September 3, 2015 • Class VI - In late 2010, EPA promulgated regulations establishing a new category of injection wells defined to be wells "used for geologic sequestration of carbon dioxide beneath the lowermost formation containing a USDW[.]" 40 C.F.R. § 144.6(f).' A state or tribe may apply for and obtain from EPA primacy (lead administration and enforcement authority) for one or all of the six classes of UIC wells. The State of Alaska, through the Commission, has obtained primacy to administer and enforce the Class II UIC program in Alaska. The State of Alaska has not yet sought primacy to administer and enforce the Class VI UIC program.2 Though it has existed for five years, the Class VI program is not widely used. At this time, EPA has approved Class VI wells for two applicants, and estimates that 6 to 10 additional commercial Class VI wells will come online by 2016.3 By comparison, EPA reports that there are approximately 172,068 Class II wells currently in operation.4 2. The 2015 EPA Guidance Clarifies That the Commission Has Authority to Approve CO2 Disposal or Storage In Class II Wells In its 2015 guidance letter, consistent with well -established Class II regulation of both enhanced recovery injection and exploration and production waste disposal, EPA pragmatically encourages use of Class II wells for CO2 injection for ER, as well as for CO2 disposal or storage.5 EPA recognizes that "CO2 storage associated with Class II wells is a common occurrence ...." 2015 EPA Guidance at 1. EPA notes that "CO2 can be safely stored where injected through Class II -permitted wells for the purpose of oil or gas -related recovery". Id. This is consistent with current PBU enhanced recovery operations. As BPXA notes in its pre -filed testimony, CO2 is a significant component (comprising approximately 800 mmscf/d) of the gas currently reinjected in the Prudhoe Oil Pool (POP) for enhanced oil recovery. (BPXA Pre -Filed Testimony, at 12.) As the Commission is aware, in the major gas sale development phase of Prudhoe Bay, after commencement of natural gas offtake, treatment and export, natural gas reinjection into the POP to support enhanced liquid recovery would decrease over time. Also in this next phase, gas treatment byproduct, principally comprising CO2, would be injected. Although this CO2 would be preferentially used for ER, if viable ER opportunities are not identified, the CO2 would be injected for disposal (as, for example, produced water would be injected for disposal, where viable ER opportunities for water injection are not presents). Regarding such Class II CO2 injection in later phases of oil and gas development, EPA states: ' See generally40 C.F.R. § 146.81 et seq. (EPA's UIC Class VI program regulations). 2 The 2015 EPA Guidance encourages states to apply for primacy for all well classes, including Class VI 3 See http://www.epa.gov/r5water/uic/adm/ (reporting on the issuance of two Class VI UIC wells to Archer Daniels Midland, one of which had been appealed to the Environmental Appeals Board),- http://www.epa.gov/r5water/uic/future-gen (addressing Class VI permits issued to FutureGen Alliance 2.0). 4 http://water.epa.gov/type/groundwater/uic/wells.cfm. 5 The 2015 EPA Guidance generally refers to CO2 "storage". In the context of Alaska's Class II program, "storage" of CO2 would constitute "disposal". See 20 AAC 25.252 and note 6 below. s Like produced water, if not used for ER, the gas treatment byproduct stream would be conventional oilfield waste. See 58 Fed. Reg. 15284, 15286 (Mar. 22, 1993); EPA Report to Congress on the Management of Waste from the Exploration, Development, and Production of Crude Oil, Natural Gas, and Geothermal CPAI Supplemental Submission Re Commission Authority to Approve CO2 Disposal in Class 11 Wells Page 3 of 4 September 3, 2015 If oil or gas recovery is no longer a significant aspect of a Class II permitted ER operation, the key factor in determining the potential need to transition a CO2 ER operation from Class II to Class VI is the increased risk to USDWs related to significant storage of CO2 in the reservoir, where the regulatory tools of the Class II program cannot successfully manage the risk. 2015 EPA Guidance at 2 (emphasis in original). EPA further states: The most direct indicator of increased risk to USDWs is increased pressure in the injection zone related to the significant storage of CO2. Increases in pressure with the potential to impact USDWs should first be addressed using tools within the Class II program. Transition to Class VI should only be considered if the Class H tools are insufficient to manage the increased risk. The key regulation, "Transitioning from Class II to Class VI," codified at 40 CFR 144.19, states that owners or operations that are injecting carbon dioxide for the primary purpose of long-term storage into an oil and gas reservoir must apply and obtain a Class VI GS permit when there is an increased risk to USDWs compared to Class ll operations. 2015 EPA Guidance at 2 and note 1 (first emphasis added; second and third emphases in original). This EPA guidance directly supports the Commission's authority to authorize CO2 disposal in Class II PBU wells. As BPXA states in its application, there is no underground freshwater source within the PBU; accordingly, there is no risk of movement of injected CO2 into USDWs. BPXA and EMAP Consolidated Application at 6. Applying this key fact to EPA's guidance, because there is no increased risk to USDWs, even if viable enhanced recovery opportunities are not identified, and CO2 and other gas treatment byproducts are injected into the reservoir for disposal or storage, rather than enhanced recovery, Class II tools will remain sufficient to manage any risks. Accordingly, there will be no reason or requirement to transition any PBU Class II operation to Class VI. As PBU CO2 disposal or storage will remain a Class II operation, the Commission has and will retain authority to approve and regulate it. We trust this Supplemental Submission addresses the Commission's request. If there is additional information that CPAI can provide, we would be pleased to do so. Sincerely, ttz, Manger, Greater Prudhoe Area hillips AI ska, Inc. Energy, EPA530-SW-88-003, Vol. 1, at p. II-18 (Dec. 1987); EPA530-K-01-004, Exemption of Oil and Gas Exploration and Production Wastes from Federal Hazardous Waste Regulations at 7 (Oct. 2002). • • CPA[ Supplemental Submission Re Commission Authority to Approve CO2 Disposal in Class II Wells Page 4 of 4 September 3, 2015 Attachment 1 — April 23, 2015 EPA Guidance cc via email: Gilbert Wong, EMAP (gilbert.wong(a-exxonmobil.com) Steve Luna, EMAP(charles.s.lunar�exxonmobil.com) Phil Ayer, CUSA (pmayer(ochevron.com) Angie Bible, CUSA (abible(a)_chevron.com) John Dittrich, BPXA (John. Dittrich(aDbp.com) George Lyle, Guess & Rudd (glyle(c)-guessrudd.com) Chris Wyatt, BPXA (Chris.Wyatt(@bp.com) Eric Reinbold, CPAI (Eric.W.Reinbold(d-)conocophillips.com) John Evans, CPAI (John.R.Evans a�conocophillips.com) 0 • Attachment 1 April 23, 2015 EPA Guidance See attached. • • J�tI k tr 'I t4 rfs K xiNl qt ✓'HOtEG UNITED STATES ENVIRONMENTAL PROTECTION AGENCY WASHINGTON D C 20460 Ar17 ? 3 901,; OFFICE CIE WAIEFR MEMORANDUM FROM: Peter C. Grevatt. Director Office of Ground Water and Drinking Water TO: Regional Water Division Directors SUBJECT: Key Principles in EPA's Underground Injection Control Program Class VI Rule Related to Transition of Class 11 Enhanced Oil or Gas Recovery Wells to Class VI Most states have primary enforcement responsibility (i.e.. primacy) for the Class 11 Underground Injection Control program for oil or gas -related injection activities, while EPA Regions currently retain direct implementation authority for the Class VI program in every state. The shared implementation of the UIC program necessitates a clear articulation and common understanding of the potential for transition of enhanced recovery wells from Class I1 to Class VI, consistent with EPA's Class VI Rule. This memo is intended to emphasize the key principles in EPA's UIC Class VI Rule related to the transition from Class Il to Class VI for ER wells that inject carbon dioxide for long-term storage. As Regions work with states on implementation of the Class VI program. I encourage you to assist states in submitting primacy applications for all well classes, including Class VI. EPA recognizes the importance of geologic sequestration of anthropogenic CO2 for climate change mitigation. The UIC Class VI Rule was developed to facilitate GS and ensure protection of underground sources of drinking water from the particular risks that large scale CO2 injection for purposes of long- term storage may pose. The following are key principles related to the transition of ER wells that store CO2 from Class 11 operations to the Class V1 program: 1. Geologic storage of COz can continue to be permitted under the UIC Class lI program. ER wells across the U.S. are currently permitted as UIC Class 11 wells. CO2 storage associated with Class 1I wells is a common occurrence. and CO2 can be safely stored where injected through Class II -permitted wells for the purpose of oil or gas -related recovery. 2. Use of anthropogenic CO2 in ER operations does not necessitate a Class VI permit. ER operations can continue to be permitted as Class 11 wells.. regardless of the source of COz. An owner or operator of an ER operation can switch from using a natural source to an anthropogenic source of CO2 without triggering the need for a Class VI permit. Interriet Address WRY I • htlp rwwx apa pv Recycled/Recyclable ' Pr, 711rd i;:h Legeiahle N Based (r7ks on It30': Postron*;"Me7 P{CCL+ss Cd lnr,ne FFeP FieCjCleQ I'aFe1 3. Class VI site closure requirements are not required for Class II CO2 injection operations. A Class II well that has been used 1br injection of anthropogenic or non-anthropogenic COz and has been operated within its permit conditions can be closed as a Class lI well. 4. f ER operations that are focused on oil or gas production will be managed under the Class II program. If oil or gas recovery is no longer a significant aspect of a Class II permitted ER operation, the key factor in determining the potential need to transition a COz ER operation from Class II to Class VI is the increased risk to USDWs related to significant storage of COz in the reservoir, where the regulatory tools of the Class II program cannot successfully manage the risk. The most direct indicator of increased risk to USDWs is increased pressure in the injection zone related to the significant storage of CO?. Increases in pressure with the potential to impact USDWs should first be addressed using tools within the Class 11 program. Transition to Class VI should only be considered if the Class II tools are insufficient to manage the increased risk. 5. The Class lI and Class VI directors should work together to address the potential need for transition of any individual operation from a Class II to a Class VI permit. The Class II program director (in most cases a state official) will have the relevant data on pressure and volume of COa injected into Class I1 ER operations, which will influence any transition decision. EPA encourages the Class II director to contact the Class VI director where he/she believes the risk has changed as a result of significant storage of CO2 in the reservoir. 6. , The best implementation approach is for states to administer both the Class II and the Class VI UIC programs. EPA encourages states to apply fbr primacy for all well classes, including Class VI. Based on our conversations with states, in most cases, states who are approved for primacy for the Class V1 program are expected to administer the program through their oil and gas program. The Office of Ground Water and Drinking Water is currently working with the U.S. Department of Energy, state associations, EPA Regions and stakeholders to finalize technical guidance focused on risk factors discussed in the Class VI Rule at 40 CFR 144.19. As we complete the final guidance, we will work to ensure that these key principles remain clear. Please contact me or have your staff contact Ron Bergman at 202-564-3823 if we can be of assistance to you on these or other UIC program issues. `The key regulation, "Transitioning from Class 11 to Class Vl," codified at 40 CFR 144.19, states that owners or operators that are injecting carbon diox ide for the primary purpose of long-term storage into an of I and gas reservoir must apply for and obtain a Class V1 GS permit when there is nit increased risk to USDffs compared to Class 11 operations. r 411 NAME STATE OF ALASKA OIL AND GAS CONSERVATION COMMISSION Public Hearing Docket Numbers: AIO 15-032, AIO 15-033, and CO 15-09 Prudhoe Bay Unit August 27, 2015 at 9am AFFILIATION Testify (yes or no) )v /)-N- N L � VA r t l,la)"I a (.e A 0CIL C 0 � s —1IC)�4---e IVy 22 . 410 ob 0 30kh �,J wv� cloi> NO jtl�m-&Le- oA C-0 f �ja ti.5� 10..E-IiWesG 'k- _ d�.IIATE Am ,10 9 • r 0 • S-� M 7t�ol TO eS -1 / 4)2 h " -If-L axe IL Syr(,dV),/V- C- AU nD) )� • • `71t} a7q; fu UNITED STATES ENVIRONMENTAL PROTECTION AGENCY ; VVASHINGTON D C 20460 q� HAt)=tiG CTIFX f i-t YdhltP MEMORANDUM FROM: Peter C. Grevatt. Director Office of Ground Water and Drinking Water TO: Regional Water Division Directors SUBJECT: Key Principles in EPA's Underground Injection Control Program Class Vi Rule Related to Transition of Class II Enhanced Oil or Gas Recovery Wells to Class VI Most states have primary enforcement responsibility (i.e., primacy) for the Class 11 Underground Injection Control program for oil or gas -related injection activities. while EPA Regions currently retain direct implementation authority for the Class VI program in every state. The shared implementation of the UIC program necessitates a clear articulation and common understanding of the potential for transition of enhanced recovery wells from Class 11 to Class V1, consistent with EPA's Class VI Rule. This memo is intended to emphasize the key principles in EPA's UiC Class VI Rule related to the transition from Class 11 to Class VI for ER wells that inject carbon dioxide for long-term storage. As Regions work with states on implementation of the Class V1 program. I encourage you to assist states in submitting primacy applications for all well classes, including Class VI. EPA recognizes the importance of geologic sequestration of anthropogenic CO2 for climate change mitigation. The UIC Class VI Rule was developed to facilitate GS and ensure protection of underground sources of drinking water from the particular risks that large scale CO2 injection for purposes of long- term storage may pose. The following are key principles related to the transition of ER wells that store CO2 from Class Ii operations to the Class VI program: 1. Geologic storage of CO2 can continue to be permitted under the UIC Class 11 program. ER wells across the U.S. are currently permitted as UIC Class ❑ wells. CO2 storage associated with Class 11 wells is a common occurrence. and CO2 can be safely stored where injected through Class II -permitted wells for the purpose of oil or gas -related recovery. 2. Use of anthropogenic CO2 in ER operations does not necessitate a Class VI permit. ER operations can continue to be permitted as Class 11 wells, regardless of the source of CO2. An owner or operator of an ER operation can switch from using a natural source to an anthropogenic source of CO2 without triggering the need for a Class V1 permit. lrtemet Atldfess+URL, • r.^, �.,.a epa g.: RecycledtRecyclable • Pr;rttel with Vege.ahle M Basea Inks on P+ncess Cht.^r,ne Fre,. Recictea Paper 9 0 3. Class VI site closure requirements are not required for Class 11 CO2 injection operations. A Class II well that has been used for injection of anthropogenic or non-anthropogenic CO2 and has been operated within its permit conditions can be closed as a Class I I well. 4. f ER operations that are focused on oil or gas production will be managed under the Class Ii program. If oil or gas recovery is no longer a significant aspect of a Class II permitted ER operation, the key factor in determining the potential need to transition a CO2 ER operation from Class 11 to Class VI is the increased risk to USDWs related to significant storage of CO2 in the reservoir, where the regulatory tools of the Class II program cannot successfully manage the risk. The most direct indicator of increased risk to USDWs is increased pressure in the injection zone related to the significant storage of CO2. Increases in pressure with the potential to impact USDWs should first be addressed using tools within the Class 11 program. Transition to Class VI should only be considered if the Class II tools are insufficient to manage the increased risk.' 5. The Class II and Class VI directors should work together to address the potential need for transition of any individual operation from a Class II to a Class VI permit. The Class II program director (in most cases a state official) will have the relevant data on pressure and volume of CO2 injected into Class I1 ER operations, which will influence any transition decision. EPA encourages the Class II director to contact the Class VI director where he/she believes the risk has changed as a result of significant storage of CO2 in the reservoir. 