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Home My WebLink AboutCO822CONSERVATION ORDER 822 Minke Oil Pool Colville River Unit North Slope Borough, Alaska 1. September 26, 2024 CPAI Application for Minke Oil Pool and Pilot Injection 2. October 7, 2024 AOGCC notice of public hearing 3. November 19, 2024 Public hearing presentation, transcripts, and supplemental Information 4. December 5, 2024 CPAI request for extension on hearing supplemental filing 5. December 20, 2024 CPAI Response to Requests From Hearing 6. February 6, 2025 CPAI Amendment to Application for Minke Oil Pool and Pilot Injection 7. March 17, 2025 CPAI request for reconsideration (CO 822 Amended) STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION 333 West 7th Avenue Anchorage, Alaska 99501 Re: THE APPLICATION OF ConocoPhillips Alaska, Inc. for an order establishing pool rules for the Minke Oil Pool in the Colville River Unit ) ) ) ) ) ) ) ) Docket Number: CO 24-012 Conservation Order No. 822 Minke Oil Pool Colville River Unit North Slope Borough, Alaska February 26, 2025 IT APPEARING THAT: 1. By application received September 26, 2024, ConocoPhillips Alaska, Inc. (CPAI), as operator of the Colville River Unit (CRU), requested an order establishing pool rules for the proposed Minke Oil Pool (MOP). Concurrent to this application CPAI also submitted an application for an Enhanced Recovery Injection Order to authorize a pilot injection project for the MOP. 2. Pursuant to 20 AAC 25.540, the Alaska Oil and Gas Conservation Commission (AOGCC) scheduled a public hearing for November 19, 2024. On October 8, 2024, 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 to all persons on the AOGCC’s mailing distribution list. On October 9, 2024, the notice was also published in the Anchorage Daily News. 3. No public comments were received on the application. 4. The hearing commenced at 10:00 a.m. on November 19, 2024. Testimony was received from representatives of CPAI. At the conclusion of the hearing the record was held open until December 6, 2024 for CPAI to respond to questions/requests made during the hearing. 5. On December 5, 2024, CPAI asked for and was granted a two-week extension, which held the record open until December 20, 2024. 6. CPAI submitted their response on December 20, 2024. The AOGCC’s decision is based on CPAI’s application, testimony, and supplemental information submitted after the hearing before the record closed. FINDINGS: 1. Owner and Landowners: CPAI is the operator and sole working interest owner of the CRU and proposed Minke development. Surface owners are Kuukpik Corporation and the United States Department of the Interior Bureau of Land Management. 2. Operator: CPAI is operator of all the leased acreage in the proposed Affected Area. CO 822 February 26, 2025 Page 2 of 13 3. Affected Area: CPAI is proposing that the affected area encompass a portion of the CRU that extends beyond the Minke Participating Area established by the Alaska Department of Natural Resources Division of Oil and Gas (see Figure 1 below). The proposed Affected Area is contained completely within the confines of the CRU and does not border any non- CRU lands 4. Exploration, Delineation, and Development History: Numerous wells drilled from the CRU CD5 drillsite and exploratory ice pads have penetrated the proposed MOP. Initially this interval was not considered to be a significant hydrocarbon bearing zone. In January 2024, CPAI drilled CRU CD5-32X (PTD 223-109, API No. 50-103-20871-00-00) as a dedicated MOP exploration well, which demonstrated the existence of this resource. CO 822 February 26, 2025 Page 3 of 13 Figure 1. Proposed Minke Oil Pool and Enhanced Recovery Injection Order Affected Areas (Source: ConocoPhillips Alaska, Inc.) CO 822 February 26, 2025 Page 4 of 13 5. Pool Identification: As proposed, the MOP is a part of the Cretaceous-aged Brookian Nanushuk Formation (Nanushuk). The Nanushuk was deposited in a shallow marine to upper slope setting in the Colville Foreland. The “topset” Nanushuk strata form a series of eastward prograding deltaic, shoreface, and uppermost slope sediments. The time- equivalent middle slope, lower slope, and basin floor sediments are grouped into the Torok Formation (Torok). The proposed MOP and injection interval are the accumulation of hydrocarbons common to and correlating with that portion of the Nanushuk in well CRU CD5-22 (PTD No. 217-089, API No. 50-103-20759-00-00) between 5,222 and 6,433 feet measured depth (MD) or 4,333 to 5,194 feet true vertical depth subsea (TVDSS). (See Figure 2.) CO 822 February 26, 2025 Page 5 of 13 Figure 2. CRU CD5-22 Reference log (Source: ConocoPhillips Alaska, Inc.) CO 822 February 26, 2025 Page 6 of 13 6. Relationship to Other Nanushuk Developments: The proposed MOP is part of the same, thick Nanushuk progradational sequence, but is not in communication with, the Nanushuk Oil Pool in the Pikka Unit, the Qannik Oil Pool in the CRU, the Coyote Oil Pool in the Kuparuk River Unit, and the proposed Willow development in the Bear Tooth Unit. 7. Geology: A. Stratigraphy: CPAI’s proposed injection interval is part of a generally west-to-east progradational system that is elongate in a northeast to southwest direction. The MOP was deposited in a delta- front to distal delta-front environment. Since net-to-gross ratio and grain size generally decrease with depositional depth, and the highest quality reservoir is located in the upper portion of the formation. The MOP is thinly bedded throughout and comprised of very fine- grained sandstones, siltstones, and mudstones. The pool thins to the west and thickens to the east. There is a presumed oil water contact at 4,400 feet TVDSS which, combined with the degrading reservoir quality with depth, limits the proposed development to approximately the upper 100 feet of the proposed pool. Core recovered from CRU CD5- 32X indicates porosity is 17-25%, air permeability is 1-114 md, and water saturation is 15- 58%. The fracture gradient of the MOP is 0.58 psi/ft B. Trap and Structure: The MOP is a combined structural-stratigraphic trap that has an up-dip pinch out to the west and south, shales out and dips below the presumed oil-water contact to the east and north, and has an average dip of ~1-2 degrees. Faulting within the proposed pool is very limited. C. Permafrost Base: The base of permafrost is interpreted to be between approximately 1,100 and 1,300 feet TVDSS. D. Upper Confining Interval: Upper confinement will be provided by a flooding shale within the Nanushuk that is 50 to more than 200 feet true vertical thickness (TVT) across the project area. Data show that the fracture