6. - The best implementation approach is for states to administer both the Class If and the Class VI UIC programs. EPA encourages states to apply for primacy for all well classes, including Class VI. Based on our conversations with states. in most cases, states who are approved for primacy for the Class VI program are expected to administer the program through their oil and gas program. The Office of Ground Water and Drinking Water is currently working with the U.S. Department of Energy, state associations, EPA Regions and stakeholders to finalize technical guidance focused on risk factors discussed in the Class VI Rule at 40 CFR 144.19. As we complete the final guidance, we will work to ensure that these key principles remain clear. Please contact me or have your staff contact Ron Bergman at 202-564-3823 if we can be of assistance to you oti these or other U I C program issues. ' The key regulation, -Trans iti on ing from Class 11 to Class VI;' codified at 40 CFR 144.19, states that owners or operators that are injecting carbon dioxide jor the primary purpose of long-term storage into an oil and gas reservoir must apply for and obtain a Class V 1 GS permit when there is an increased risk to US0111s compared to Class 11 operations. Prudhoe Oil Pool Major Gas Sales Presentation to the AOGCC by BPXA as an individual Prudhoe Bay Unit working interest owQj Objectives ........... General overview of the Alaska LNG project Support Rule 9 Application for amendment of CO 341 D Rule 9 for the Prudhoe Oil • Pool (POP) Technical justification for increasing the maximum allowable gas offtake from 2.7 to 4.1 BCFD Address several topics of interest for the AOGCC Support Application for AlO Modification of AIO 3A and AlO 4F Technical justification for request to inject CO2-byproduct into the POP for Enhanced Recovery and Pressure Maintenance Alaska GasTreatment Plant (GTP) • 3.3 BSCFD peak export rate • Three trains • CO2 removed for injection at PBU Liquefaction Facility • Natural gas is cooled to -260 deg F • 3 trains dehydrate, and liquefy gas to produce up to 20 million tons of LNG each year LNG Storage & Marine Terminal • LNG storage tanks • Two jetties for LNG carriers i� An integrated liquefied natural gas export project that would provide access to gas for Alaskans Beaufort Sea 40 PRUDHOE BAY Point. 3. C$LDFOOT J LIVENGOOD r a D FAIRBANKS DELTA - ",:JUNCTION K£ETNA ...nt.�;a,? ANCHORAGE OVA y Pnnce ' William Source'. AK LNG Point Thomson Transmission Line ! (PTTL) • —60 miles, 32" diameter j above ground Prudhoe Say Transmission Line (PBTL) • ~1 mile, 60" diameter above ground Gas Pipeline • 800+ mile 42" diameter below ground gas pipeline • 6-10 compressor stations • Up to 5 in -state off -take points \0 .. Sound. ,Pubject to Change s �a �o Gulf of Alaska. - - - - - Artists renditions of LNG and GTP RAW • ' - * p GRSIIHI .• ConocoPhillips E�canMobil 4TransCanada D,U;LOP1141 OOBP 0 3 by The Major Gas Sales (MGS) Reference Case (3.3 BSCFD) and the Maximum Allowable Gas (MAG) Sensitivity Case (4.1 BSCFD) both demonstrate significant additional hydrocarbon recovery from POP as a result of major gas sales Results of the MGS reference case demonstrate that POP is capable of delivering: Approximately 22 Trillion Standard Cubic Feet (TSCF) of hydrocarbon sales gas or 3.8 billion Barrels of Oil Equivalent (BOE) A gas sales plateau length of 20+ years Continued oil development and production The MAG sensitivity case produces an equivalent ultimate hydrocarbon recovery of between 17.7 and 17.8 billion BOE's An increase in Rule 9 gas offtake to an annual average of 4.1 billion standard cubic feet per day (BSCFD) is consistent with good oil field engineering practices; and positions the Prudhoe Bay Unit working interest owners to access the MGS opportunity afforded by the Alaska LNG Project, and therefore should be approved 0 Alaska LNG Project has advised gas supply to the GTP must be maintained during normal operations at a rate of —3.5 BSCFD annual average untreated gas GTP feed rate of —3.5 BSCFD rate allows for 0.4 - 0.5 BSCFD for in -State gas demand and —2.7 BSCFD to satisfy LNG facility inlet demand POP's total gas offtake would also include lease fuel, minor North Slope sales and Miscible Injectant NO used outside of the POP in Prudhoe Bay Unit satellites. 4.1 BSCFD allows POP flexibility - to supply the full GTP feed rate in the event of supply disruptions from other fields to accommodate improved facility performance and allow operations flexibility POP Offtake - MGS Reference Case (Normal Operations) -2.7 POP Offtake - MAG Sensitivity Case * Higher supply rate due to higher CO2 concentrations in POP than in other fields • Gas Offtake Produce gas from existing well stock Optimize offtake with: Targeted re -completion for gas Injector to producer conversions Two redundant offtake points at Central Gas Facility (CGF) Upgrade select equipment to ensure reliable gas delivery AKLNG Project participants are designing the GTP to return the CO2 byproduct to PBU Conceptual CO2 receipt and distribution system W11,:> WPZ WP W CO2 Control Module CGF . 0.5 mde: CO2 trom GTP APEX PL i-- 1 mdesi GC-2 GC-1 s ,u.. GC-3 • , 0� M7 E 4,,, . .;at. r°�Y �FRW . M%.." ;,y, A_. a�GALES OA9 �TEftWf✓ - �Y�'� � MOWLE aT etl Xxh`LI � $. CO2 Receipt and Injection Injection into Eileen West End (EWE) through new pipeline to existing wells at well pads W and Z EWE is the most promising option. Additional CO2 injection options outside POP will be evaluated for additional enhanced recovery opportunity Backup capability could be FS2 and the Apex injectors 0 0 The current field activity prepares for MGS; Active drilling program Rig workovers to maintain healthy well stock Continued Gas Cap Water Injection (GCWI) Active non -rig well work programs Waterflood and MI management BPXA and the other unit owners will continue to actively manage field optimization of the depletion strategy to enhance field performance into the future by The Major Gas Sales (MGS) Reference Case (3.3 BSCFD) and the Maximum Allowable Gas (MAG) Sensitivity Case (4.1 BSCFD) both demonstrate significant additional hydrocarbon recovery from POP as a result of major gas sales Results of the MGS reference case demonstrate that POP is capable of delivering: Approximately 22 Trillion Standard Cubic Feet (TSCF) of hydrocarbon sales gas or 3.8 billion Barrels of Oil Equivalent (BOE) A gas sales plateau length of 20+ years Continued oil development and production The MAG sensitivity case produces an equivalent ultimate hydrocarbon recovery of between 17.7 and 17.8 billion BOE's An increase in Rule 9 gas offtake to an annual average of 4.1 billion standard cubic • feet per day (BSCFD) is consistent with good oil field engineering practices; and positions the Prudhoe Bay Unit working interest owners access the MGS opportunity afforded by the Alaska LNG Project, and therefore should be approved Objective Requesting modification to AlO 3A and 4F for the POP 0 Explain technical benefits and implications of injection CO2 into POP Summary CO2 handling limitations impact CO2 injection development options POP is injecting a similar amount of CO2 under current field operations EWE is the most promising location for CO2 injection within the POP Additional CO2 from outside sources generates negligible changes to POP reservoir outcomes BPXA has studied and anticipates that the PBU working interest owners will continue to evaluate potential locations where CO2 injection may be economically beneficial for enhanced recovery and pressure maintenance 59 Discussion of the Full Field Model and the quality and uses Forward prediction of the Oil Reference Case Detailed discussion of comparative cases and assumptions Description of gas delivery and CO2 handling MGS Reference Case profile MAG Sensitivity Case profile Expected recovery comparison MGS start date sensitivity A10 modification CO2 studies already conducted POP and non -POP CO2 recovery estimates n 0 •• i All opinions, assessments and analyses (including forward looking or predictions of future activities) in this presentation are those of BP Exploration (Alaska) Inc., in its capacity as an individual working interest owner in the Prudhoe Bay Unit. The PBU FFM consists of three parts: (1) historical PBU operational data; (ii) a set of reasoned assumptions about future PBU activities; (items (1) and (ii) are collectively referred to as the "FFM Inputs"); and Oil) a BPXA proprietary and trade secret process consisting of software code and algorithms owned by or licensed to BPXA (the "FFM Tool"). Full Field Model runs (sometimes referred to as cases or scenarios) are generated by inputting the FFM Inputs into the FFM Tool. FFM runs are meant to be predictive of future circumstances or consequences that could occur, depending on the FFM Inputs. Because of the proprietary and trade secret processes that BPXA employs in the use of the FFM Tool, it is not possible to derive • the details of PBU operational or technical data (e.g., specific geological data) from FFM runs. BPXA uses the FFM Tool to generate FFM runs for both itself and, upon request, for the PBU working interest owners. All references in this testimony to the FFM (or to PBU FFM) are a reference to FFM Inputs plus the FFM Tool. 9 • Tom Lakosh 3301 Eureka Street, A 12 Anchorage, Alaska 99503 phone/fax (907) 563-7380 email: lakosh@gci.net August 27, 2015 Cathy P. Foerster Commission Chair Alaska Oil and Gas Conservation Commission RECEIVED AUG 272015, AQGCC 333 West 7th Avenue, Suite 100 Anchorage, Alaska 99501 Sent via email to: Jody.Colombie@alaska.gov and samantha.carlisle@alaska.gov Re: Consolidated Application for Amendment of Prudhoe Oil Pool Rule The BP/Exxon application under consideration at today's public hearing should be rejected because the BPU operator must make the application as representative of all lessees who must agree on a future plan production that must be approved by DNR. ConocoPhillips clearly objects to the requested gas off -take volume and the unit lessees must first submit the proposed gas production plan through the unit operator to DNR under unit consensus rules and not as separate competing interests to AGOCC. The proposed gas off -take amounts should similarly be rejected as they do not fairly consider new proposed uses of POP gas such as a local LNG plant in the planning stages and power production for the pipeline's Gas Treatment Plant or the pipeline compressors. The applicants should be required to document these other proposed uses in consideration of their higher value added and increased pressure drops on oil production fields. The application should be rejected as it fails to provide the public sufficient information to insure their rights to maximum production of hydrocarbons on the unit. The information must minimally show that there is sufficient reinjection of CO2 to maintain POP pressures for continuing oil production at maximum rates. Where the CO2 available from the GTP falls far short of the gas removed from POP, the commission should require CO2 capture and injection from all power production available in the area. The commission should also recommend applicants investigate advanced carbon capture and power production technology such as supercritical CO2 turbines and/or post combustion CO2 capture to insure that the lowest cost for FOR and pool pressure maintenance can be achieved. The CO2 available from S-CO2 turbines may be more effective for FOR given the higher pressures and temperatures that may be available from the turbine exhaust/heat recuperation system. Where miscible injectants such as natural gas liquids used in conjunction with hot CO2 have been shown to substantially enhance oil recovery, including recovery of under - produced heavy oils, the AGOCC should not approve this application unless and until the commission and the public can revisit the efficacy of CO2 injection with the newly available NGLs from Point Thomson. Where applicants have previously failed to disclose or employ injection of available CO2 from all sources to provide for maximum hydrocarbon production from state leases, the AGOCC must retroactively evaluate the value of lost production and assess fines to recuperate lessor's losses to date in addition to mandating maximum FOR using CO2 and miscible injectants in the future. The requested maximization of CO2 capture and injection will not only improve production on state leases in the near term, but can set industry standards that could substantially reduce the carbon footprint of the gas and power production industries as a whole. These practices may help minimize or reverse climate change in Alaska to allow for longer drilling seasons and still greater annual oil production as is the mandate for the AGGCC. The AGOCC must definitively determine whether CO2 capture and injection is a viable substitute for natural gas reinjection as it is clear that the natural gas off -take now has a viable market to produce value for the owner citizens of Alaska and new technologies for carbon capture from raw well gas and power production may drive the economics of gas off -take where CO2 injection can be used to maintain pool pressures and enhance oil migration to production wells. The AGOCC must remain vigilant in its assessment of FOR opportunities going forward and demand that lessees adopt new CO2 capture and injection technologies as they become commercially available as they may present a viable alternative for maintaining maximum hydrocarbon liquids and gas production consistent with lease provisions. The public hearing process should be continued until the application can be amended to clearly show the public owners of the hydrocarbon resources that the maximum production of all leased hydrocarbon reserves will be maintained. The applicants' confidential submissions must be minimally redacted to preserve trade secrets while allowing a fair public review of the possible gas and oil production alternatives consistent with their constitutional rights and lessees obligations to extract hydrocarbon resources at their maximum sustainable rate. We should not be forced to leave oil in the ground to produce gas for sale where CO2 can be economically captured from any, or all local sources and injected to maintain pool pressures and enhance oil recovery. Sincerely, Tom Lakosh ExxonMobil Production Company P. O. Box 196601 Anchorage, Alaska 99519-6601 907-561-5331 Telephone 906-564-3677 Facsimile August 27, 2015 Ms. Cathy P. Foerster, Chair Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, Alaska 99501 Cory E4arles Alaska Production Manager E�onMobil Production RECEIVED 27 Z015 Re: Consolidated Application for Amendment of Prudhoe Oil Pool Rule 9 and Modification of Prudhoe Bay Unit Area Injection Orders AIO 3A and AIO 4F Dear Chair Foerster: On July 17, 2015, BP Exploration (Alaska) Inc. (BPXA) filed with the Commission a Consolidated Application for Amendment of Prudhoe Oil Pool Rule 9 and Modification of Prudhoe Bay Unit Area Injection Order AIO 3A and AIO 4F (the Application) which was filed on behalf of ExxonMobil Alaska Production Inc. (ExxonMobil) as an individual working interest owner in the Prudhoe Bay Unit. ExxonMobil supports the request to increase the maximum annual average gas offtake rate for the Prudhoe Oil Pool from the current 2.7 billion standard cubic feet per day to 4.1 billion standard cubic feet per day. ExxonMobil also supports the request to modify Area Injection Orders AIO 3A and AIO 4F to authorize injection of a byproduct stream from the Alaska LNG Project Gas Treatment Plant, composed of CO2, and other effluent gases from sources within or outside the Prudhoe Bay Unit. The application seeks approvals from the Commission that will support work by the parties in the Alaska LNG Project, and allow progress to the next, front-end engineering and design, stage for that project. A maximum annual average gas offtake rate of 4.1 billion standard cubic feet per day, and modification of the Area Injection Orders to allow injection of CO2 is in accordance with good oil field engineering practice. The requested actions are appropriate for the Commission to take. ExxonMobil also supports the pre -filed testimony, witness