gradient of the upper confining interval is greater than or equal to 0.7 psi/ft. E. Lower Confining Interval: Lower confinement will be provided by more than 300 feet TVT of mud-dominated Torok Formation (Torok) sediments deposited in a slope setting. Data show that the fracture gradient of the lower confining interval is greater than or equal to 0.7 psi/ft. 8. Reservoir Fluid Contacts: There is a presumed oil-water contact estimated to be located at 4,400 feet TVDSS. CO 822 February 26, 2025 Page 7 of 13 9. Reservoir Fluid Properties: CPAI provided the following reservoir fluid properties at a datum of 4,320 feet TVDSS from samples collected in CRU CD5-32X. Property Value Initial Reservoir Pressure (psia) 1,990 Reservoir Temperature (°F) 106 Stock Tank Oil API Gravity (°) 34.8 Gas-Oil Ratio (SCF/STB) 424 Bubble Point Pressure, Pb (psi) 1,734 Oil Formation Factor at Pb (RB/STB) 1.2 Oil Viscosity at Pb (cP) 2.17 Gas Formation Factor at Pb (RB/MSCF) at Saturation Pressure 1.5 10. In-Place and Recoverable Reserves Volumes: Reservoir Volumes Range (MMSTBO) Original Oil in Place (OOIP) in Proposed MOP 80-150 Primary Recovery (5-10% OOIP) 4-15 Primary + Waterflood (20-30% OOIP) 16-45 Primary + Water Alternating Gas Under Evaluation 11. Reservoir Development Drilling Plan: CPAI plans to initially drill a three-well pilot project (two injectors and one producer) to determine the optimal design for a full field development of the MOP. Subject to revision pending the results of the pilot project, CPAI plans a full-scale development of the MOP from the CRU CD5 drill site would consist of an estimated 9 horizontal multi-stage fracture-stimulated producers and 8 horizontal multi- stage fracture-stimulated injectors in a line drive pattern waterflood with the possibility of employing water-alternating-gas (WAG) injection. The pilot project wells are planned to be drilled on an inter-well spacing of 1,250 feet to evaluate pressure communication between injectors and producers at that distance. Upon completion of this pilot project and other evaluations, CPAI will expand development to the full pool adjusting the current plan as required based on the pilot project results. Wells will trend southeast to northwest to generally align with the maximum principal stress direction to improve waterflood performance. Wells will have horizontal sections of 4,000 to 10,000 feet in length. 12. Design of Wells: Development wells will be of a two- or three-string design with surface casing set below the C40 marker and cemented to surface. In three-string wells intermediate casing will be set below the top of the Minke sand at approximately 85 degrees. In two-string wells the crossover between 7-5/8” and 4-1/2” casing will occur at approximately the same depth. Both designs will be cemented to a minimum of 500 feet MD or 250 feet TVD, whichever is greater, above the casing shoe or casing crossover. The wells will be completed with cemented or uncemented casing/liners with frac sleeves to CO 822 February 26, 2025 Page 8 of 13 facilitate multistage hydraulic fracturing. It is anticipated the wells will be completed with 4-1/2” tubing. 13. Reservoir Management: CPAI plans to conduct the pilot project portion of the development as a waterflood utilizing produced water from the CRU and Greater Moose’s Tooth Unit (GMTU) and Beaufort Seawater from the Oliktok Point Seawater Treatment Plant. The target voidage replacement ratio is 1.0. Future development may include WAG injection. 14. Reservoir Surveillance Plans: CPAI proposes the following reservoir surveillance plan: a. Static bottom-hole pressure surveys will be conducted in all new injection wells prior to initiating injection. b. Static surveys will be performed on production wells at the discretion of CPAI, or as directed by the AOGCC. c. For annual pressure surveillance, a minimum of one (1) pressure survey will be conducted annually in the MOP. d. In lieu of stabilized bottom-hole pressure measurements, the alternative pressure survey methods below can be implemented: i. Open-hole wireline formation fluid pressure measurements, ii. Cased-hole pressure buildups with bottom-hole pressure measurement, iii. Injector surface pressure fall-off, iv. Readings from permanent downhole pressure/temperature gauges, v. Static pressure surveys following extended shut-in periods, or vi. Bottom-hole pressures calculated from wellhead pressure and fluid levels in the tubing of a stabilized shut-in injector e. All pressure surveys will be reported annually, rather than monthly, to reduce paperwork due to the limited number of surveys. 15. Datum Depth: The top of the pool extends between approximately 4,150 feet TVDSS and 4,950 feet TVDSS. 4,320 feet TVDSS will be a representative target depth since the estimated oil-water contact depth is approximately 4,400 feet TVDSS. 16. Metering and Measurement Processes: Production from the MOP will be commingled at the surface with production from other CRU and GMTU pools and from future pools that may be processed through the Alpine Central Facility. Well testing and allocation meters will be installed and maintained according to industry recommended practices and wells will be tested at least twice per month. 17. Waivers: CPAI requested the following waivers: a. Wellbore Surveys: in lieu of the requirements of 20 AAC 25.050(b), CPAI proposes submitting the following information with permit to drill applications: i. Plan view, ii. Vertical section, CO 822 February 26, 2025 Page 9 of 13 iii. Close approach data, and iv. Directional data b. Well Spacing: The interwell spacing restrictions of 20 AAC 25.055 be waived for development wells in the proposed MOP to accommodate horizontal, line-drive wells and maximize ultimate recovery. The property line offset regulations in 20 AAC 25.055 would remain in effect. c. Logs and Geologic Data: CPAI requests that the requirements of 20 AAC 25.071(a) only apply to one well from the CRU CD5 drill site and be waived for all other MOP wells. These requirements have already been satisfied because a number of wells in the area have been drilled and logged. Additional data will not significantly add to the geologic knowledge for this area. d. Workover Operations: CPAI requests that the MOP be included in the existing order CO 735 that governs workover operations on CPAI operations. 18. Interwell Spacing Requirements: Effective September 27, 2022, the statute governing interwell spacing was changed and interwell spacing requirements were eliminated. However, property line setback requirements were unchanged. (See AOGCC Industry Guidance Bulletin 22-002). CONCLUSIONS: 1. Establishing pool rules for the MOP is appropriate and will aid in the efficient development of the field while not promoting waste and protecting correlative rights and freshwater. 