presentations, and other supporting evidence presented by BPXA to the Commission in support of the Application. ExxonMobil respectfully asks that the Commission approve the request set forth in the application by BPXA. Sincerely, CEQ:j xc: Commissioner Daniel T. Seamount Dave P. Lachance, BPXA A Division of Exxon Mobil Corporation • s Dave Lachance Vice President Alaska Reservoir Development August 25, 2015 Via Hand Delivery Cathy P. Foerster Commission Chair Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, Alaska 99501 BP Exploration (Alaska) Inc. 900 East Benson Boulevard P.O. Box 196612 Anchorage, AK 99508 USA Direct 907 564 4855 Mobile 907 538 1719 Main 907 564 5111 dave.lachance®bp.com RECEIVED AUG 2 5 2015 Re: Docket Numbers: AIO 15-032, AIO 15-033 and CO 15-09, Prudhoe Oil Pool BPXA Written Testimony in support of Consolidated Application for Amendment of Prudhoe Oil Pool Rule 9 and Modification of Prudhoe Bay Unit Area Injection Orders AIO 3A and AIO 4F Dear Chair Foerster: BP Exploration (Alaska) Inc. submits, on behalf of itself and ExxonMobil Production Inc., as applicants in the above referenced matter, and respectfully requests that the Commission accept the enclosed written and sworn testimony. Depending upon the testimony, if any, presented by others at the public hearing, BPXA reserves the right to present additional testimony at the public hearing, or by post -hearing submission if so authorized by the Commission. Please note that the portion of sworn testimony contained in the Confidential Appendix is confidential, and BPXA requests that such information be held confidential pursuant to AS 31.05.035(d), 20 AAC 25.537(b) and AS 45.50.910 et seq., as well as Section 11.4 of the Prudhoe Bay Unit Agreement. The Confidential Appendix is enclosed in a separate envelope and marked confidential. Sincerely, Dave P. Lachance Vice President, Reservoir Development Cl • BPXA Written Testimony Application to Amend POP Rule 9 and Modify AIOs August 25, 2015 Page 2 Attachment cc via email: Ernesto Daza, BPXA (ernesto.daza@bp.com) John Dittrich, BPXA Oohn.dittrich@bp.com) George Lyle, Guess & Rudd (glyle@guessrudd.com) Chris Wyatt, BPXA (chris.wyatt@bp.com) Gilbert Wong, EMAP (gilbert.wong@exxonmobil.com) Gerry Smith, EMAP (Gerry.b.smith@exxonmobil.com) Steve Luna, EMAP (charles.s.luna@exxonmobil.com) Brian Gross, EMAP O.brian.gross@exxonmobil.com) Jon Schultz, CPAI(Jon.Schultz@conocophillips.com) Eric Reinbold, CPAI (Eric.W.Reinbold@conocophillips.com) John Evans, CPAI (John,R.Evans@conocophillips.com) Phil Ayer, CUSA (pmayer@chevron.com) Angie Bible, CUSA (abible@chevron.com) STATE OF ALASKA Alaska Oil and Gas Conservation Commission Docket Numbers: AIO 15-032, AIO 15-033 and CO 15-09 Application for Amendment of Pool Rule 9 and Modification of AlOs Prudhoe Oil Pool, Prudhoe Bay Field Written Submittal of BP Exploration (Alaska), Inc. Submitted August 25, 2015 Commissioners: ECEIVe A 06 25 2015 This submission and the accompanying appendices are a component of the application by BP (Exploration) Alaska, Inc. ("BPXA") as an individual working interest owner ("WIO") in the Prudhoe Bay Unit ("PBLP') and not as PBU operator, on behalf of itself and PBU WIO ExxonMobil Alaska Production Inc. ("EMAP"), to the Alaska Oil and Gas Conservation Commission ("AOGCC" or "Commission"), for an amendment of Prudhoe Oil Pool ("POP") Rule 9 of Conservation Order ("CO") 341 D and modification of PBU Area Injection Orders ("AIOs") 3A and 4F. INTRODUCTION The application requests that the Commission amend the maximum annual average gas offtake rate for the POP in CO 341 D Rule 9, from 2.7 billion standard cubic feet per day ("bscf/d") to 4.1 bscf/d. As demonstrated in the application and this testimony, a maximum annual average gas offtake rate of 4.1 bscf/d is in accordance with good oil field engineering practices and should be approved by the Commission. The application also requests that the Commission modify AIOs 3A and 4F to authorize the injection of CO2 for enhanced hydrocarbon recovery and reservoir pressure maintenance, from sources both within and outside the PBU. As demonstrated in the application and this testimony, the requested modification of AIOs 3A and 4F is in accordance with good oil field engineering practices and should be approved by the Commission. BPXA and EMAP are filing this application with the Commission so each PBU WIO has the ability to access the opportunity presented by the Alaska LNG Project (the "AK LNG Project") to progress major gas sales of Prudhoe Bay Unit natural gas ("PBMGS"). As the Commission knows, affiliates of the three largest PBU WIOs — BPXA, EMAP and ConocoPhillips Alaska, Inc. ("CPAF') are all working with the State of Alaska to develop the AK LNG Project. BPXA will provide a witness at the public hearing to testify further on the AK LNG Project from BPXA's perspective. Written Submittal of BP Exploration (Alaska) Inc. Application for Amendment of POP CO 341D Rule 9 and AIOs 3A and 4F This application and the requested approvals are necessary at this time for several reasons: (i) The requested approvals are needed so BPXA, EMAP and the other PBU WIOs have the ability to access the opportunity presented by the AK LNG Project for progressing PBMGS. The AK LNG Project participants have informed the PBU WIOs that the approvals requested in this application are necessary at this time to support progression of the project beyond pre -FEED engineering stage of development. The requested approvals are just one of many regulatory and facility planning activities on which the PBU WIOs have been diligently working to prepare for PBMGS. (ii) The requested approvals support individual PBU WIO and State of Alaska internal preparations for major gas sales, including preparations for marketing each party's respective share of PBU gas. BPXA and EMAP collectively own 63 percent of the working interests in the oil and gas leases that comprise the PBU. The ability of each PBU WIO and the State of Alaska (assuming an election by the State to take gas royalty in kind) to market its gas is fundamental to the success of the PBMGS opportunity presented by the AK LNG Project. LNG buyers will demand certainty of gas supplies to the AK LNG Project system, and without the certainty provided by the requested approvals, BPXA and EMAP respective LNG marketing efforts to monetize their shares of PBU gas production would be impeded. The inability of each company to progress its individual gas marketing efforts would hinder progress of the AK LNG Project. BPXA is submitting this sworn testimony in the form of this written narrative and associated exhibits. This testimony is provided by BPXA as an individual PBU WIO. BPXA has consulted and coordinated with PBU WIO EMAP in the preparation of this testimony, and has their support in the application. The assessments contained in this testimony have been discussed with the other PBU WIOs, CPAI and Chevron U.S.A. Inc. ("CUSA"). Section I of this submission identifies the witness who is submitting this written testimony on behalf of BPXA. Section II provides a brief summary of this testimony. Section III contains the substance of the testimony in support of an amendment to CO 341D Rule 9. Section IV contains the substance of testimony in support of modification of AIOs 3A and 4F. Section V, which is being separately submitted to the Commission as a Confidential Appendix to preserve confidentiality, contains confidential information and figures referenced in this testimony that BPXA requests be held confidential by the Commission pursuant to AS 31.05.035(d), 20 AAC 25.537(b) and AS 45.50.910 et seq. 2 LJ • Written Submittal of *BP Exploration (Alaska) Inc. Application for Amendment oj'POP CO 341 D Rule 9 and AlO,s 3A and 4F SECTION I BPXA WITNESS This narrative submission is the testimony of Mr. Bruce Laughlin. His business address is 900 E. Benson Blvd., Anchorage, Alaska 99508. Mr. Laughlin received a Bachelor of Science Degree from Pennsylvania State University and a Masters of Science degree from Texas A&M University. Mr. Laughlin's current title at BPXA is Reservoir Management Team Leader. In his present position, Mr. Laughlin supervises BPXA and contract staff focused on delivering long term oil and gas production opportunities for BPXA's PBU assets, including the POP. His team comprises reservoir engineers, geologists and geophysicists. Mr. Laughlin has the training, experience and knowledge relevant and necessary to provide the opinions included in this testimony; in particular as to analytical and dynamic simulation of field depletion mechanisms. Mr. Laughlin has previously testified before the AOGCC as an expert in January 2014 in relation to the "Inquiry Into Gas Liquids Disposition." BPXA respectfully requests that the Commission qualify Mr. Laughlin as an expert in these proceedings in accordance with 20 AAC 25.540(c)(5). Mr. Laughlin will be present, and made available to the Commissioners for questions, at the public hearing on this application to amend POP Rule 9. As noted above, BPXA will provide at least one non -expert witness at the public hearing to testify on the AK LNG Project from BPXA's perspective. That testimony is not included in this filing. SECTION II SUMMARY OF SUBMITTAL A. The Requested Amendment Will Support Progress On The AK LNG Project BPXA and EMAP consider this request to amend the gas offtake rate in Rule 9 of CO 341 D as a significant step for PBU development. The PBU WIOs and the AOGCC have long contemplated a major gas sale project. The participants in the AK LNG Project (which include the State of Alaska and affiliates of BPXA, EMAP and CPAI) have publicly stated that they are progressing plans for an integrated LNG project with a scheduled start-up in 2025. The requested amendment of CO 341 D Rule 9 to increase the maximum annual average gas offtake rate from 2.7 bscf/d to 4.1 bscf/d facilitates that opportunity by providing the flexibility to supply both expected normal and full sustained gas feed rates to the AK LNG Project Gas Treatment Plant ("GTP") from the POP. The AK LNG Project participants have informed the PBU WIOs that the GTP is being designed for sustained receipt of feed gas at the GTP at an annual average rate of 3.5 bscf/d. (The filings by the AK LNG Project with FERC state that the GTP will have an initial gas treating capacity of up to 4.3 bscf/d of feed gas.) BPXA expects that under 3 • • Written Submittal of BP Exploration (Alaska) Inc. Application for Amendment of POP CO 341 D Rule 9 and AIOs 3A and 4F normal operating circumstances, after a one-year operations ramp -up period beginning in 2025, approximately three -fourths of the gas delivered to the GTP is anticipated to be from the POP (2.7 bscf/d) and one-fourth is anticipated to be from Point Thomson or other sources (0.8 bscf/d). (Please refer to AK LNG project draft Resource Reports filed with FERC, cited in the application). To support this level of gas delivery to the GTP from the POP, a minimum annual average gas offtake rate of 3.3 bscf/d from the POP would be required (2.7 bscf/d to the GTP and additional gas offtake of approximately 0.6 bscf/d annual average used for fuel, field operations and minor local gas sales). However, because the GTP is being designed for sustained receipt of feed gas at an average annual rate of 3.5 bscf/d, if the supply of gas to the GTP from the Point Thomson Unit or other sources does not occur as expected or is interrupted, up to 100 percent of the gas supply to the GTP from the POP would be required to maintain uninterrupted gas deliveries to the AK LNG Project. To allow the flexibility for the POP to be the source for up to 100 percent of the feed gas supplied to the GTP in those circumstances, and to avoid disruptions to GTP operations and resulting disruptions to PBU operations that could result from interruptions in a sustained stable supply of gas to the GTP, BPXA and EMAP are requesting AOGCC authorization for a maximum annual average gas off -take of 4.1 bscf/d (3.6 bscf/d to the inlet of the GTP plus 0.5 bscf/d for fuel, field operations and minor local gas sales). Note that in the 100 percent POP case, the feed gas inlet to the GTP must be slightly greater than 3.5 bscf/d to yield an equivalent hydrocarbon gas delivery to the downstream gas offtake points and the LNG liquefaction facility because the CO2 percentage of the POP feed gas stream is greater than in the Point Thomson feed gas stream. The POP fuel gas requirements in the 100 percent POP case drops slightly from 0.6 bscf/d to 0.5 bscf/d since less POP gas is re -injected into the Prudhoe reservoir. A 4.1 bscf/d offtake rate for the POP also would accommodate improved facility performance and allow operational flexibility. The GTP is being designed to receive, treat and ship gas to the liquefaction facility, and to return CO2 by-product to the PBU for injection. Similar to the requested amendment of Rule 9 addressed above, the requested modifications to the AIOs are being requested at this time to support the joint efforts of the State of Alaska and the other participants in the AK LNG Project to progress the project to the front-end engineering and design (FEED) development stage. As more specifically addressed below, modifications of the AIOs are based upon the AK LNG Project design plan for injection of the GTP CO2 by- product into the POP. B. There Is A High Degree Of Confidence In The Current Full Field Model Results The PBU Full Field Model ("FFM") consists of three parts: (i) historical PBU operational data; (ii) a set of reasoned assumptions about future PBU activities; (items (i) and (ii) are collectively referred to as the "FFM Inputs"); and (iii) a BPXA proprietary and trade secret process consisting of software code and algorithms owned by or licensed to BPXA (the "FFM Tool"). Full Field Model runs (sometimes referred to as model scenarios) are generated by inputting the FFM Inputs into the FFM Tool ("FFM Runs"). 4 • Written ,Submittal of BP Exploration (Alaska) Inc. Application for Amendment of POP CO 341 D Rule 9 and AIOs 3A and 4F FFM Runs are meant to be predictive of future circumstances or consequences that could occur, depending on the FFM Inputs. Because of the proprietary and trade secret processes that BPXA employs in the use of the FFM Tool, it is not possible to derive the details of PBU operational or technical data (e.g., specific geological data) from FFM Runs. BPXA uses the FFM Tool to generate FFM Runs for both itself and, upon request, for the PBU WIOs. All references in this submission to the FFM are a reference to FFM Inputs plus the FFM Tool. References to and discussions of FFM modeling, scenarios, runs and similar statements are references to FFM Runs. The AOGCC and the PBU WIOs have evaluated and reviewed the potential effects of a PBMGS project on oil production and hydrocarbon recovery from the POP at various stages of field development, most recently in 20071. The PBU WIOs informed and discussed with AOGCC staff, in a series of workshops held earlier this year, upgrades that BPXA has made to the FFM since 2006. Over the past several years the underlying geologic and dynamic data have been extensively reviewed and agreed by the WiOs with the State of Alaska to determine the historic and predictive behavior. The upgrades that have been made by BPXA to the FFM include: increased model resolution; improved and updated well breakage and repair assumptions and data; segregation of drilling by type and area to align assumptions and predictions with potential drilling schedules; use of an improved fuel gas usage algorithm; and improved and updated satellite field flow assumptions and data. Moreover, with substantial updated production and flow history, the FFM history match has been updated to 2014 and improved to include gas cap water injection ("GCWI") impacts on reservoir pressure projections. The updated and recalibrated FFM provides a higher degree of confidence in its predictive capabilities. C. The PBMGS Gas Reference Case The FFM was used to generate an FFM Run of the estimated increase in ultimate hydrocarbon recovery from the POP for a PBMGS case beginning in 2025 and assumed to end in 2055, with a total annual average gas offtake rate of 3.3 bscf/d including all uses, (the "gas reference case"), as well as the estimated ultimate hydrocarbon recovery from the POP. BPXA's assessment of the gas reference case is that hydrocarbon recovery is increased by approximately 3.8 billion barrels of oil equivalent ("BOU) or 22 trillion standard cubic feet of gas ("tsiq ). Combined with oil, condensate and NGLs production, BPXA's ' The Commission has long understood that the gas off -take rate in Rule 9 of CO 341 D would have to be revised