2. A waiver of the requirements of 20 AAC 25.050(b) is commonly granted to simplify the permit to drill application and review process and is appropriate for the MOP. 3. The interwell spacing requirements of 20 AAC 25.055 are no longer supported by Alaska Statutes and are therefore unenforceable. (See AOGCC Industry Guidance Bulletin 22- 002). CPAI’s requested waiver of the interwell spacing regulation is unnecessary. The offset from property lines requirements, which is 500 feet for oil wells, are still in place. 4. A waiver of the logging requirements of 20 AAC 25.071(a) is appropriate for the MOP. 5. Applying CO 735 to the MOP is appropriate to ensure all pools in the CRU have the same rules regarding when a sundry permit/report is required. NOW THEREFORE IT IS ORDERED: Development and operation of the Minke Oil Pool is subject to the following rules and the statewide requirements under 20 AAC 25 to the extent not superseded by these rules: CO 822 February 26, 2025 Page 10 of 13 Affected Area: Umiat Meridian (See Figure 1) Township 10 North, Range 3 East Sections 1: N/2 NE/4 Township 11 North, Range 3 East Section 1: E/2 & SW/4 Section 11: E/2E/2 Sections 12&13: all Section 14: E/2 & SE/4SW/4 Section 23: E/2, E/2W/2, SW/4NW/4, & NW/4SW/4 Sections 24 & 25: all Section 26: Ne/4, N/2SE/4, SE/4SE/4, & NE/4NW/4 Section 35: NE/4NE/4 Section 36 N/2, SE/4, N/2SW/4, and SE/4SW/4 Township 11 North, Range 4 East Section 5: N/2, SW/4, N/2SE/4, & SW/4SE/4 Sections 6 & 7: all Section 8: W/2, w/2NE/4, & NW/4SE/4 Section 17: W/2W/2 Section 18: all Section 19: N/2, SW/4, N/2SE/4, & SW/4SE/4 Section 20: NW/4NW/4 Section 30: W/2 & W/2NE/4 Section 31: N/2NW/4 & SW/4NW/4 Township 12 North, Range 3 East Section 36: E/2SE/4 Township 12 North, Range 4 East Section 19: E/2 Section 20: W/4NW/4, W/2SW/4, & SE/4SW/4 Section 29: W/2, SW/4NE/4, W/2SE/4, & SE/4SE/4 Section 30: E/2, SE/4NW/4, & E/2SW/4 Section 31: E/2, SW/4, E/2NW/4, & SW/4NW/4 Section 32: all Section 33: W/2NW/4 & NW/4SW/4 CO 822 February 26, 2025 Page 11 of 13 Rule 1 Field and Pool Name The field is the Colville River Field, and the pool is the Minke Oil Pool. Rule 2 Pool Definition The Minke Oil Pool is defined as the accumulation of oil and gas common to and correlating with the interval within the CRU CD5-22 well between the depths of 5,222 and 6,433 feet MD (4,333 and 5,194 feet TVDSS). (See Figure 2, above.) Rule 3 Gas Oil Ratio Exemption Wells producing from the Minke Oil Pool are exempt from the gas-oil ratio limitations set forth in 20 AAC 25.240 so long as there is an active enhanced oil recovery injection project. Rule 4 Drilling and Completion Practices A. Alternate casing and completion programs, in addition to those specified in 20 AAC 25, may be administratively approved by the AOGCC upon application and presentation of data that demonstrate the alternatives are appropriate and based upon sound engineering principles. B. In lieu of the requirements under 20 AAC 25.050(b) permit to drill applications shall include: a. Plan view, b. Vertical section, c. Close approach data, and d. Directional plan. C. The requirements of 20 AAC 25.071(a) have already been satisfied for the CRU CD5 drill site. For the MOP, the AOGCC may specify which types of logs are to be run on a well- by-well basis. Rule 5 Automatic Shut-In Equipment a. Double check valve arrangement, or b. Single check valve and a surface safety valve (SSV). A sub-surface-controlled injection valve (SCSSV) satisfies the requirements of a single check valve. Rule 6 Well Spacing The interwell spacing requirements of 20 AAC 25.055(a)(3) and (4) and 20 AAC 25.055(b) and (c) are no longer supported by an underlying statute and as such are unenforceable. The property line offset requirements of 20 AAC 25.055(a)(1) and (2) remain in effect. Rule 7 Reservoir Surveillance a. Static bottom-hole pressure surveys will be conducted in all new injection wells prior to initiating injection. b. Static surveys will be performed on production wells at the discretion of CPAI. CO 822 February 26, 2025 Page 12 of 13 c. In lieu of stabilized bottom-hole pressure measurements, the alternative pressure survey methods below can be implemented: a. Open-hole wireline formation fluid pressure measurements, b. Cased-hole pressure buildups with bottom-hole pressure measurement, c. Injector surface pressure fall-off, d. Static pressure surveys following extended shut-in periods, or e. Bottom-hole pressures calculated from wellhead pressure and fluid levels in the tubing of a stabilized shut-in injector. d. All pressure surveys will be reported annually, rather than monthly, to reduce paperwork due to the limited number of surveys. e. The datum depth for pressure surveys shall be 4,320 feet TVDSS. f. The Minke Oil Pool shall be included in the annual reservoir surveillance report submitted for the Colville River Unit. Rule 8 Workover Operations Conservation Order No. 735 shall apply to the Minke Oil Pool. Rule 9 Sustained Casing Pressure for Production Wells a. At the time of installation or replacement, the operator shall conduct and document a pressure test of tubulars and completion equipment in each production well that is sufficient to demonstrate that planned well operations will not result in failure of well integrity, uncontrolled release of fluid or pressure, or threat to human safety. b. The operator shall monitor each production well daily to check for sustained pressure, except if prevented by extreme weather conditions, emergency situations, or unavoidable circumstances. Monitoring results shall be kept available for AOGCC inspections. c. The operator shall notify the AOGCC within three working days after the operator identifies a well as having: (i) sustained inner annulus pressure that exceeds 2,000 pounds per square inch gauge (psig) for all production wells, or (ii) sustained outer annulus pressure that exceeds 1,000 psig. d. If the operator identifies sustained pressure in the inner annulus of a production well that exceeds 45 percent of the burst pressure rating of the well’s production casing for inner annulus pressure, or sustained pressure in the outer annulus that exceeds 45 percent of the burst pressure rating of the well’s surface casing for outer annulus pressure, the operator shall notify the AOGCC within three working days and take corrective action. Unless well conditions require the operator to take emergency corrective action before AOGCC approval can be obtained, the operator shall submit in an Application for Sundry Approvals (Form 10-403) a proposal for corrective action. The AOGCC may approve the operator’s proposal or require other corrective action, including a mechanical integrity test or other diagnostic tests. The operator shall give the AOGCC sufficient notice of the testing schedule to allow the AOGCC to witness the tests. CO 822 February 26, 2025 Page 13 of 13 e. Except as otherwise approved by the AOGCC under (d) of this rule, before a shut-in well is placed in service, any annulus pressure must be relieved to a sufficient degree: (1) that the inner annulus pressure at operating temperature will be below 2,000 psig, and (2) that the outer annulus pressure at operating temperature will be below 1,000 psig. A well subject to (c) but not (d) of this rule may reach an annulus pressure at operating temperature that is described in the operator’s notification to the AOGCC under (c) of this rule, unless the AOGCC prescribes a different limit. f. For purposes of this rule, i. “inner annulus” means the space in a well between tubing and production casing; ii. “outer annulus” means the space in a well between production casing and surface casing; and iii. “sustained pressure” means pressure that (A) is measurable at the casing head of an annulus, (B) is not caused solely by temperature fluctuations, and (C) has not been applied intentionally. DONE at Anchorage, Alaska and dated February 26, 2025. Jessie L. Chmielowski Gregory C. Wilson Commissioner Commissioner RECONSIDERATION AND APPEAL NOTICE As provided in AS 31.05.080(a), within 20 days after written notice of the entry of this order or decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration of the matter determined by it. If the notice was mailed, then the period of time shall be 23 days. An application for reconsideration must set out the respect in which the order or decision is believed to be erroneous. The AOGCC shall grant or refuse the application for reconsideration in whole or in part within 10 days after it is filed. Failure to act on it within 10-days is a denial of reconsideration. If the AOGCC denies reconsideration, upon denial, this order or decision and the denial of reconsideration are FINAL and may be appealed to superior court. The appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision denying reconsideration, UNLESS the denial is by inaction, in which case the appeal MUST be filed within 40 days after the date on which the application for reconsideration was filed. If the AOGCC grants an application for reconsideration, this order or decision does not become final. Rather, the order or decision on reconsideration will be the FINAL order or decision of the AOGCC, and it may be appealed to superior court. That appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision on reconsideration. In computing a period of time above, the date of the event or default after which the designated period begins to run is not included in the period; the last day of the period is included, unless it falls on a weekend or state holiday, in which event the period runs until 5:00 p.m. on the next day that does not fall on a weekend or state holiday. Gregory C. Wilson Digitally signed by Gregory C. Wilson Date: 2025.02.26 08:20:13 -09'00' Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2025.02.26 08:32:58 -09'00' From:Coldiron, Samantha J (OGC) To:AOGCC_Public_Notices Subject:[AOGCC_Public_Notices] Enhanced Recovery Injection Order 9 and Conservation Order 822 (CPAI) Date:Wednesday, February 26, 2025 2:08:04 PM Attachments:ERIO9.pdf CO822.pdf THE APPLICATION OF ConocoPhillips Alaska, Inc. for an order authorizing underground injection of fluids for a pilot enhanced oil recovery project in the Colville River Unit, Minke Oil Pool THE APPLICATION OF ConocoPhillips Alaska, Inc. for an order establishing pool rules for the Minke Oil Pool in the Colville River Unit 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 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION 333 West 7th Avenue Anchorage, Alaska 99501 Re: THE APPLICATION OF ConocoPhillips Alaska, Inc. for an order establishing pool rules for the Minke Oil Pool in the Colville River Unit ) ) ) ) ) ) ) ) ) Docket Number: CO 24-012 Conservation Order 822 Amended Minke Oil Pool Colville River Unit North Slope Borough, Alaska April 23, 2025 Nunc pro tunc February 26, 2025 IT APPEARING THAT: 1. By application received September 26, 2024, ConocoPhillips Alaska, Inc. (CPAI), as operator of the Colville River Unit (CRU), requested an order establishing pool rules for the proposed Minke Oil Pool (MOP). Concurrent to this application CPAI also submitted an application for an Enhanced Recovery Injection Order to authorize a pilot injection project for the MOP. 2. Pursuant to 20 AAC 25.540, the Alaska Oil and Gas Conservation Commission (AOGCC) scheduled a public hearing for November 19, 2024. On October 8, 2024, 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 to all persons on the AOGCC’s mailing distribution list. On October 9, 2024, the notice was also published in the Anchorage Daily News. 3. No public comments were received on the application. 4. The hearing commenced at 10:00 a.m. on November 19, 2024. Testimony was received from representatives of CPAI. At the conclusion of the hearing the record was held open until December 6, 2024 for CPAI to respond to questions/requests made during the hearing. 5. On December 5, 2024, CPAI asked for and was granted a two-week extension, which held the record open until December 20, 2024. 6. CPAI submitted their response on December 20, 2024. The AOGCC’s decision is based on CPAI’s application, testimony, and supplemental information submitted after the hearing before the record closed. FINDINGS: 1. Owner and Landowners: CPAI is the operator and sole working interest owner of the CRU and proposed Minke development. Surface owners are Kuukpik Corporation and the United States Department of the Interior Bureau of Land Management. 