for major gas sales. See the July 10, 2007 Report Of The Commission Inquiry Into Amending Rule 9 and December 5, 2005 Report On Commission Inquiry Into Potential Revision of Gas Offtake Limit. Written Submittal of BP Exploration (Alaska) Inc. Application for Amendment of POP CO 341D Rule 9 and AIOs 3A and 4F assessment is that total hydrocarbon recovery from the POP under the gas reference case is approximately 17.7 billion BOE; a net increase of 3.6 billion BOE from the current oil reference case. The details of BPXA's assessment of the gas reference case are discussed in Section V (the Confidential Appendix). D. The PBMGS Full GTP Inlet Supply Case (The Application Request) The FFM was also used to generate an FFM Run evaluating a scenario where the requested total annual average gas offtake rate from the POP of 4.1 bscf/d was applied for an assumed AK LNG Project life of 30 years (i.e., assuming no gas delivery to the GTP from other fields) (the "full GTP inlet supply case"). This case has been compared to the gas reference case. BPXA's assessment of the full GTP inlet supply case is that slightly more BOEs are recovered than in the gas reference case (17.8 billion instead of 17.7 billion BOEs) due to higher gas recovery that offsets additional impacts on oil production. The details of BPXA's assessment of the full GTP inlet supply case are discussed in Section V (the Confidential Appendix). E. Reference Case Sensitivities The FFM also was used to test the sensitivity of reference case predicted oil and gas recovery to a robust set of alternative assumptions and development scenarios. This type of analysis is often undertaken by BPXA, using its FFM Tool, in conjunction with BPXA and the other PBU WIOs development of specific development plans. Apart from in -place volumes, the most sensitive parameters identified are CO2 injection location (for enhanced hydrocarbon and pressure maintenance), and well breakage. BPXA's assessment of the results of these analyses is that the sensitivity of liquid and total hydrocarbon recovery is negligible (less than 1 percent). The details of BPXA's analysis are discussed in Section V (the Confidential Appendix) F. CO2 Injection into the POP The AK LNG Project participants have indicated that the GTP is being designed to deliver 350 to 450 mmscf/d of CO2 byproduct to PBU for injection. Greater than 90 percent of the total CO2 volume will originate from gas delivered to the GTP from PBU. The additional hydrocarbon recovery associated with PBMGS is 3.8 billion BOE. This additional hydrocarbon recovery is dependent upon CO2 being received at PBU from the GTP. Reservoir studies have been conducted to look at several possible injection locations for enhanced hydrocarbon recovery and pressure maintenance, and initially the Eileen West End ("EWE") area has been identified as the most promising, but the specific location in the POP has not been determined. BPXA and EMAP will continue to work with the PBU WIOs, the Commission and the Alaska Department of Natural Resources to determine one or more locations for injection of CO2 for enhanced Z • Written Submittal of BP Exploration (Alaska) Inc. Application for Amendment of POP CO 341 D Rule 9 and A10s 3A and 4F hydrocarbon recovery and pressure maintenance. G. Conclusion The POP is the most robust resource on the North Slope, with more than 35 years of production history and operations. BPXA and EMAP are seeking a maximum annual average gas off -take rate of 4.1 bscf%d to allow for the full inlet gas delivery to the GTP and related LNG facilities to be supplied from the POP. This off -take rate will provide BPXA and EMAP, the other PBU WIOs (CPAI and CUSA) and the State of Alaska with flexibility, and allow use of POP gas to cover any gas supply disruptions to the GTP that may occur from other gas supply fields. BPXA and EMAP are also seeking a modification of AIOs 3A and 4F to authorize the injection of CO2 into the POP for enhanced hydrocarbon recovery and reservoir pressure maintenance purposes, from sources both within and outside the PBU. BPXA is confident in the results of the updated and enhanced FFM. BPXA's assessment of the studies and the FFM Runs that have been performed using the FFM is that: (i) total BOE hydrocarbon recovery for the POP is substantially increased with a PBMGS project by approximately 3.8 billion BOE or 22 tscf of gas. Combined with oil, condensate and NGLs production, total hydrocarbon recovery from the POP under the gas reference case is approximately 17.7 billion BOE, a net increase of 3.6 billion BOE from the current oil reference case; (ii) the total BOE hydrocarbon recovery from the POP at the requested full GTP inlet supply case off -take rate (17.8 billion BOE) is comparable to the gas reference case off -take rate (17.7 billion BOE), a difference of less than 1 percent; (iii) ultimate hydrocarbon recovery is relatively insensitive to alternative assumptions and scenarios (less than 1 percent); and (iv) EWE is initially the most promising location for injecting CO2 for enhanced hydrocarbon recovery and pressure maintenance. SECTION III AMENDMENT OF CO 341D RULE 9 TO INCREASE THE MAXIMUM GAS OFF -TAKE TO 4.1 bscf/d IS PRUDENT, APPROPRIATE AND NECESSARY TO PROGRESS THE AK LNG PROJECT A. POP Rule 9 Gas Off -Take Rate CO 341D Rule 9 limits the maximum annual average gas offtake from the POP to 2.7 bscf/d. Currently, approximately 0.6 bscUd from the POP is used for fuel, field operations and minor local gas sales. This level of other gas usage is anticipated to 7 0 • Written Submittal of BP Exploration (Alaska) Inc. Application for Amendment of POP CO 341 D Rule 9 and AI0s 3A and 4F remain stable. Accordingly, under Rule 9, an annual average gas off -take of approximately 2.1 bscf/d would be available for gas pipeline delivery for major gas sales. This offtake level is not adequate to allow sufficient gas delivery from the POP to the AK LNG GTP for PBMGS. (Please note that unless otherwise indicated, references to AK LNG public statements in this submission are to the draft Resource Reports filed with FERC as referenced in the application.) 1. AK LNG Project The participants in the AK LNG Project, including the affiliates of both BPXA and EMAP and the State of Alaska, have informed the PBU W10s that the design of the AK LNG facilities is premised on a sustained annual average gas supply rate of 3.5 bscf/d to the GTP. (AK LNG Project participants have publicly stated that the GTP will have an initial gas treating capacity of up to 4.3 bscf/d of feed gas.) The AK LNG Project participants have also publicly stated that the GTP is being designed to receive, treat, and ship gas to the Liquefaction Plant, and to return for reinjection into the POP the by- product primarily consisting of CO2. 2. POP Gas Supply to AK LNG The AK LNG Project participants have publicly stated that under normal operating circumstances, they anticipate that —3/4 of the feed gas to the GTP (2.7 bscf/d) will be from the POP, and the remaining 1/4 of the feed gas (0.8 bscf/d) will be from Point Thomson or other sources. BPXA and EMAP together will provide approximately 69 percent of the total hydrocarbon resources from these fields to the AK LNG Project. BPXA and EMAP's assessment is that the POP will be able to deliver gas to the GTP for 30 years under this scenario. 3. Amendment of Rule 9 CO 341D Rule 9 limits the maximum annual average gas off -take from the POP to 2.7 bscf/d. Currently, approximately 0.6 bscf/d of gas from the POP is used for fuel, field operations and minor local gas sales. This level of other gas usage is anticipated to remain stable in the future. Therefore, the current 2.7 bscf/d off -take limit is insufficient to meet the gas delivery inlet capacity of the AK LNG GTP under even normal operating conditions, which assume delivery of 0.8 bscf/d from Point Thomson or other sources (current POP offtake limit of 2.7 bscf/d minus 0.6 bscf/d gas for fuel, field operations and minor local sales only allows 2.1 bscf/d to the GTP, which combined with 0.8 bscf/d from Point Thomson or other sources does not meet AK LNG Project design for a sustained annual average gas supply rate of 3.5 bscf/d of feed gas to the GTP). Under the circumstance where gas delivery to the GTP from Point Thomson and other sources does not occur as expected or suffers a supply interruption, a total gas offtake of 4.1 bscf/d would be required from the POP (3.6 bscf/d to the GTP + 0.5 bscf/d for fuel, field operations and minor local sales) to allow the full supply of inlet gas supply to the 8 • • Written Submittal of BP Exploration (Alaska) Inc. Application for Amendment ojPDP CO 341D Rule 9 and AIOs 3A and 4F GTP. B. Full Field Model And Data Improvements BPXA has made many updates to the FFM since the AOGCC last considered analyses of a PBMGS in 2007. The following is a high level summary of those updates. Section V of the Confidential Appendix contains a comprehensive and more detailed discussion of these confidential FFM improvements. BPXA has continuously updated the FFM since its original development. Over many years of historical production and development updates, the model continues to narrow the assumptions and improvement needs. The physical constraints associated with facility limits, pipeline networks, drilling and well work activity all contribute to better understanding of the shape of the model and the property distribution. With improved computer processors, refinements to the grid resolution have given better understanding to the flow characteristics between wells. The FFM has been used internally by BPXA to inform its analysis, from a PBU WIO perspective, of drilling projects, the gas cap water injection project, surface facility debottlenecking projects, as well as previous PBMGS analyses. BPXA has also provided FFM Runs to the PBU WIOs to inform their analysis of similar projects. As a result of these FFM refinements and updated data, BPXA's assessment of the FFM is that the current history match predicts each fluid phase within 1 percent of actual field data. Therefore, BPXA considers the current FFM to be highly reliable. C. FFM Assumptions And Analyses In order to assess hydrocarbon recovery for a PBMGS development scenario compared to an oil production scenario, a reference case set of assumptions was developed and incorporated in the FFM to reflect both sound engineering principles and a development program that recognizes economic considerations. The following is a high level summary of those assumptions. Section V of the Confidential Appendix contains a comprehensive discussion and details of these assumptions. In order to perform a valid analysis of the benefits for PBMGS, the model requires assumptions about both oil -focused operations and a PBMGS. In this analysis, the following assumptions were made for the oil reference case and the gas reference case. 1. The Oil Reference Case The oil reference case assumed the following activities will continue. Among these assumptions are activities that have been implemented with the view toward PBMGS. • Active development drilling program • Rig workovers to maintain healthy well stock Z LJ n L� Written Submittal of BP Exploration (Alaska) Inc. Application fir Amendment of POP CO 341 D Rule 9 and AIOs 3A and 4F • Continued Gas Cap Water Injection • Normal Turnaround activities for facility maintenance 2. The PBMGS Gas Reference Case The gas reference case includes many of the same activities assumed for the oil reference case. The reason for these assumption sets to be the same is to give a more valid consideration of the benefits on a like -for -like comparison. There are certain additions to the assumptions that must be incorporated to manage a gas analysis. The following are the assumptions associated with the gas reference case. • Same development drilling program as the oil reference case • January 2025 gas sales startup date with a 1 year ramp to full delivery • Annual average gas supply to the GTP —2.7 bscf/d • Normal annual turnaround maintenance events • GTP by-product COZ injected into the Eileen West End of the POP • Conversion of the apex gas injectors to gas producers late in project life • Rig workovers to keep healthy well stock until the end of the project • Perforations to add gas production to the project • 30 year total project life As noted earlier, the gas reference case shows PBMGS will increase ultimate hydrocarbon recovery from the POP by approximately 22 tscf or 3.8 BOE. 3. The PBMGS Full GTP Inlet Supply Case Comparison The full GTP inlet supply case incorporates one change. The annual average gas supply to the GTP is increased from —2.7 bscf/d to a rate of 3.6 bscf/d. (3.6 bscf/d is used because the gross inlet volume of gas will be slightly higher in this modeled case due to the higher CO2 content in POP gas compared to the blended gas stream expected from other gas fields.) As noted earlier, the full GTP inlet supply case recovers slightly more BOEs than the gas reference case (17.8 instead of 17.7 billion BOEs) due to higher gas recovery that offsets additional impacts on oil production. 4. Impacts of Sensitivities The impacts of the sensitivities on gas sales, oil recovery and BOE recovery were evaluated. Apart from in -place volumes, the most sensitive parameters identified are COz injection location (for enhanced hydrocarbon and pressure maintenance), and well breakage. All of the other sensitivities have less than a 5 percent impact on total BOE recovery, with most sensitivities having a negligible impact (less than 1 percent impact). The impacts on gas production from the sensitivities tested have a greater effect on ultimate BOE recovery than the nominal positive impacts to oil recovery. These results 10 • Written Submittal of BP Exploration (Alaska) Inc. Application for Amendment of POP CO 341 D Rule 9 and AIOs 3A and 4F are discussed in Section V (the Confidential Appendix). SECTION IV MODIFICATION OF AIOS 3A AND 4F INJECTION OF CO2 FROM SOURCES WITHIN OR OUTSIDE OF PBU FOR ENHANCED HYDROCARBON RECOVERY AND PRESSURE MAINTENANCE A. AK LNG CO2 Byproduct Return The AK LNG Project participants (including affiliates of BPXA, EMAP and CPAI, and the State of Alaska) have informed BPXA that gas shipped through the AK LNG system pipelines to the liquefaction facility will need to be treated in the GTP to a CO2 specification of 50 ppm or less. AK LNG Project participants have publicly stated that the GTP is being designed on the basis that the byproduct from gas treated at the GTP, which BPXA expects will be dry and approximately greater than 99 percent CO2, will be transported to the PBU for further handling. See Figure 1 below for a conceptual depiction of a CO2 distribution system. Conceptual CO2 receipt and distribution system B. Amendment of AIOs CO2 Control Mod0e 0 CGF CO2 from GTP APEY PL GC-2 GC-3 Figure 1 CO2 Distribution System The AK LNG Project participants inform us that the GTP may deliver an annual average of 350 to 450 mmscf/d of CO2 byproduct to PBU for injection. Greater than 90 percent of the total CO2 volume will originate from gas delivered from PBU. A10s 3A and 4F, however, currently only permit injection of gas (which includes the CO2 entrained in the gas) that is sourced from PBU gas processing facilities. The additional hydrocarbon recovery associated with PBMGS is 3.8 billion BOE. This 9 • Written Submittal of BP Exploration (Alaska) Inc. Application for Amendment of POP CO 341D Rule 9 and AIOs 3A and 4F additional hydrocarbon recovery is dependent upon the ability of PBU to receive CO2 from the GTP. Although the specific location for injection is still being evaluated, analysis of CO2 injection in POP shows there will be enhanced hydrocarbon recovery and pressure maintenance benefits. BPXA is therefore seeking a modification of AIOs 3A and 4F to authorize the injection Of CO2 into the POP for enhanced hydrocarbon recovery and reservoir pressure maintenance purposes, from sources both within and outside the PBU. Similar to the requested amendment of Rule 9 addressed above, the requested modifications to the AIOs are requested at this time to support the joint efforts of the State of Alaska and the other AK LNG Project participants to progress the AK LNG Project to the front-end engineering and design (FEED) development stage. Amendment of the AIOs at this time will also allow the PBU WIOs to pursue related PBU activities supporting this injection of GTP CO2, C. Assessment of CO2 Injection Various locations within the POP were evaluated to determine the hydrocarbon recovery associated with injection of CO2. These areas included the Gas Cap, Flow Station 2 area and Eileen West End. In past evaluations of PBMGS, the gas cap was considered as an option. Lower CO2 handling limits into the GTP and the rapid increase in CO2 from the POP that would occur demonstrates that this location is a less viable option given the impact on hydrocarbon recovery. The Flow Station 2 area was also evaluated and this area remains a potential location due to the availability of the miscible injection distribution system. Compared to the more promising Eileen West End location, the FS2 area was also determined to have higher returned CO2 concentrations and lower hydrocarbon recovery. Eileen West End provided the highest benefit from a hydrocarbon recovery perspective when compared to the other injection locations. Due to the large volume of CO2 that is currently injected into the POP through day to day operations as part of the overall gas reinjection stream (about 800 mscf/d), the volume of CO2 injected during PBMGS is essentially the same. The benefits of this injection are associated with increased pressure to the reservoir, thus improving oil recovery throughout the field and recovery of Miscible Injectant ("MT') currently trapped in the EWE area of the field. This MI can be utilized for additional FOR benefits. 