2. Operator: CPAI is operator of all the leased acreage in the proposed Affected Area. CO 822 Amended April 23, 2025 Nunc pro tunc February 26, 2025 Page 2 of 13 3. Affected Area: CPAI is proposing that the affected area encompass a portion of the CRU that extends beyond the Minke Participating Area established by the Alaska Department of Natural Resources Division of Oil and Gas (see Figure 1 below). The proposed Affected Area is contained completely within the confines of the CRU and does not border any non- CRU lands 4. Exploration, Delineation, and Development History: Numerous wells drilled from the CRU CD5 drillsite and exploratory ice pads have penetrated the proposed MOP. Initially this interval was not considered to be a significant hydrocarbon bearing zone. In January 2024, CPAI drilled CRU CD5-32X (PTD 223-109, API No. 50-103-20871-00-00) as a dedicated MOP exploration well, which demonstrated the existence of this resource. CO 822 Amended April 23, 2025 Nunc pro tunc February 26, 2025 Page 3 of 13 Figure 1. Proposed Minke Oil Pool and Enhanced Recovery Injection Order Affected Areas (Source: ConocoPhillips Alaska, Inc.) CO 822 Amended April 23, 2025 Nunc pro tunc February 26, 2025 Page 4 of 13 5. Pool Identification: As proposed, the MOP is a part of the Cretaceous-aged Brookian Nanushuk Formation (Nanushuk). The Nanushuk was deposited in a shallow marine to upper slope setting in the Colville Foreland. The “topset” Nanushuk strata form a series of eastward prograding deltaic, shoreface, and uppermost slope sediments. The time- equivalent middle slope, lower slope, and basin floor sediments are grouped into the Torok Formation (Torok). The proposed MOP and injection interval are the accumulation of hydrocarbons common to and correlating with that portion of the Nanushuk in well CRU CD5-22 (PTD No. 217-089, API No. 50-103-20759-00-00) between 5,222 and 6,433 feet measured depth (MD) or 4,333 to 5,194 feet true vertical depth subsea (TVDSS). (See Figure 2.) CO 822 Amended April 23, 2025 Nunc pro tunc February 26, 2025 Page 5 of 13 Figure 2. CRU CD5-22 Reference log (Source: ConocoPhillips Alaska, Inc.) CO 822 Amended April 23, 2025 Nunc pro tunc February 26, 2025 Page 6 of 13 6. Relationship to Other Nanushuk Developments: The proposed MOP is part of the same, thick Nanushuk progradational sequence, but is not in communication with, the Nanushuk Oil Pool in the Pikka Unit, the Qannik Oil Pool in the CRU, the Coyote Oil Pool in the Kuparuk River Unit, and the proposed Willow development in the Bear Tooth Unit. 7. Geology: A. Stratigraphy: CPAI’s proposed injection interval is part of a generally west-to-east progradational system that is elongate in a northeast to southwest direction. The MOP was deposited in a delta- front to distal delta-front environment. Since net-to-gross ratio and grain size generally decrease with depositional depth, and the highest quality reservoir is located in the upper portion of the formation. The MOP is thinly bedded throughout and comprised of very fine- grained sandstones, siltstones, and mudstones. The pool thins to the west and thickens to the east. There is a presumed oil water contact at 4,400 feet TVDSS which, combined with the degrading reservoir quality with depth, limits the proposed development to approximately the upper 100 feet of the proposed pool. Core recovered from CRU CD5- 32X indicates porosity is 17-25%, air permeability is 1-114 md, and water saturation is 15- 58%. The fracture gradient of the MOP is 0.58 psi/ft B. Trap and Structure: The MOP is a combined structural-stratigraphic trap that has an up-dip pinch out to the west and south, shales out and dips below the presumed oil-water contact to the east and north, and has an average dip of ~1-2 degrees. Faulting within the proposed pool is very limited. C. Permafrost Base: The base of permafrost is interpreted to be between approximately 1,100 and 1,300 feet TVDSS. D. Upper Confining Interval: Upper confinement will be provided by a flooding shale within the Nanushuk that is 50 to more than 200 feet true vertical thickness (TVT) across the project area. Data show that the fracture gradient of the upper confining interval is greater than or equal to 0.7 psi/ft. E. Lower Confining Interval: Lower confinement will be provided by more than 300 feet TVT of mud-dominated Torok Formation (Torok) sediments deposited in a slope setting. Data show that the fracture gradient of the lower confining interval is greater than or equal to 0.7 psi/ft. 8. Reservoir Fluid Contacts: There is a presumed oil-water contact estimated to be located at 4,400 feet TVDSS. CO 822 Amended April 23, 2025 Nunc pro tunc February 26, 2025 Page 7 of 13 9. 10. Reservoir Fluid Properties: CPAI provided the following reservoir fluid properties at a datum of 4,320 feet TVDSS from samples collected in CRU CD5-32X. Property Value Initial Reservoir Pressure (psia) 1,990 Reservoir Temperature (°F) 106 Stock Tank Oil API Gravity (°) 34.8 Gas-Oil Ratio (SCF/STB) 424 Bubble Point Pressure, Pb (psi) 1,734 Oil Formation Factor at Pb (RB/STB) 1.2 Oil Viscosity at Pb (cP) 2.17 Gas Formation Factor at Pb (RB/MSCF) at Saturation Pressure 1.5 11. In-Place and Recoverable Reserves Volumes: Reservoir Volumes Range (MMSTBO) Original Oil in Place (OOIP) in Proposed MOP 80-150 Primary Recovery (5-10% OOIP) 4-15 Primary + Waterflood (20-30% OOIP) 16-45 Primary + Water Alternating Gas Under Evaluation 12. Reservoir Development Drilling Plan: CPAI plans to initially drill a three-well pilot project (two injectors and one producer) to determine the optimal design for a full field development of the MOP. Subject to revision pending the results of the pilot project, CPAI plans a full-scale development of the MOP from the CRU CD5 drill site would consist of an estimated 9 horizontal multi-stage fracture-stimulated producers and 8 horizontal multi- stage fracture-stimulated injectors in a line drive pattern waterflood with the possibility of employing water-alternating-gas (WAG) injection. The pilot project wells are planned to be drilled on an inter-well spacing of 1,250 feet to evaluate pressure communication between injectors and producers at that distance. Upon completion of this pilot project and other evaluations, CPAI will expand development to the full pool adjusting the current plan as required based on the pilot project results. Wells will trend southeast to northwest to generally align with the maximum principal stress direction to improve waterflood performance. Wells will have horizontal sections of 4,000 to 10,000 feet in length. 13. Design of Wells: Development wells will be of a two- or three-string design with surface casing set below the C40 marker and cemented to surface. In three-string wells intermediate casing will be set below the top of the Minke sand at approximately 85 degrees. In two-string wells the crossover between 7-5/8” and 4-1/2” casing will occur at approximately the same depth. Both designs will be cemented to a minimum of 500 feet MD or 250 feet TVD, whichever is greater, above the casing shoe or casing crossover. The CO 822 Amended April 23, 2025 Nunc pro tunc February 26, 2025 Page 8 of 13 wells will be completed with cemented or uncemented casing/liners with frac sleeves to facilitate multistage hydraulic fracturing. It is anticipated the wells will be completed with 4-1/2” tubing. 14. Reservoir Management: CPAI plans to conduct the pilot project portion of the development as a waterflood utilizing produced water from the CRU and Greater Moose’s Tooth Unit (GMTU) and Beaufort Seawater from the Oliktok Point Seawater Treatment Plant. The target voidage replacement ratio is 1.0. Future development may include WAG injection. 15. Reservoir Surveillance Plans: CPAI proposes the following reservoir surveillance plan: a. Static bottom-hole pressure surveys will be conducted in all new injection wells prior to initiating injection. b. Static surveys will be performed on production wells at the discretion of CPAI, or as directed by the AOGCC. c. For annual pressure surveillance, a minimum of one (1) pressure survey will be conducted annually in the MOP. d. In lieu of stabilized bottom-hole pressure measurements, the alternative pressure survey methods below can be implemented: i. Open-hole wireline formation fluid pressure measurements, ii. Cased-hole pressure buildups with bottom-hole pressure measurement, iii. Injector surface pressure fall-off, iv. Readings from permanent downhole pressure/temperature gauges, v. Static pressure surveys following extended shut-in periods, or vi. Bottom-hole pressures calculated from wellhead pressure and fluid levels in the tubing of a stabilized shut-in injector e. All pressure surveys will be reported annually, rather than monthly, to reduce paperwork due to the limited number of surveys. 16. Datum Depth: The top of the pool extends between approximately 4,150 feet TVDSS and 4,950 feet TVDSS. 4,320 feet TVDSS will be a representative target depth since the estimated oil-water contact depth is approximately 4,400 feet TVDSS. 17. Metering and Measurement Processes: Production from the MOP will be commingled at the surface with production from other CRU and GMTU pools and from future pools that may be processed through the Alpine Central Facility. Well testing and allocation meters will be installed and maintained according to industry recommended practices and wells will be tested at least twice per month. 18. Waivers: CPAI requested the following waivers: a. Wellbore Surveys: in lieu of the requirements of 20 AAC 25.050(b), CPAI proposes submitting the following information with permit to drill applications: i. Plan view, CO 822 Amended April 23, 2025 Nunc pro tunc February 26, 2025 Page 9 of 13 ii. Vertical section, iii. Close approach data, and iv. Directional data b. Well Spacing: The interwell spacing restrictions of 20 AAC 25.055 be waived for development wells in the proposed MOP to accommodate horizontal, line-drive wells and maximize ultimate recovery. The property line offset regulations in 20 AAC 25.055 would remain in effect. c. Logs and Geologic Data: CPAI requests that the requirements of 20 AAC 25.071(a) only apply to one well from the CRU CD5 drill site and be waived for all other MOP wells. These requirements have already been satisfied because a number of wells in the area have been drilled and logged. Additional data will not significantly add to the geologic knowledge for this area. d. Workover Operations: CPAI requests that the MOP be included in the existing order CO 735 that governs workover operations on CPAI operations. 19. Interwell Spacing Requirements: Effective September 27, 2022, the statute governing interwell spacing was changed and interwell spacing requirements were eliminated. However, property line setback requirements were unchanged. (See AOGCC Industry Guidance Bulletin 22-002). CONCLUSIONS: 1. Establishing pool rules for the MOP is appropriate and will aid in the efficient development of the field while not promoting waste and protecting correlative rights and freshwater. 2. A waiver of the requirements of 20 AAC 25.050(b) is commonly granted to simplify the permit to drill application and review process and is appropriate for the MOP. 3. The interwell spacing requirements of 20 AAC 25.055 are no longer supported by Alaska Statutes and are therefore unenforceable. (See AOGCC Industry Guidance Bulletin 22- 002). CPAI’s requested waiver of the interwell spacing regulation is unnecessary. The offset from property lines requirements, which is 500 feet for oil wells, are still in place. 4. A waiver of the logging requirements of 20 AAC 25.071(a) is appropriate for the MOP. 5. Applying CO 735 to the MOP is appropriate to ensure all pools in the CRU have the same rules regarding when a sundry permit/report is required. NOW THEREFORE IT IS ORDERED: Development and operation of the Minke Oil Pool is subject to the following rules and the statewide requirements under 20 AAC 25 to the extent not superseded by these rules: CO 822 Amended April 23, 2025 Nunc pro tunc February 26, 2025 Page 10 of 13 Affected Area: Umiat Meridian (See Figure 1) Township 10 North, Range 3 East Sections 1: N/2 NE/4 Township 11 North, Range 3 East Section 1: E/2 & SW/4 Section 11: E/2E/2 Sections 12&13: all Section 14: E/2 & SE/4SW/4 Section 23: E/2, E/2W/2, SW/4NW/4, & NW/4SW/4 Sections 24 & 25: all Section 26: Ne/4, N/2SE/4, SE/4SE/4, & NE/4NW/4 Section 35: NE/4NE/4 Section 36 N/2, SE/4, N/2SW/4, and SE/4SW/4 Township 11 North, Range 4 East Section 5: N/2, SW/4, N/2SE/4, & SW/4SE/4 Sections 6 & 7: all Section 8: W/2, w/2NE/4, & NW/4SE/4 Section 17: W/2W/2 Section 18: all Section 19: N/2, SW/4, N/2SE/4, & SW/4SE/4 Section 20: NW/4NW/4 Section 30: W/2 & W/2NE/4 Section 31: N/2NW/4 & SW/4NW/4 Township 12 North, Range 3 East Section 36: E/2SE/4 Township 12 North, Range 4 East Section 19: E/2 Section 20: SW/4NW/4, W/2SW/4, & SE/4SW/4 Section 29: W/2, SW/4NE/4, W/2SE/4, & SE/4SE/4 Section 30: E/2, SE/4NW/4, & E/2SW/4 Section 31: E/2, SW/4, E/2NW/4, & SW/4NW/4 Section 32: all Section 33: W/2NW/4 & NW/4SW/4 CO 822 Amended April 23, 2025 Nunc pro tunc February 26, 2025 Page 11 of 13 Rule 1 Field and Pool Name The field is the Colville River Field, and the pool is the Minke Oil Pool. Rule 2 Pool Definition The Minke Oil Pool is defined as the accumulation of oil and gas common to and correlating with the interval within the CRU CD5-22 well between the depths of 5,222 and 6,433 feet MD (4,333 and 5,194 feet TVDSS). (See Figure 2, above.) Rule 3 Gas Oil Ratio Exemption Wells producing from the Minke Oil Pool are exempt from the gas-oil ratio limitations set forth in 20 AAC 25.240 so long as there is an active enhanced oil recovery injection project. Rule 4 Drilling and Completion Practices A. Alternate casing and completion programs, in addition to those specified in 20 AAC 25, may be administratively approved by the AOGCC upon application and presentation of