12 0 • Written Submittal of BP Exploration (Alaska) Inc. Application for Amendment of POP CO 341D Rule 9 and AIOs 3A and 9F OATH BPXA requests that the Commission authorize and recognize this submission as pre -filed written public testimony in support of its application. Based upon my expertise, knowledge, information and belief formed after reasonable inquiry, I certify and swear that the statements and information in Sections II through V of this submittal, including in the Confidential Appendix to this submittal, are true and accurate. Bruce Laughlin BP Exploration (Alaska), Inc. 13 R F_ G AUG 1s2015 AOGGG Conoco -Phillips Jon Schultz Manager Greater Prudhoe Area Alaska P.O. Box 100360 Anchorage, AK 99510-0360 Phone: 907-265-1315 August 19, 2015 Catherine P. Foerster, Commission Chair Alaska Oil and Gas Conservation Commission 333 W. 7th Ave #100 Anchorage, Alaska, 99501-3539 RE: Docket Numbers: AIO 15-032, AIO 15-033, CO 15-09 — Prudhoe Bay Unit ConocoPhillips Comments to BP Exploration (Alaska) Inc. (BPXA) and ExxonMobil Alaska Production, Inc. (EMAP) July 17, 2015 Consolidated Application for Amendment of Prudhoe Oil Pool Rule 9 and Modification of Prudhoe Bay Unit Area Injection Orders AIO 3A and AIO 4F Dear Commissioner Foerster, ConocoPhillips Alaska, Inc. (CPAI) submits, on behalf of itself and Chevron U.S.A. Inc. (CUSA), both Prudhoe Bay Unit (PBU) working interest owners, the following comments to the above -referenced application (BPXA and EMAP Consolidation Application), and respectfully requests that the Alaska Oil and Gas Conservation Commission (Commission): (i) Approve BPXA's and EMAP's request to increase the Rule 9 maximum allowable gas offtake rate, but to a maximum offtake rate of 3.6 billion standard cubic feet per day (bscf/d) annual average, rather than the 4.1 bscf/d annual average requested by BPXA and EMAP; (ii) Approve BPXA's and EMAP's request to modify relevant area injection orders to permit injection of carbon dioxide (CO2) and other gas treatment byproducts for purposes of enhanced oil recovery (EOR) and pressure maintenance; and, in addition to BPXA's and EMAP's request, also approve injection of CO2 and other gas treatment byproducts for disposal in appropriate intervals, in the event that FOR or pressure maintenance opportunities that result in increased POP hydrocarbon recovery are not identified; and (III) Include in Rule 9 and relevant area injection orders provisions, as necessary, to permit administrative approval of future modifications. CPAI Comments to BPXA an• AP Consolidated Application to Amend. 9 and Modify AIOs Page 2 of 6 August 19, 2015 A. CPAI Supports BPXA's and EMAP's Request to Increase the Rule 9 Maximum Allowable Offtake Rate, But Requests the Commission Approve a Rate — 3.6 bscf/d — Commensurate With the AKLNG Design Basis and Reasonably Expected Gas Volume Needs As the Commission is aware, CPAI has been working closely with the other PBU working interest owners (WIOs), to support a request to the Commission to increase the current 2.7 bscf/d annual average Rule 9 maximum gas offtake rate for the Prudhoe Oil Pool (POP), as an important part of making possible potential major gas sales from PBU through the Alaska LNG Project (AKLNG). Affiliates of BPXA, EMAP and CPAI, together with agents of the State of Alaska, have advanced AKLNG pre -FEED engineering, and AKLNG is expected to enter FEED' next year. Increasing the Rule 9 maximum annual average offtake rate will provide additional certainty to support an AKLNG FEED decision, as well as subsequent decisions to construct and operate AKLNG. In this regard, CPAI always has supported, and continues to support, requesting that the Commission increase the Rule 9 maximum allowable POP offtake rate. As the Commission likely is aware, until June, CPAI supported considering an increase to the maximum annual average POP offtake to 4.1 bscf/d, where that daily rate would be available if the PBU WIOs determined to supply additional gas to the AKLNG gas treatment plant (GTP), in the event of a temporary non -POP gas supply disruption. As explained below, after further consideration, CPAI has determined that 3.6 bscf/d annual average POP offtake is more than sufficient to accommodate full AKLNG GTP supply from the POP for the full duration of any reasonably expected non -POP gas supply disruption. Accordingly, CPAI requests that the Commission approve 3.6 bscf/d as the Rule 9 maximum allowable annual average POP offtake rate. 1. Governor Walker's June 8 Letter Defined Reasonable Expectations For the Duration of Non -POP Gas Supply Disruption On June 8, Governor Walker sent a letter to BPXA, EMAP and CPAI. The Governor shared the June 8 letter with the Alaska Legislature on June 15.2 The Governor's letter provided helpful clarity regarding necessary gas supply terms to support AKLNG, including the duration of potential non -POP gas supply disruption. Appendix A of the Governor's June 8 letter lays out a preferred commercial structure comprised of two joint ventures: one receiving PBU gas and one receiving PTU gas (PTU being the non -POP gas supply source to AKLNG), and treating, transporting and liquefying the gas through AKLNG capacity reserved for each source of supply. Appendix A notes that the Prudhoe Bay joint venture and the Point Thomson joint venture may enter into certain mutual aid arrangements: one month of mutual aid per year, in case of downtime caused by operational issues; and two months of mutual aid on a one-time basis, in case of severe disruption. This proposal from the Governor defined reasonable expectations regarding maximum durations over which 100% POP offtake rate could be required: at most, one month on an annual basis; at most, two additional months, in case of once -in -field -life emergency. These maximum durations are conservative, safe assumptions, well in excess of typical industry or North Slope downtimes. So far as CPAI is aware, no major North Slope field ever has experienced an operational issue that caused the field to be entirely offline for three months. The longest major shutdown of which ' Front -End Engineering and Design (FEED) is the final engineering phase before AKLNG sanction, or final investment decision (FID). The AKLNG parties are expected to determine whether to enter FEED in 2016, and to determine whether to approve FID in 2019. 2 The Governor's June 15 and June 8 letters are Attachment 1 to these comments. CPAI Comments to BPXA an*MAP Consolidated Application to Amend le 9 and Modify AIOs Page 3 of 6 August 19, 2015 CPAI is aware occurred in October 2006 when approximately 30% of PBU production was shut in for 82 days, due to transit line issues. 2. 3.6 bscf/d Is the Appropriate Maximum POP Offtake Rate At This Time Taking into account the AKLNG design basis, premised POP and non -POP AKLNG supply, reasonable expectations regarding PTU downtime, minimization of PBU liquid impacts, and the basic premise that 4.1 bscf/d could be used as an excursion rate, available if the PBU WIOs determined to supply additional gas to the AKLNG GTP, in case of a temporary non -POP gas supply disruption, 3.6 bscf/d is the appropriate maximum annual average POP offtake rate at this time. 3.6 bscf/d annual average maximum offtake provides more than sufficient capacity, even in case of a worst - case 3 month period of 100% PTU downtime in a single year. In fact, a maximum annual average offtake of 3.6 bscf/d would allow for the PBU WIOs to supply 100% of AKLNG GTP inlet volume for approximately 4 months in one year .3 3. 3.6 bscf/d Annual Average Offtake Is More Than Sufficient for AKLNG AKLNG FEED is estimated to cost approximately $2 billion. Accordingly, the decision to enter FEED will require certainty on many issues to support such a large commitment. The current shared goal of BPXA, EMAP and CPAI is to secure an increase to the current Rule 9 maximum allowable offtake rate from the POP, to provide certainty regarding available POP gas, which would be a key factor supporting a 2016 AKLNG FEED decision, as well as subsequent decisions to build and operate AKLNG. A 3.6 bscf/d annual average rate would provide more than sufficient certainty regarding POP gas availability, based on reasonable expectations of maximum PTU downtime in any year. 4. The Commission Should Defer Consideration of an Offtake Rate Higher Than the 3.6 bscf/d Annual Average Rate Required for AKLNG The 3.6 bscf/d annual average POP offtake rate will be more than sufficient to supply AKLNG. However, if AKLNG does not proceed, and if another gas commercialization project is later developed, with different gas sources, or a different basis of design, then it would be appropriate for the Commission to reevaluate POP offtake in light of that new technical information, and then -current POP reservoir and other information. 5. PTU Is Premised to Provide 25% of the Gas to AKLNG; However, If PTU Start Up Is Materially Delayed or PTU Resources Are Materially Less Than Predicted, There Will Be More Than Sufficient Time to Amend the POP Offtake Rate, If Appropriate BPXA's and EMAP's application states that additional POP rate may be required "during startup of, or after gas production begins to decline from, other fields".4 CPAI does not entirely understand this statement. It may suggest that BPXA and EMAP perceive a real risk that PTU start-up will be materially delayed, after AKLNG start-up currently premised in 2025. CPAI also is a PTU owner, and is not aware of such a risk, especially in light of the extent of work that will have been completed by next year for IPS. As far as CPAI is aware, excepting TAPS, no North Slope project similar to (or larger than) PTU gas expansion has been delayed more than 3 months. Further, given the complexity and scope of AKLNG (currently estimated to 3 CPAI's requested 3.6 bscf/d POP maximum annual average offtake rate is comprised of 2.7 bscf/d normal AKLNG GTP supply, 0.6 bscf/d for fuel gas, other field operations, and minor North Slope sales, plus 0.3 bscf/d to allow for the POP to supply 100% of AKLNG GTP inlet volume for up to four months in one year. In this regard, if POP offtake occurred at 4.1 bscf/d for 4 months, and at 3.3 bscf/d for 8 months, then the annual average offtake rate would be approximately 3.6 bscf/d. 4 BPXA and EMAP Consolidated Application, at 4. CPA[ Comments to BPXA ancTEMAP Consolidated Application to Amend }mule 9 and Modify AIOs Page 4 of 6 August 19, 2015 cost $45-$65 billion), it is much more likely that AKLNG — not PTU — would be the source of any material start-up delay. However, if AKLNG did start-up in 2025, and if PTU start-up were materially delayed after AKLNG start up, and the PBU WIOs wished to supply the AKLNG GTP during the period of PTU delay, CPAI anticipates the Commission could timely consider a short term increase to the Rule 9 offtake rate at that time. As construction progress will be closely tracked against critical path schedules, the PBU WIOs would know likely at least one year in advance if PTU start up would be delayed more than four months.5 In any event, given the low likelihood of material PTU delay — a successful AKLNG project is premised on simultaneous start-up of all project and related upstream systems — there is no need for the Commission to grant a POP annual average offtake rate higher than 3.6 bscf/d at this time. The same is true if, in relation to BPXA's and EMAP's statement that additional POP supply may be required "after gas production begins to decline from ... other fields".6 This statement appears to suggest that if PTU declines much faster than expected, supply from the POP will be needed to cover the difference. As far as CPAI is aware, this is unlikely. The PTU operator has provided very high quality information validating PTU resources. The IPS Project will provide additional validation. CPAI expects there will be a low likelihood that PTU will decline much faster than anticipated. However, in the unlikely event that PTU declines much faster than expected, and the PBU WIOs wished to supply additional gas from the POP, there would be sufficient time to request an appropriate Rule 9 increase.' AKLNG start-up currently is premised to occur in 2025. Accelerated PTU decline, if it were to occur, would occur many years after 2025 start-up. In sum, material PTU delay and materially accelerated PTU decline are both unlikely events. If either ever occurred, a PBU offtake increase could be timely considered by the PBU WIOs and the Commission, if appropriate, at that time. B. CPAI Supports BPXA's and EMAP's Request to Allow GTP Byproduct Injection for FOR and Pressure Maintenance, But Further Requests That the Commission Allow Disposal of GTP Byproducts in Appropriate Intervals Through Class II Wells CPAI supports BPXA's and EMAP's request to inject GTP byproducts, principally comprising CO2, into appropriate intervals within the PBU, for FOR and pressure maintenance. However, CPAI notes that the benefit BPXA and EMAP identify in connection with such injection — approximately 3.8 billion barrels of oil equivalent — is the total gas recovery associated with major gas sales into AKLNG.8 This additional recovery is very material, but it is not an FOR benefit. BPXA and EMAP have not identified actual FOR benefits in their application.9 However, AKLNG start up is premised to occur in 2025, so there are many years in which to investigate additional FOR opportunities. In this regard, CPAI requests that the Commission grant BPXA's and EMAP's 5 Further, unless AKLNG start up is to occur on the first of a calendar year, a 3.6 bscf/d maximum offtake rate would allow offtake from the POP at 4.1 bscf/d for longer than four months in that year (as the daily rates are averaged over the entire calendar year), which would afford additional flexibility. 6 BPXA and EMAP Consolidated Application, at 4. CPAI requests that the Commission include, as necessary, provisions in Rule 9 and relevant area injection orders to permit administrative approval of future modifications. 6 BPXA and EMAP Consolidated Application, at 5. 9 The Consolidated Application does not identify "an expected increase in incremental hydrocarbon recovery" from CO2 injection. 20 AAC 25.402(c)(14). • • CPAI Comments to BPXA and EMAP Consolidated Application to Amend Rule 9 and Modify AIOs Page 5 of 6 August 19, 2015 request to approve GTP byproduct injection for FOR and pressure maintenance, in anticipation that there may be FOR opportunities later identified. However, in the event that FOR opportunities are not later identified, CPAI also requests that the Commission approve disposal of GTP byproduct in appropriate intervals in Class II PBU wells.10 C. Supporting Information CPAI will have appropriate experts available at the public hearing to testify regarding these comments. Depending on the testimony presented by others, CPAI reserves the right to present additional testimony at the public hearing, or by post -hearing submission, if so authorized by the Commission. D. Conclusion Based on the above comments, CPAI respectfully requests that the Commission: (1) Approve BPXA's and EMAP's request to increase the Rule 9 maximum allowable offtake rate, but to a maximum offtake rate of 3.6 bscf/d annual average, rather than the 4.1 bscf/d annual average requested by BPXA and EMAP; (ti) Approve BPXA's and EMAP's request to modify relevant area injection orders to permit injection of CO2 and other gas treatment byproducts for purposes of FOR and pressure maintenance; and, in addition, also approve injection of CO2 and other gas treatment byproducts for disposal in appropriate PBU Intervals, In the event that FOR or pressure maintenance opportunities that result in increased POP hydrocarbon recovery are not identified; and (iii) Include in Rule 9 and relevant area injection orders provisions, as necessary, to permit administrative approval of future modifications. Please contact Eric Reinbold at 907-263-4465 if the Commissioners or Commission staff have any questions regarding these comments. Please direct communications regarding procedural matters, including the public hearing, to John Evans, counsel for CPAI, at 907-265-6329. Sincerely, , Greater Prudhoe Area i, Inc. Concurring for Chavroy 1A S.A. Inc. J.M. Wolnler, NOJV Manager Chevron North America Exploration and Production Company, a division of Chevron U.S.A. Inc. 10 CPAI recognizes that the Commission will need additional information under 20 AAC 25.252 to approve a disposal request; however, this information can be readily provided by the PBU operator. Relevant to 20 AAC 25.252(c), as noted in BPXA's and EMAP's Consolidated Application, there is no risk of movement of fluids into sources of freshwater or underground drinking water. BPXA and EMAP Consolidated Application at 6. CPAI Comments to BPXA an*MAP Consolidated Application to Amend }rule 9 and Modify AIOs Page 6 of 6 August 19, 2015 Attachment 1 — June 15 and June 8 Letters from the Governor of the State of Alaska cc via email: Gilbert Wong, EMAP (gilbert.wonq(o)exxonmobil.com) Steve Luna, EMAP (charles.s.luna(aa)exxonmobil.com) Phil Ayer, CUSA (pmayer(@chevron.com) Angie Bible, CUSA (a bible (a�chevron.com) John Dittrich, BPXA (John. Dittrich(,5bp.com) George Lyle, Guess & Rudd (glyle(ab-guessrudd.com) Chris Wyatt, BPXA (Chris.Wyatt(D-bp.com) Eric Reinbold, CPA[ (Eric.W.Rein bold(aD-conocophill ips.com) John Evans, CPAI (John. R. Evans(cD-conocophillips.com) • • Attachment 1 June 15 and June 8 Letters from the Governor of the State of Alaska See attached. • STATE CAPITOL PO. Box 110001 Juneau, AK 9981 1-0001 907-465-3S00 fax: 907-465-3532 Governor Bill Walker STATE OF ALASKA June 15, 2015 The Honorable Kathy Giessel Alaska State Senate 716 W. 4th Ave. Suite 511 Anchorage AK, 99501 The Honorable Benjamin Nageak Alaska State House of Representatives State Capitol Room 126 Juneau AK,99801 The Honorable Dave Talerico Alaska State House of Representatives 1292 Sadler Way Suite 328 Fairbanks AK, 99701 Dear Senate and House Resource Committee Chairs and Co -Chairs: SSO West Seventh Avenue, Suite 1700 Anchorage. AK 99501 907-269-7450 fax 907-269-7461 www.Gov.Alaska.Gov Governor@Alaska.Gov I want to inform you about the efforts of my administration to move the AK LNG project ahead. Attached is my letter dated June 8, 2015 to the heads of the producers' negotiating teams for the AK LNG project. We have identified a lack of urgency in the parties' resolution process. The methodology that the AK LNG team adopted for identifying problems and issues is excellent. However, there does not appear to be much process associated with resolving issues between the parties, and certainly not one with a sense of time urgency. It is time to build this gas pipeline to Nikiski, and therefore the state needs to take the lead and proactively mediate and find resolutions within a time frame that will keep the project on schedule. The attached letter proposes a time frame and process for moving the issues to resolution. To date, the producers have been working towards a 2nd quarter-2016 FEED decision. This meshes efficiently with a fall special session for legislative review of the proposed agreements. It also works well should voter consideration of a November 2016 constitutional amendment be required in addressing the fiscal certainty needs of the project. For these reasons, schedules should not be allowed to slide. Assuming that all the producers match the State's commitment to commercialize North Slope gas, we must push ourselves to close out these issues. The attached letter identifies the key issues requiring resolution and the state's position on those issues. My hope is that with clarity of focus and attention, the producers and the state can stay the course on their intended timeline and give Alaskans a gas pipeline project from the North Slope to Nikiski that will provide the next generation the revenues they need to build a prosperous future. • E Sincerely, 1 ill V��alker Governor cc: Janet Weiss Dave VanTuyl Joe Marushack Pat Flood Bill McMahon Jim Flood STATE CAPITOL PO Box 110001 r `f`. •_ .-� .• Juneau. AK 9981 1 -0001 ~M 907-465-3500 fax: 907-465-3532 Governor Bill Walker STATE OF ALASKA June 8, 2015 Janet Weiss & Dave VanTyle BP Exploration Alaska, Inc. 900 E. Benson Blvd. Anchorage, AK 99508 Joe Marushack & Pat Flood ConocoPhillips Alaska, Inc. P.O. Box 100360 Anchorage, AK 99510-0360 Bill McMahon & Jim Flood ExxonMobil Development Company Wellness 2, 5A.345 22777 Springwoods Village Parkway Spring, Texas 77389 Dear AK LNG Sponsors: SSO West Seventh Avenue, Suite 1 700 Anchorage, AK 99SO1 907-269 7450 fax 907-269-7461 www.Gov.Alaska Gov Gover nor@Alaska. Gov A few weeks ago, we jointly set a goal to finalize the term sheets for all major project enabling contracts by the middle of June. It is now June 8'1'. Despite the efforts of all parties, it is clear we are not on schedule to achieve this goal. There are at least two major issues and at least three smaller major issues. I have summarized the State's listing of those issues along with my comments. I am asking that this list be considered by the VAMOU on Tuesday to determine if consensus can be reached on the completeness of the list. The goal would be to gain agreement on a final list of major issues in order for our respective negotiating teams to share a common focus and issue prioritization. The resulting list would then be presented at the Sponsor Meeting on Wednesday with the Sponsor representatives tasked to resolve these major issues — especially the two large major issues. Resolution of these major sticking points will be a catalytic event enabling substantial progress on finalizing the terms of the project contracts. To the extent there are issues remaining after the Sponsor Meeting where the parties are substantially apart, I would like the State to engage in a shuttle diplomatic effort with producers, with a goal of gaining issue closure or at least a clear understanding of the extent of remaining disagreement. Following the best efforts of our teams to reach closure on the major issues, I 0 11 would like to meet face to face during the week of June 15`h with each Sponsor executive individually to attempt to resolve the remaining issues. I would like to resolve the major issues in these meetings so we can begin the process of drafting contracts The AK LNG team will be briefing the Legislature on the 161h of June in Kenai, Alaska. After months of expectation, the people of Alaska and their elected representatives are anxious for concrete progress. Large Major Issues The largest issue is Joint Venture Marketing vs. Equity Marketing, The State believes it will be very difficult, if not impossible, for this project to proceed with the PBU and PTU fields with all the current participants outside a Joint Venture Marketing context. 2. Upstream issues — to the extent they are not resolved by Joint Venture Marketing. Most of the remaining upstream issues can be resolved through the use of separate Joint Ventures that would receive the gas from the PBU and PTU fields with support between the two Joint Ventures along the lines of the proposal attached as Appendix A. Other Major Issues 3. Fiscal Stability: It will only deal with the gas dedicated to this Project from PBU and PTU. It will not include oil. The State is willing to consider a 25 year term in order to facilitate integrated project financing. The State believes a Constitutional Amendment will provide the certainty that all parties would like. Attached as Exhibit B is an example of what I envision the constitutional amendment might look like. 4. 48 inch line: Constructing a 48 inch line will alleviate the issues of open access and expansion. The Producers have stated they do not need or want a 48 inch line. The State is willing to pay for this expansion subject to legislative approval, but it would own all the benefits of the increased size. The State would also pay for installing the valves, pads etc. to accommodate four more compressor stations that will be added when demand exists from new developments or fields. The State intends to use this expansion capacity to encourage open access. 5. East vs. West Cook Inlet crossing: It is my understanding that the studies for the two routes are under way but that the tentative conclusion at this point in time is that the Western Route is the preferred alternative. The Matsu Valley constitutes the second largest population base in the State of Alaska and has some of the highest industrial potential in the State. Consequently, the State strongly prefers the Eastern Route since the studies to date do not indicate any insurmountable obstacles. Also, the Eastern Route will better enable this Project to better fulfill the statutory domestic gas mandate. 0 • Sincerely, i004l .-� Bill Walker Governor Enclosure Appendix A — Joint Venture Marketing Model Appendix B — Sample Draft Constitutional Amendment cc: Dona Keppers, SOA, Deputy Commissioner of Revenue Dan Fauske, AGDC Steve Wright, SOA, Department of Natural Resources Audie P. Setters, SOA, Gas Team, General Manager 0 Joint Venture Marketing Model Appendix A PB Capacity MMM" Future Mutual Aid I PT Capacity AKLNG Less complex than any acceptable FSA solution proposed to date • Can explain to buyers, lenders and other State stakeholders Market Perception of AKLNG AKLNG JV Buyers -LNG -LNG -In State -in State Note: Each party to verify that any marketing structure contemplated for AKLNG complies with applicable anti-trust laws • The JV revenue flows back to Titleholders in proportion to their respective participation • Any JV costs (including SPA penalties) flow back to Titleholders in proportion to their respective participation • The JV nominates supply from each Unit, and takes title at entry point to the relevant Transmission Line Gas Balancing and Mutual Aid: 1 • One month of borrow/loan gas each year for operational issues: • to be repaid in kind within one calendar year; • In place for 15 years after start-up • One time gas purchase option (approx. 2 months of PTU downtime): • 80 BCF (20 cargos) on an energy basis • Expires lesser of 5 years after triggered or year 15. • JVs can "bank" gas to ensure access to additional future gas; • Good faith mutual assist provision to ensure Ns avoid reputational damage to AKLNG (dropped cargos) • 0 0 • APPENDIX B Sample Draft Constitutional Amendment * Section 1. Article IX, Constitution of the State of Alaska, is amended by adding a new section to read: Section 18. Suspension of Taxation by Contract Authorized by Law. Contracts approved by a majority of the legislature and entered into by the executive branch by December 31, 2017 to provide fiscal terms for a liquefied natural gas project, including a gas treatment plant, gas pipelines, and a liquefied natural gas plant and related facilities, as provided by law are constitutional under this article. Such contracts as originally executed shall be binding upon future legislatures as to terms of gas taxation, but any amendments to such contracts executed between the parties shall not bind future legislatures as to any aspect of taxation. • REVISED Notice of Public Hearing STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION Re: Docket Numbers: AIO 15-032, AIO 15-033, and CO 15-09 Prudhoe Bay Unit Requested Modifications BP Exploration (Alaska) Inc., by letters dated July 17, 2015, requests the Alaska Oil and Gas Conservation Commission (AOGCC) modify Area Injection Orders 3A & 4F, and Conservation Order 341D authorize the injection of CO2 for enhanced recovery purposes and to increase the allowable gas offtake rate for the Prudhoe Oil Pool. The AOGCC previously scheduled a public hearing on this application for August 27, 2015 at 9:00 a.m. at 333 West 7th Avenue. By this revised noticed, the site of the public hearing is changed to 716 West 4th Avenue, Anchorage, Alaska 99501. Written comments regarding this application may be submitted to the AOGCC, at 333 West 7th Avenue, Anchorage, Alaska 99501. Comments must be received no later than the conclusion of the August 27, 2015 hearing. If you would like to attend the above Public Hearing but are unable to do so in person, the call in number is 1-844-586-9085 or you can watch live at akl.tv. If, because of a disability, special accommodations may be needed to comment or attend the hearing, contact the AOGCC's Special Assistant, Jody Colombie, at 793-1221, no later than August 20, 2015. Cathy P. oerster Chair, Commissioner • • STATE OF ALASKA ADVERTISING ORDER NOTICE TO PUBLISHER SUBMIT INVOICE SHOWING ADVERTISING ORDER NO., CERTIFIED AFFIDAVIT OF PUBLICATION WITH ATTACHED COPY OF ADVERTISMEN T. ADVERTISING ORDER NUMBER AO-16-004 FROM: Alaska Oil and Gas Conservation Commission AGENCY CONTACT: Jody Colombie/Samantha Carlisle DATE OF A.O. 07/23/15 AGENCY PHONE: 1(907) 793-1221 333 West 7th Avenue Anchorage, Alaska 99501 DATES ADVERTISEMENT REQUIRED: COMPANY CONTACT NAME: PHONE NUMBER: ASAP FAX NUMBER: (907)276-7542 TO PUBLISHER: Alaska Dispatch News SPECIAL INSTRUCTIONS: PO Box 149001 Anchorage, Alaska 99514 TYPE OF ADVERTISEMENT: LEGAL DISPLAY CLASSIFIED OTHER (Specify below) DESCRIPTION PRICE Revised AIO-15-032, AIO-033 and CO-15-09 Initials of who prepared AO: Alaska Non -Taxable 92-600185 S[TRMIT Py1'olGl:s}tgw�tvc: AtiVERTlsrrvc �- ORDERINO,. CERTIFIE 1 AFFIDAV.IT OF;:; �PUJHACAT'IONWITH ATTACKED: COPY OF Ai>VEtt7CSMPIVT T6 ... .. ... Department of Administration Division of AOGCC 333 West 7th Avenue Anchorage, Alaska 99501 Page 1 of 1 Total of All Pages S REF Type Number Amount Date Comments I PvN ADN94501 2 Ao AO-16-004 3 4 FIN AMOUNT SY CC PGM LGR ACCT FY DIST LIQ I 16 02140100 73451 16 2 3 4 5 Purchas ig u 0 ame: itie: j 7 uy'c n thority's Signa ure Telephone Number 1 A.O. # a receiving agency name st appe on all invoices and documents rel4jing to this purchase. 2 The stat j registered for tax free transactions under Chapter 32, IRS code Regis ration number 92-73-0006 K. Items are for the exclusive use of the state and not for resale. DISTRIBUTION Division Fiscal/OrrginalAO Copies: Publisher (faxed), D►v►slon Fisc-Ai Form:02-901 Revised: 7/23/2015 270227 • 0001368912 $ 194.24 • E AFFIDAVIT OF PUBLICATI O 4C, ON STATE OF ALASKA THIRD JUDICIAL DISTRICT Leesa Little being first duly sworn on oath deposes and says that he/she is a representative of the Alaska Dispatch 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 July 24, 2015 and that such newspaper was regularly distributed to its subscribers during all of said period. That the full amount of the fee charged for the foregoing publication is not in excess of the rate charged private individuals. Signed, Subscribed and sworn to before me this 24th day of July, 2015 Notary Public in and for The State of Alaska. Third Division Anchorage, Alaska MY COMMISSION EXPIRES �23/- 19 Revised Public Hearing STATE OF ALASKA Alaska Oil and Gas Conservation Commission Re: Docket Numbers: AIO 15-032, AIO 15-033, and CO 15-09 Prudhoe Bay Unit Requested Modifications BP Exploration (Alaska) Inc., by letters dated July 17, 2015, requests the Alaska Oil and Gas Conservation Commission (AOGCC) modify Area Injection Orders 3A & 4F, and Conservation Order 341 D authorize the in ection of Coe for enhanced recovery purposes and to increase the allowable gas offtake rate for the Prudhoe Oil Pool. The AOGCC previously scheduled a public hearing on this application for August 27, 2015 at 9:00 a.m. at 333 West 7th Avenue. By this revised noticed, the site of the public hearing is changed to 716 West 4th Avenue, Anchorage, Alaska 99501. Written comments regarding this application may be submitted to the AOGCC, at 333 West 7th Avenue, Anchorage, Alaska 99501. Comments must be received no later than the conclusion of the August 27, 2015 hearing. If you would like to attend the above Public Hearing but are unable to do so in person, the call in number is 1-844-586-9085 or you can watch live at akl.ty. If, because of a disability, special accommodations may be needed to comment or attend the hearing, contact the AOGCC's Special Assistant, Jody Colombie, at 793-1221, no later than August 20, 2015. Cathy P. Foerster Chair, Commissioner AO-16-004 Published: July 24, 2015 NOWY Public BRITNEY L, rHOMPSON State Of Alaska MY �®AIf111111on Expires Feb 23, 2019 0 • Singh, Angela K (DOA) From: Colombie, Jody J (DOA) Sent: Thursday, July 23, 2015 2:32 PM To: Ballantine, Tab A (LAW); 'Salena'; Delbridge, Rena E (LAS); glyle@guessrudd.com; AKDCWellIntegrityCoordinator, Alex Demarban; Alexander Bridge; Allen Huckabay; Andrew VanderJack; Anna Raff; Barbara F Fullmer, bbritch; Becca Hulme; bbohrer@ap.org; Bob Shavelson; Brian Havelock; Bruce Webb; Burdick, John D (DNR); 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; Greg Duggin; Gregg Nady; gspfoff, Jacki Rose; Jdarlington oarlington@gmail.com); Jeanne McPherren; Williams, Jennifer L (LAW); Jerry Hodgden; Jerry McCutcheon; Solnick, Jessica D (LAW); Jim Watt, Jim White; Joe Lastufka; news@radiokenai.com; John Adams; Easton, John R (DNR); Jon Goltz; Juanita Lovett; Judy Stanek; Houle, Julie (DNR); Julie Little; Kari Moriarty; Kazeem Adegbola; Keith Wiles; Kelly Sperback; 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 Landt; Mark Wedman; Kremer, Marguerite C (DNR); Mary Cocklan-Vendl; Michael Calkins; Michael Duncan; Michael Moora; Mike Bill; mike@kbbi.org; Mikel Schultz; 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; Patty Alfaro; Paul Craig; Decker, Paul L (DNR); 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); Smart Energy Universe; Smith, Kyle S (DNR); Sondra Stewman; Stephanie Klemmer; Sternicki, Oliver R; Moothart, Steve R (DNR); Suzanne Gibson; sheffield@aoga.org; Tania Ramos; Ted Kramer, Davidson, Temple (DNR); Terence Dalton; Teresa Imm; Terry Templeman; Thor Cutler, Tim Mayers; Todd Durkee; trmjrl; Tyler Senden; Vicki Irwin; Vinnie Catalano; Aaron Gluzman; Aaron Sorrell; Ajibola Adeyeye; Alan Dennis; Andrew Cater, Anne Hillman; Bajsarowicz, Caroline 1; Brian Gross; Bruce Williams; Bruno, Jeff J (DNR); Casey Sullivan; Don Shaw; Donna Vukich; Eric Lidji; Erik Opstad; Gary Orr; Smith, Graham O (PCO); Greg Mattson; Dickenson, Hak K (DNR); Heusser, Heather A (DNR); Holly Pearen; Hyun, James J (DNR); Jason Bergerson; 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, James M (DNR); Morgan, Kirk A (DNR); Pat Galvin; Bettis, Patricia K (DOA); Pete Dickinson; Peter Contreras; Richard Garrard; Richmond, Diane M; Robert Province; Ryan Daniel; Sandra Lemke; Sarah Baker, Peterson, Shaun (DNR); Pollard, Susan R (LAW); Talib Syed; Tina Grovier (tmgrovier@stoel.com); Todd, Richard J (LAW); Tostevin, Breck C (LAW); Wayne Wooster; William Hutto; William Van Dyke; Ballantine, Tab A (LAW); Bender, Makana 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); Foerster, Catherine P (DOA); Frystacky, Michal (DOA); Grimaldi, Louis R (DOA); Guhl, Meredith D (DOA); Herrera, Matthew F (DOA); Hill, Johnnie W (DOA); Hunt, Jennifer L (DOA); Jackson, Jasper C (DOA); Jones, Jeffery B (DOA); Kair, Michael N (DOA); Loepp, Victoria T (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, To: Angela K (DOA); Wallace, Chris D (DOA) • Subject: Revised Public Notices Attachments: Revised Notice of Public Hearing, CO-15-08.pdf, Revised Notice of Hearing, Dockets AIO-15-32, AIO-15-33, CO-15-09.pdf Please disregard the Public Notices that I sent earlier, the website information was incorrect. I apologize for any inconvenience this may have caused you. 0 0 Bernie Karl James Gibbs Jack Hakkila K&K Recycling Inc. P.O. Box 1597 P.O. Box 190083 P.O. Box 58055 Soldotna, AK 99669 Anchorage, AK 99519 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 Dave P. Lachance Vice President Richard Wagner Darwin Waldsmith Alaska Reservoir Development P.O. Box 60868 P.O. Box 39309 BP Exploration (Alaska), Inc. Fairbanks, AK 99706 Ninilchik, AK 99639 P.O. Box 196612 Anchorage, AK 99508 2312vOS, CL�sc* Angela K. Singh 0 Notice of Public Hearing STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION Re: Docket Numbers: AIO 15-032, AIO 15-033, and CO 15-09 Prudhoe Bay Unit Requested Modifications BP Exploration (Alaska) Inc., by letters dated July 17, 2015, requests the Alaska Oil and Gas Conservation Commission (AOGCC) modify Area Injection Orders 3A & 4F, and Conservation Order 341D authorize the injection of CO2 for enhanced recovery purposes and to increase the allowable gas offtake rate for the Prudhoe Oil Pool. The AOGCC has scheduled a public hearing on this application for August 27, 2015 at 9:00 a.m. at 333 West 7th Avenue, Anchorage, Alaska 99501. Written comments regarding this application may be submitted to the AOGCC, at 333 West 7tn Avenue, Anchorage, Alaska 99501. Comments must be received no later than the conclusion of the August 27, 2015 hearing. If, because of a disability, special accommodations may be needed to comment or attend the hearing, contact the AOGCC's Special Assistant, Jody Colombie, at 793-1221, no later than August 20, 2015. Cathy P. oerster Chair, Commissioner 0 s STATE OF ALASKA ADVERTISING ORDER NOTICE TO PUBLISHER SUBMIT INVOICE SHOWING ADVERTISING ORDER NO., CERTIFIED AFFIDAVIT OF PUBLICATION WITH ATTACHED COPY OFADVERTISMENT. ADVERTISING ORDER NUMBER AO-16-002 FROM: Alaska Oil and Gas Conservation Commission AGENCY CONTACT: Jody Colombie/Samantha Carlisle DATE OF A.O. 07/20/15 1(907) AGENCY PHONE: 793-1221 333 West 7th Avenue Anchorage, Alaska 99501 DATES ADVERTISEMENT REQUIRED: COMPANY CONTACT NAME: PHONE NUMBER: ASAP FAX NUMBER: (907)276-7542 TO PUBLISHER: Alaska Dispatch News SPECIAL INSTRUCTIONS: PO Box 149001 Anchorage, Alaska 99514 TYI `' LEGALw DISPLAY GLASStF1ED OTHER (Specify below) a "W, fit. DESCRIPTION PRICE AIO-15-032, AIO-15-033 and CO-15-09 Initials of who prepared AO: Alaska Non -Taxable 92-600185 " " " " sv$iyiLT pVyoI9:SHoaviv�;Ai11ElR7L51P?Cr" ::�O;RDEB:NO,,;GERIIFIEIJA:F:F#DAV�I'OF;:;� rUaie4riiiriwiii►:ATiaciiEti;cirYoi?: .......... Department of Administration Division of AOGCC 333 West 7th Avenue Anchorage, Alaska 99501 Pagel of 1 Total of All Pages $ - .................................. REF Type Number Amount Date Comments I PvN ADN84501 2 Ao AO-16-002 3 4 FIN AMOUNT SY CC PGM LGR ACCT FY DIST LIQ 1 16 02140100 73451 16 2 3 4 urchasi A th i T le: uthor' i nature Telephone Number 1. .0.:# nd ceiving agency name must appear on all invoices and docume is relating to this purchase. 2. The s to is registered for tax free transactions under Chapter 32, IRS code. egistration number 92-73-0006 K. Items are for the exclusive use of the state and not for resale. :. UT O Ni.:........'.".:.:.:.:.:.:...:.:.::::::::.::::ii::::: i::::::...:::::: i:!":!"::: "':'.:_..._::':'.':'_ ...'...'_ .:.:::: :.: ' ' :...:...... AISTIIIB .TL .N......"................................. ................... I)ivrsron Fiscal/Original: A0. C Ie§c".;P+iblisher (faxed), ➢iyisioit Fiscai;"Iteceivirig...; "" Form: 02-901 Revised: 7/20/2015 270227 • 0001368715 $ 169.34 • RECEIVED JUL 3 0 2015 AFFIDAVIT OF PUBLICATION AaGcG STATE OF ALASKA THIRD JUDICIAL DISTRICT Leesa Little being first duly sworn on oath deposes and says that he/she is a representative of the Alaska Dispatch 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 July 21, 2015 and that such newspaper was regularly distributed to its subscribers during all of said period. That the full amount of the fee charged for the foregoing publication is not in excess of the rate charged private individuals. Signed lez-� Subscribed and sworn to before me this 21 st day of July, 2015 Notary Public in and for The State of Alaska. Third Division Anchorage, Alaska MY COMMISSION EXPIRES 3 Notice of Public Hearing STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION Re: Docket Numbers: AIO 15-032, AID 15-033, and CO 15-09 Prudhoe Bay Unit Requested Modifications BP Exploration (Alaska) Inc., by letters dated July 17, 2015, requests the Alaska Oil and Gas Conservation Commission (AOGCC) modify Area Injection Orders 3A & 4F, and Conservation Order 341D authorize the in of CO2 for enhanced recovery purposes and to increase the allowable gas offtake rate for the Prudhoe oil Pool. The AOGCC has scheduled a public hearing on this application for August 27, 2015 at 9:00 a.m. at 333 West 7th Avenue, Anchorage, Alaska 99501. Written comments regarding this application may be submitted to the AOGCC, at 333 West 7th Avenue, Anchorage, Alaska 99501. Comments must be received no later than the conclusion of the August 27, 2015 hearing. If, because of a disability, special accommodations may be needed to comment or attend the hearing, contact the AOGCC's Special Assistant, Jody Colombie, at 793-1221, no later than August 20, 2015. AO-16-002 Published: July 21, 2015 Cathy P. Foerster Chair, Commissioner NNotary Public �s BRITYL. THOMPSON My Oo State of Alaska "Mission Expires Feb 23, 2019 • 0 Singh, Angela K (DOA) From: Colombie, Jody J (DOA) Sent: Monday, July 20, 2015 1:07 PM To: Ballantine, Tab A (LAW); 'Nathan Hile (nwhcmatrix@hotmail.com)'; 'Salena'; glyle@guessrudd.com; 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); Frystacky, Michal (DOA); Guhl, Meredith D (DOA); Hunt, Jennifer L (DOA); Jackson, Jasper C (DOA); Kair, Michael N (DOA); Loepp, Victoria T (DOA); Mumm, Joseph (DOA sponsored); Paladijczuk, Tracie L (DOA); Pasqual, Maria (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); AKDCWeIIIntegrityCoordinator, Alex Demarban; Alexander Bridge; Allen Huckabay; Andrew VanderJack; Anna Raff; Barbara F Fullmer; bbritch; Becca Hulme; bbohrer@ap.org; Bob Shavelson; Brian Havelock; Bruce Webb; Burdick, John D (DNR); 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; Greg Duggin; Gregg Nady; gspfoff, Jacki Rose; Jdarlington oarlington@gmail.com); Jeanne McPherren; Williams, Jennifer L (LAW); Jerry Hodgden; Jerry McCutcheon; Solnick, Jessica D (LAW); Jim Watt; Jim White; Joe Lastufka; news@radiokenai.com; John Adams; Easton, John R (DNR); Jon Goltz; Juanita Lovett; Judy Stanek; Houle, Julie (DNR); Julie Little; Kari Moriarty; Kazeem Adegbola; Keith Wiles; Kelly Sperback; 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 Landt; Mark Wedman; Kremer, Marguerite C (DNR); Mary Cocklan-Vendl; Michael Calkins; Michael Duncan; Michael Moora; Mike Bill; mike@kbbi.org; Mikel Schultz; 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; Patty Alfaro; Paul Craig; Decker, Paul L (DNR); 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); Smart Energy Universe; Smith, Kyle S (DNR); Sondra Stewman; Stephanie Klemmer; Sternicki, Oliver R; Moothart, Steve R (DNR); Suzanne Gibson; Sheffield@aoga.org; Tania Ramos; Ted Kramer; Davidson, Temple (DNR); Terence Dalton; Teresa Imm; Terry Templeman; Thor Cutler; Tim Mayers; Todd Durkee; trmjrl; Tyler Senden; Vicki Irwin; Vinnie Catalano; Aaron Gluzman; Aaron Sorrell; Ajibola Adeyeye; Alan Dennis; Andrew Cater, Anne Hillman; Bajsarowicz, Caroline J; Brian Gross; Bruce Williams; Bruno, Jeff 1 (DNR); Casey Sullivan; Don Shaw; Donna Vukich; Eric Lidji; Erik Opstad; Gary Orr, Smith, Graham O (PCO); Greg Mattson; Dickenson, Hak K (DNR); Heusser, Heather A (DNR); Holly Pearen; Hyun, James J (DNR); Jason Bergerson; jili.a.mcleod@conocophillips.com; Jim Magill; Joe Longo; John Martineck, Josh Kindred; Kenneth Luckey; King, Kathleen 1 (DNR); Laney Vazquez; Lois Epstein; Longan, Sara W (DNR); Marc Kuck; Marcia Hobson; Steele, Marie C (DNR); Matt Armstrong; Matt Gill; 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; Sarah Baker; Peterson, Shaun (DNR); Pollard, Susan R (LAW); Talib Syed; Tina Grovier (tmgrovier@stoel.com); Todd, Richard J (LAW); Tostevin, Breck C (LAW); Wayne Wooster, William Hutto; William Van Dyke Subject: Public Notice (PBU Requested Modifications) AIO-15-32, AIO-15-033, CO-15-09 Attachments: Notice of Hearing, Dockets AIO-15-32, AI0-15-33, CO-15-09.pdf 0 • James Gibbs Jack Hakkila Bernie Karl P.O. Box 1597 P.O. Box 190083 K&K 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 Dave P. Lachance Richard Wagner Darwin Waldsmith Vice President P.O. Box 60868 P.O. Box 39309 Alaska Reservoir Development Fairbanks, AK 99706 Ninilchik, AK 99639 BP Exploration (Alaska), Inc.P.O. Box 196612 Anchorage, AK 99508 4-,AQa,4,qL ' 's"1 2\, 2 cti1 �j 0�� Angela K. Singh • Dave Lachance Vice President Alaska Reservoir Development July 17, 2015 Via Hand Delivery Cathy P. Foerster Commission Chair Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, Alaska 99501 JUL 17 2015 AOGCC BP Exploration (Alaska) Inc. 900 East Benson Boulevard P.O. Box 196612 Anchorage, AK 99508 USA Direct 907 564 4855 Mobile 907 538 1719 Main 907 564 5111 dave.lachance@bp.com 11 Re: Consolidated Application for Amendment of Prudhoe Oil Pool Rule 9 and Modification of Prudhoe Bay Unit Area Injection Orders AIO 3A and AID 4F Dear Chair Foerster: BP Exploration (Alaska) Inc., as an individual working interest owner (BPXA) in the Prudhoe Bay Unit (PBO, and not as PBU operator, on behalf of itself and PBU working interest owner ExxonMobil Alaska Production Inc. (EMAP), submits this consolidated application to the Alaska Oil and Gas Conservation Commission (AOGCC) to obtain two related authorizations: (i) Amendment of Rule 9 of Conservation Order (CO) 341 D for the Prudhoe Oil Pool (POP) to authorize an increase in the maximum annual average gas off - take limit from 2.7 billion standard cubic feet per day (bscf/d) to 4.1 bscf/d. (ii) Modification of AIO 3A and AIO 4F (collectively the AIOs) to authorize the injection of CO2 for enhanced recovery and pressure maintenance from sources both inside, which is already authorized, and outside the Prudhoe Bay Unit. As related procedural matters, BPXA respectfully requests that, to the full extent allowed by the applicable regulations, the AOGCC: (i) consolidate proceedings pertaining to amendment of Rule 9 and modification of the AIOs because of their interrelated nature; (ii) provide notice of a public hearing on this application tentatively scheduled for on or about August 31, 2015 in accordance with 20 AAC 25.520 and 20 AAC 25.540; (iii) tentatively schedule a pre -hearing conference for on or about August 10, 2015 in accordance with 20 AAC 25.540(f); and • Application to Amend POP Rule 9 and Modify AIOs July 17, 2015 Page - 2 (iv) allow the submission of pre -filed written testimony in support of the application pursuant to 20 AAC 25.540(c)(12) with the submitting witness(es) to be present at the public hearing to provide sworn testimony and respond to questions of the AOGCC, if any. Please note that the portion of this consolidated application contained in the Confidential Appendix is confidential, and BPXA requests that such information be held confidential pursuant to AS 31.05.035(d), 20 AAC 25.537(b), and AS 45.50.910 et seq. The Confidential Appendix is enclosed in a separate envelope and marked confidential. BPXA respectfully requests that the AOGCC make a decision on the matters addressed in this consolidated application on or before October 15, 2015. I. PRUDHOE OIL POOL RULE 9 AMENDMENT A. POP Maximum Annual Average Gas Off -Take Rate Rule 9, as adopted by the AOGCC in 1977, limits the maximum annual average gas off -take from the POP to 2.7 bscf/d. Approximately 0.6 bscf/d is currently used (and anticipated to continue to be used) for fuel, other field operations and minor local gas sales. Accordingly, under Rule 9, an annual average gas off -take of approximately 2.1 bscf/d would be available for major gas sales. BPXA and the other PBU working interest owners (individually referred to as a WIO and collectively as WIOs) and the AOGCC have long contemplated a major gas sales project involving gas from Prudhoe Bay (PBMGS'). In accordance with good oil field engineering practices, at various stages of field development, the PBU WIOs have evaluated the potential effects of a PBMGS on oil production and hydrocarbon recovery from the POP based upon then - existing information and models. Gas production from the POP has been used for extraction of miscible injectant, manufacture of natural gas liquids, pressure maintenance, and enhanced oil recovery. Partly as a result of this POP gas utilization, liquid recovery from the POP has increased from the estimated 9.6 billion barrels in 1977 to over 12.2 billion barrels to date. The AOGCC held a public hearing in June 2007 and issued a report dated July 10, 2007 regarding possible amendment of Rule 9. The AOGCC concluded that no change was necessary to Rule 9 at that time.' The PBU WIOs have continued to prepare for a PBMGS and, because of progress by participants in the Alaska LNG Project (AK LNG) and related planning by the PBU 1 Report of the Commission Inquiry Into Amending Rule 9 ("Pool Off -Take Rates"), CO 341 D, For the Prudhoe Oil Pool, Prudhoe Bay Field. • Application to Amend POP Rule 9 and Modify AIOs July 17, 2015 Page - 3 WIOs for a PBMGS, it is now appropriate for the AOGCC to amend Rule 9 to allow a greater gas off -take rate from the POP.2 B. Gas Off -Take for PBMGS The participants in AK LNG are progressing plans for an integrated LNG project, currently anticipated to start-up in 2025, consisting of a liquefaction facility and associated LNG storage and marine terminal facilities located in the Cook Inlet area, a large diameter gas pipeline approximately 800-miles in length (with gas off -take interconnection points to allow for in -state deliveries) connecting the liquefaction facility to a Gas Treatment Plant (GTP) on the North Slope, transmission lines between the GTP and producing fields, and various other associated facilities and infrastructure.3 On May 28, 2015 the U.S. Department of Energy conditionally granted authorization to AK LNG to export LNG to non -free trade agreement nations.4 The GTP is being designed by AK LNG to receive, treat, and ship gas to the Liquefaction Plant, and to send to the PBU a GTP by-product stream primarily consisting of carbon dioxide (CO2).5 The design of the AK LNG facilities is premised on maintaining an annual average gas supply rate of 3.5 bscf/d to the GTP.6 BPXA and EMAP plan to deliver part of the gas supply into the GTP from PBU (from the POP). C. Request to Increase POP Maximum Annual Average Off -take Rate There are several reasons why an amendment of Rule 9 to increase the maximum annual average gas off -take rate is being requested. Under expected normal operations of the GTP, approximately 75 percent of the gas supply (2.7 bscf/d) will be from the POP with approximately 25 percent of the gas (0.8 bscf/d) supplied from l BPXA participated in PBMGS preparations in its capacity as a PBU WIO and facilitated discussions in its capacity as PBU operator. j See AK LNG Preliminary Resource Report No. 1 at § 1.1, Docket No. PF 14-21-000 (doc. Number: USAKE-PT-SRREG-00-0001) (hereafter referred to as "Resource Report No. 1" ), available at: https://elibrga.ferc.gov/idmws/file list.asp?document id=14300991. The AK LNG project is currently undergoing pre -filing review before the Federal Energy Regulatory Commission (FERC) at Docket No. PF14-21-000. The applicants before FERC for the AK LNG project are the Alaska Gasline Development Corporation, BP Alaska LNG LLC, ConocoPhillips Alaska LNG Company, ExxonMobil Alaska LNG LLC, and TransCanada Alaska Midstream LP. See DOE/FE Order No. 3643 (FE Docket No. 14-96-LNG), available at: http://www. energy. gov/fe/downloads/order-3 643 -alaska-ing-project-llc. 5 See Resource Report No. 1 at p.15. 6 According to the current design, the GTP will have an annual average inlet gas treating capacity of up to 3.7 bscf/d, excluding planned/unplanned downtime. Id. Assuming 95% operating efficiency, the annual average gas supply requirement for the GTP is 3.5 bscf/d. 0 Application to Amend POP Rule 9 and Modify AIOs July 17, 2015 Page - 4 other sources. Under normal operations, total POP gas off -take would occur at an annual average rate of approximately 3.3 bscf/d (2.7 bscf/d to the GTP plus 0.6 bscf/d for existing fuel use and minor local gas sales). The current Rule 9 off -take rate of 2.7 bscf/d is not sufficient to meet the annual average gas off -take from the POP under those circumstances. The Commission has long acknowledged that a change to the gas off -take rate from the POP would be needed to facilitate a major gas sale. In addition to POP gas supply under normal operating conditions, if the supply of gas from other sources is not delivered as expected (or during startup of, or after gas production begins to decline from, other fields), it is possible the POP would need to be the source for up to 100 percent of the gas BPXA and other parties will each need to supply to the GTP to cover gas supply commitments. In such circumstances, the total gas off -take from the POP could be up to 4.1 bscf/d (3.5 bscf/d to the GTP adjusted for the higher COZ content of POP feed gas in comparison to the expected blended feed stream plus 0.6 bscf/d for existing fuel use and minor local sales). This application to amend Rule 9 requests an increase in the annual average off -take rate to 4.1 bscf/d to accommodate the maximum potential gas off -take from the POP in circumstances when non -POP gas supply to the GTP is not delivered as expected. D. Analysis of Increase in Gas Off -Take Upgrades to the PBU Full Field Model (FFM have been made since the AOGCC last considered POP gas off -take rates in 2007. In addition, model inputs incorporate updated production, drilling, well breakage data, and updated fuel gas algorithms. As a result of increased model resolution, other model refinements, and updated data, a greater degree of confidence in model results has been achieved regarding recovery mechanisms, well productivity, facility processing and compositional detail of -oil and gas production. Analyses of the upgraded FFM were performed and presented by the PBU WIOs to AOGCC staff in workshops during April and May of this year. BPXA's assessment of the results is set forth in the Confidential Appendix to this application. BPXA believes that amendment of Rule 9 to allow a maximum annual average gas off -take rate of 4.1 bscf/d for the POP is consistent with good oilfield engineering practices, and appropriate action for the Commission to take. E. Timing for AOGCC Decision Amendment of Rule 9 is being requested at this time in consideration of current actions by the State of Alaska and the AK LNG parties, including BPXA's affiliate BP Alaska LNG LLC and EMAP's affiliate ExxonMobil Alaska LNG LLC, to progress the AK LNG project to the front- end engineering and design (FEED) development stage (which effort involves the expenditure of billions of dollars). To move to the FEED stage of project activity, a number of project -enabling 7 Resource Report No. 1 at 16, 18-19.Current GTP design contemplates that 25% of the supply into the facility will be gas delivered from the Point Thomson Unit. Application to Amend POP Rule 9 and Modify AIOs July 17, 2015 Page - 5 actions have been identified.$ Amendment of Rule 9 to allow the flexibility to supply both ordinary and full feed gas rates to the GTP from PBU supports those activities. BPXA is requesting that the AOGCC render a decision by October 15, 2015 to facilitate those project - enabling actions. II. MODIFICATION OF AIOS A. Introduction As addressed in Sections I.A-.B above (incorporated into this request by reference), the GTP is being designed to receive, treat and ship gas to the liquefaction facility, and to return CO2 by- product to the PBU for injection. Gas will be received from multiple fields, including the POP at PBU. Similar to the requested amendment of Rule 9 addressed above, the requested modifications to the AIOs are being requested at this time to support the joint efforts of the State of Alaska and the AK LNG parties to progress the Alaska LNG Project to FEED development stage. As more specifically addressed below, modifications of the AIOs are based upon the Alaska LNG project design plan for re -injection of the GTP CO2 by-product into the POP. B. Request to Authorize Injection of CO2 1. Injection of CO2 by-product After treatment of feed gas at the GTP, the Alaska LNG Project design is to return CO2 by- product, which is greater than 99% dry CO2, to the Prudhoe Bay Unit for injection.9 BPXA's assessment is that PBMGS will enable an additional hydrocarbon recovery benefit of approximately 3.8 billion barrels of oil equivalent from the PBU, of which the injection of CO2 in the POP is a key step. BPXA's analysis and assumptions regarding CO2 injection is set forth in the Confidential Appendix to this application. Please refer to the Confidential Appendix for information provided to the Commission in support this application, pursuant to 20 AAC 25.402. 8 See Heads of Agreement for the Alaska LNG Project (Jan. 14, 2014). 9 Resource Report No. 1. Application to Amend POP Rule 9 and Modify AIOs July 17, 2015 Page - 6 2. Modification of AIOs to authorize injection of GTP CO2 by-product will not allow or increase the risk of movement of fluids into sources of freshwater or underground drinking water Within the PBU, there are no subsurface sources of freshwater. Aquifer Exemption Order 1 states that all portions of aquifers lying directly below the Western Operating and K Pad areas of the Prudhoe Bay Unit are exempted for Class II injection activities. Based on data submitted to AOGCC, Finding 5 of AIO 4 covering the Eastern Operating Area states that "injection into, though, or above a fresh water aquifer or underground source of drinking water will not occur." The AIOs only authorize injection into an authorized injection strata. The orders contain requirements for periodic mechanical integrity testing and monitoring injection wells. Should a lack of injection zone isolation be indicated, the operator must notify the AOGCC and submit a plan of corrective action. The well must be shut-in if freshwater were threatened. As noted earlier in this Application, injection of PBU CO2 into the POP (as part of authorized PBU gas cycling operations) is already allowed by the Commission, and this request simply requests authorization for the injection of incremental CO2 from gas supplied to the GTP from other reservoirs. B. Requested modifications to AIOs BPXA requests, pursuant to 20 AAC 25.410(h), that the Commission approve the following modifications to the referenced Rule in each of the AIOs (requested modifications in bold and underlined text): 1. AREA INJECTION ORDER 3A (PRUDHOE OIL POOL) Rule 1. Authorized Injection Strata and Fluids for Enhanced Recovery Within the affected area and in the strata defined as those strata which correlate with the strata found in ARCO Alaska Inc. (Atlantic -Richfield -Humble) Prudhoe Bay State Well No. 1 between the measured depths of 8110 feet and 8680 feet the following fluids may be injected for purposes of pressure maintenance and enhanced oil recovery: a) Produced water and gas from Prudhoe Bay Unit processing facilities; b) CO2 and other GTP effluent gases from sources within or outside the Prudhoe Bay Unit; Enriched hydrocarbon gas; ed) Non -hazardous water and water based fluids - (specifically seawater, source water, freshwater, domestic wastewater, equipment washwater, sump fluids, hydrotest fluids, firewater, and water with trace chemicals, and other water based fluids with a pH greater than 2 and less than 12.5 and flashpoint greater than 140 degrees F); 9 • Application to Amend POP Rule 9 and Modify AIOs July 17, 2015 Page - 7 de) Fluids introduced to production facilities for the purpose of oil production, plant operations, plant/piping integrity or well maintenance that become entrained in the produced water stream after oil, gas, and water separation in the facility. Specifically: i. Freeze protection fluids; ii. Fluids in mixtures of oil sent for hydrocarbon recycle; iii. Corrosion/scale inhibitor fluids; iv. Anti-foams/emulsion breakers; v. Glycols; vi. Radioactive tracer survey fluids eef Non -hazardous glycols and glycol mixtures; W Fluids that are used for their intended purpose within the oil production process. Specifically: i. Scavengers; ii. Biocides gh) Fluids to monitor or enhance reservoir performance. Specifically: i. Tracer survey fluids; ii. Well stimulation fluids; iii. Reservoir profile modification fluids. 2. AREA INJECTION ORDER 4F (PRUDHOE OIL POOL, PUT RIVER OIL POOL, LISBURNE OIL POOL. PT. MCINTYRE OIL POOL, WEST BEACH OIL POOL, AND STUMP ISLAND OIL POOL) Rule 1 Authorized Injection Strata and Fluids for Enhanced Recovery Within the affected area and the following strata: The Prudhoe Oil Pool strata defined as (i) the accumulations of oil that are common to and that correlate with the accumulations found in the Atlantic Richfield -Humble Prudhoe Bay State No. 1 well between the depths of 8,110 feet and 8,680 feet, and (ii) the accumulation of oil that is common to and correlates with the interval from 9,638 to 9,719 measured feet on the Borehole Compensated Sonic Log, Run 2, dated September 28, 1975, in the Atlantic Richfield -Exxon NGI No. 1 well, and that is in hydraulic communication with the gas cap of the former accumulations in the Sag River Formation. The latter accumulation is found within the following area: Umiat Meridian. T11N R14E: Sections: 1, 2, 11(N/2 and SE/4), 12, 13, 14(E/2), 23(NE/4), 24, 25(N/2); T11N R15E: Sections: 6, 7, 8, 17, 18, 19, 20, 29(N/2), 30(N/2); T12N R14E: Sections 35, 36 The Put River Oil Pool strata are defined as the sandstone reservoirs within the Southern, Central and Western lobes of the Put River Sandstone Member (PRS) of the Kalubik Formation that correlate with the interval 9,638 to 9,719 measured feet on the Borehole Compensated Sonic Log, Run 2--dated September 28, 1975--in the Atlantic Richfield - Exxon NGI No. I well, but excluding the PRS Northern Lobe reservoirs that are in • • Application to Amend POP Rule 9 and Modify AIOs July 17, 2015 Page - 8 pressure communication with the Prudhoe Oil Pool gas cap in the Sag River Formation. The Put River Oil Pool is found within the following area: Umiat Meridian. Tl 1N R14E Sections: 3, 4, 9, 10, 11(SW/4), 14(W/2), 15, 16, 21, 22, 23(W/2 and SE/4), 25(S/2), 26, 27, 28, 33, 34, 35, 36; T11N RI5E Sections: 29(S/2), 30(S/2), 31, 32; T10N R14E Sections: 1, 2, 3, 11, 12, 13, 14; T10N R15E Sections: 5, 6, 7, 8, 17, 18 The Lisburne Oil Pool strata correlate with and are common to the formations found in the ARCO Prudhoe Bay State No. 1 well between the measured depths of 8, 790-10,440. The Pt. Mcintyre Oil Pool strata correlate with and are common to the formations found in the Pt. Mcintyre No. 11 well between the measured depths of 9,908- 10,665 feet. The West Beach Oil Pool strata correlate with and are common to the formations found in the West Beach No.4 well between the measured depths of 14,458- 14,781 feet. The Stump Island Oil Pool enhanced recovery plans will be evaluated on a well - by -well basis in conjunction with Pt. Mcintyre Oil Pool development. The following fluids may be injected for pressure maintenance and enhanced recovery purposes: a) Produced water and gas from PBU processing facilities; b) CO2and other GTP effluent gases from sources within or outside the Prudhoe Bay Unit; hc) Enriched hydrocarbon gas; eA) Non -hazardous water and water based fluids -(specifically seawater, source water, freshwater, domestic wastewater, equipment washwater, sump fluids, hydrotest fluids, firewater, and water with trace chemicals, and other water based fluids with a pH greater than 2 and less than 12.5 and flashpoint greater than 140 degrees F); de) Fluids introduced to production facilities for the purpose of oil production, plant operations, plant/piping integrity or well maintenance that become entrained in the produced water stream after oil, gas, and water separation in the facility. Specifically: i. Freeze protection fluids; ii. Fluids in mixtures of oil sent for hydrocarbon recycle; iii. Corrosion/scale inhibitor fluids; iv. Anti-foams/emulsion breakers; v. Glycols 0 • Application to Amend POP Rule 9 and Modify AIOs July 17, 2015 Page - 9 efJ' Non -hazardous glycols and glycol mixtures; €g) Fluids that are used for their intended purpose within the oil production process. Specifically: i. Scavengers; ii. Biocides gh) Fluids to monitor or enhance reservoir performance. Specifically: i. Tracer survey fluids; ii. Well stimulation fluids; iii. Reservoir profile modification fluids. III. SUPPORTING INFORMATION This application provides comprehensive information and support for approval of the requested amendment of Rule 9 maximum annual average gas off -take rate for the POP to 4.1 bscf/d, as well as modification of the AIOs. Mr. Bruce Laughlin, as testifying witness, will be present at, and made available to, the AOGCC for questions at the public hearing with respect to this application. Depending upon the testimony, if any, presented by others at the public hearing, BPXA reserves the right to present additional testimony at the public hearing, or by post -hearing submission if so authorized by the Commission. IV. CONCLUSION Based upon this application, BPXA requests that the AOGCC: (i) amend Rule 9 of CO 341D to establish a maximum annual average gas off -take rate of 4.1 bscf/d for the POP; and (ii) modify AIO 3A.002 and AIO 4F to authorize injection of CO2 from the PBU and other sources for the purposes of enhanced oil and gas recovery, and pressure maintenance. Please contact John Dittrich at 907-564-5075 if the Commissioners or AOGCC staff have any questions or clarification regarding this application. BPXA is represented in this matter by George Lyle of Guess & Rudd, 510 L Street, Suite 700, Anchorage, AK 99501, 907-793-2222. Please direct communications regarding procedural matters, including the pre -hearing and public hearing, to Mr. Lyle. We sincerely appreciate the time and attention of the Commissioners and the AOGCC staff to this application. Si rely, Dave P. Lachance C' Vice President, Reservoir Development Attachment cc: George Lyle