data that demonstrate the alternatives are appropriate and based upon sound engineering principles. B. In lieu of the requirements under 20 AAC 25.050(b) permit to drill applications shall include: a. Plan view, b. Vertical section, c. Close approach data, and d. Directional plan. C. The requirements of 20 AAC 25.071(a) have already been satisfied for the CRU CD5 drill site. For the MOP, the AOGCC may specify which types of logs are to be run on a well- by-well basis. Rule 5 Automatic Shut-In Equipment a. Double check valve arrangement, or b. Single check valve and a surface safety valve (SSV). A sub-surface-controlled injection valve (SCSSV) satisfies the requirements of a single check valve. Rule 6 Well Spacing The interwell spacing requirements of 20 AAC 25.055(a)(3) and (4) and 20 AAC 25.055(b) and (c) are no longer supported by an underlying statute and as such are unenforceable. The property line offset requirements of 20 AAC 25.055(a)(1) and (2) remain in effect. Rule 7 Reservoir Surveillance a. Static bottom-hole pressure surveys will be conducted in all new injection wells prior to initiating injection. CO 822 Amended April 23, 2025 Nunc pro tunc February 26, 2025 Page 12 of 13 b. Static surveys will be performed on production wells at the discretion of CPAI. c. In lieu of stabilized bottom-hole pressure measurements, the alternative pressure survey methods below can be implemented: a. Open-hole wireline formation fluid pressure measurements, b. Cased-hole pressure buildups with bottom-hole pressure measurement, c. Injector surface pressure fall-off, d. Static pressure surveys following extended shut-in periods, or e. Bottom-hole pressures calculated from wellhead pressure and fluid levels in the tubing of a stabilized shut-in injector. d. All pressure surveys will be reported annually, rather than monthly, to reduce paperwork due to the limited number of surveys. e. The datum depth for pressure surveys shall be 4,320 feet TVDSS. f. The Minke Oil Pool shall be included in the annual reservoir surveillance report submitted for the Colville River Unit. Rule 8 Workover Operations Conservation Order No. 735 shall apply to the Minke Oil Pool. Rule 9 Sustained Casing Pressure for Production Wells a. At the time of installation or replacement, the operator shall conduct and document a pressure test of tubulars and completion equipment in each production well that is sufficient to demonstrate that planned well operations will not result in failure of well integrity, uncontrolled release of fluid or pressure, or threat to human safety. b. The operator shall monitor each production well daily to check for sustained pressure, except if prevented by extreme weather conditions, emergency situations, or unavoidable circumstances. Monitoring results shall be kept available for AOGCC inspections. c. The operator shall notify the AOGCC within three working days after the operator identifies a well as having: (i) sustained inner annulus pressure that exceeds 2,000 pounds per square inch gauge (psig) for all production wells, or (ii) sustained outer annulus pressure that exceeds 1,000 psig. d. If the operator identifies sustained pressure in the inner annulus of a production well that exceeds 45 percent of the burst pressure rating of the well’s production casing for inner annulus pressure, or sustained pressure in the outer annulus that exceeds 45 percent of the burst pressure rating of the well’s surface casing for outer annulus pressure, the operator shall notify the AOGCC within three working days and take corrective action. Unless well conditions require the operator to take emergency corrective action before AOGCC approval can be obtained, the operator shall submit in an Application for Sundry Approvals (Form 10-403) a proposal for corrective action. The AOGCC may approve the operator’s proposal or require other corrective action, including a mechanical integrity test or other CO 822 Amended April 23, 2025 Nunc pro tunc February 26, 2025 Page 13 of 13 diagnostic tests. The operator shall give the AOGCC sufficient notice of the testing schedule to allow the AOGCC to witness the tests. e. Except as otherwise approved by the AOGCC under (d) of this rule, before a shut-in well is placed in service, any annulus pressure must be relieved to a sufficient degree: (1) that the inner annulus pressure at operating temperature will be below 2,000 psig, and (2) that the outer annulus pressure at operating temperature will be below 1,000 psig. A well subject to (c) but not (d) of this rule may reach an annulus pressure at operating temperature that is described in the operator’s notification to the AOGCC under (c) of this rule, unless the AOGCC prescribes a different limit. f. For purposes of this rule, i. “inner annulus” means the space in a well between tubing and production casing; ii. “outer annulus” means the space in a well between production casing and surface casing; and iii. “sustained pressure” means pressure that (A) is measurable at the casing head of an annulus, (B) is not caused solely by temperature fluctuations, and (C) has not been applied intentionally. DONE at Anchorage, Alaska and dated April 23, 2025, Nunc pro tunc February 26, 2025. Jessie L. Chmielowski Gregory C. Wilson Commissioner Commissioner RECONSIDERATION AND APPEAL NOTICE As provided in AS 31.05.080(a), within 20 days after written notice of the entry of this order or decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration of the matter determined by it. If the notice was mailed, then the period of time shall be 23 days. An application for reconsideration must set out the respect in which the order or decision is believed to be erroneous. The AOGCC shall grant or refuse the application for reconsideration in whole or in part within 10 days after it is filed. Failure to act on it within 10-days is a denial of reconsideration. If the AOGCC denies reconsideration, upon denial, this order or decision and the denial of reconsideration are FINAL and may be appealed to superior court. The appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision denying reconsideration, UNLESS the denial is by inaction, in which case the appeal MUST be filed within 40 days after the date on which the application for reconsideration was filed. If the AOGCC grants an application for reconsideration, this order or decision does not become final. Rather, the order or decision on reconsideration will be the FINAL order or decision of the AOGCC, and it may be appealed to superior court. That appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision on reconsideration. In computing a period of time above, the date of the event or default after which the designated period begins to run is not included in the period; the last day of the period is included, unless it falls on a weekend or state holiday, in which event the period runs until 5:00 p.m. on the next day that does not fall on a weekend or state holiday. Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2025.04.23 14:15:19 -08'00' Gregory C. Wilson Digitally signed by Gregory C. Wilson Date: 2025.04.23 14:54:13 -08'00' From:Coldiron, Samantha J (OGC) To:AOGCC_Public_Notices Subject:[AOGCC_Public_Notices] Conservation Order 822 Amended (CPAI) Date:Wednesday, April 23, 2025 3:11:15 PM Attachments:CO822 Amended.pdf CO 822 was revised to correct a typographical error in the legal description of the affected area in Section 20, Township 12 North Range 4 East. It read “Section 20: W/4NW/4…” it was corrected to read “Section 20: SW/4NW/4…” 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 7 March 17, 2025 Alaska Oil and Gas Conservation Commission 333 W. 7th Ave #100 Anchorage, Alaska, 99501-3539 RE: Request for Reconsideration Conservation Order No. 822, Minke Oil Pool, North Slope, AK Enhanced Recovery Injection Order No. 009, Minke Oil Pool, North Slope, AK Dear Commissioners: ConocoPhillips Alaska, Inc. (“CPAI”) appreciates the Commission’s timely issuance of the Minke Oil Pool (“MOP”) Conservation Order 822 (“CO”) and Enhanced Recovery Injection Order 9 (“ERIO”). CPAI respectfully requests reconsideration of the following items: The title page of the ERIO contains a typographical error. The title page incorrectly lists the ERIO number for the MOP as ERIO 8. CPAI requests the typographical error be corrected to provide ERIO 9. Finding 13 on Page 7 of the ERIO incorrectly lists “Coyote Oil Pool Reservoir Volume” in the table. CPAI requests the revised language for the title for Finding 13 be Minke Oil Pool Reservoir Volume. ERIO Rule 5 requires that the AOGCC must be notified at least 72 hours in advance to enable a representative to witness a mechanical integrity test (MIT). CPAI requests the timeframe be revised to 24 hours to match the timeframe in CPAI’s other injection orders within CRU. See AIO 18 Rule 5, AIO 28 Rule 6, AIO 30, Rule 6, and AIO 35 Rule 6.The concern is that having different rules for different injection orders will be difficult to administer. On page 10 of the CO there is a small typographical error in the land description. CPAI requests the highlighted adjustment be made. Michael Driscoll WNS Development Supervisor North Slope Development ConocoPhillips Alaska, Inc. P.O. Box 100360 Anchorage, AK 99510-0360 phone 907.265.6383 Via Electronic Mail aogcc.permitting@alaska.gov By Samantha Coldiron at 7:35 am, Mar 18, 2025 Request for Reconsideration of Conservation Order No. 822 and Enhanced Recovery Injection Order No. 09 Page 2 of 2 On page 10 of the ERIO a portion of the land description contains a typo. CPAI requests the highlighted adjustment be made. CPAI appreciates the Commission reconsidering these items. Please contact Ethan Castongia (263- 4358, ethan.e.castongia@conocophillips.com) if you have questions or would like to discuss this request for reconsideration. Regards, Michael Driscoll WNS Development Supervisor North Slope Development 6 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. From:Hobbs, Greg S To:AOGCC Reporting (CED sponsored) Cc:Roby, David S (OGC); Dodson, Kate; Zwarich, Nola R; Castongia, Ethan E Subject:Amendment to Application for Minke Oil Pool and Pilot Injection, North Slope, Alaska Date:Thursday, February 6, 2025 2:49:10 PM Attachments:AOGCC Cover Letter - Minke Pool_ERIO 20250204.pdf Good Afternoon, In the attached document, please find the request and amended exhibits to correct an error with land identification and description in the original application. If there are further questions on the matter, please reach out to Ethan Castongia. Thank you, Greg Greg Hobbs, P.E. Regulatory Engineer | Wells Team ConocoPhillips Alaska Inc. Office: 907-263-4749 Cell: 907-231-0515 February 5, 2025 Jessie Chmielowski Commissioner, Alaska Oil and Gas Conservation Commission 333 W. 7th Ave Anchorage, Alaska 99501-3539 RE: Amendment to Application for Minke Oil Pool and PilotInjection, North Slope, Alaska Dear Commissioner Chmielowski, ConocoPhillips Alaska, Inc.,as operator of the Colville River Unit, submitsto the Alaska Oil and Gas Conservation Commission the attached amendment to the previously submitted application to the AOGCC requestingformation of the Minke Oil Pool and approval of PilotInjection into the Minke Oil Pool.The amendment (i) amends and replaces the lands identiﬁed within Section H Proposed Minke Oil Pool Rules with the lands described in Exhibit A to correct an error in the land description, the original application erroneously described just the proposed participating area (PA)portion of the oil pool, the amended version includes a land description for the entire proposed Minke Oil Pool, and (ii)clariﬁes the proposed areafor the requestedpilot injection program to be the proposed PA area only by including an additional subsection within Section D Reservoir Development described as “Proposed Pilot Injection Area”inExhibit B. Please ﬁnd digital copies of the amended application attached to this email. Please contact Ethan Castongia (907-263-4358, ethan.e.castongia@conocophillips.com) if you have any questions or require additional information. Regards, Michael Driscoll Michael Driscoll Development Supervisor ConocoPhillips Company 700 G Street Anchorage, AK 99501 OƯice: 907-265-6383 Fax: 907-263-4966 michael.d.driscoll@conocophillips.com EXHIBIT A Amendment to the Application to the Alaska Oil and Gas Conservation Commission (AOGCC) for Formation of the Minke Oil Pool As of February 5, 2025 SSecƟon H Proposed Minke Oil Pool Rules The rules set forth apply to the following area referred to in this order: Umiat Meridian, Alaska T10N, R3E Section 1: N/2NE/4 T11N, R3E Section 1: E/2 & SW/4 T11N, R3E Section 11: E/2E/2 T11N, R3E Section 12: ALL T11N, R3E Section 13: ALL T11N, R3E Section 14: E/2 & SE/4SW/4 T11N, R3E Section 23: E/2, E/2W/2, SW/4NW/4, & NW/4SW/4 T11N, R3E Section 24: ALL T11N, R3E Section 25: ALL T11N, R3E Section 26: NE/4, N/2SE/4, SE/4SE/4, & NE/4NW/4 T11N, R3E Section 35: NE/4NE/4 T11N, R3E Section 36: N/2, SE/4, N/2SW/4, SE/4SW/4 T11N, R4E Section 5: N/2, SW/4, N/2SE/4, & SW/4SE/4 T11N, R4E Section 6: ALL T11N, R4E Section 7: ALL T11N, R4E Section 8: W/2, W/2NE/4, & NW/4SE/4 T11N, R4E Section 17: W/2W/2 T11N, R4E Section 18: ALL T11N, R4E Section 19: N/2, SW/4, N/2SE/4, & SW/4SE/4 Section 20: NW/4NW/4 T11N, R4E Section 30: W/2 & W/2NE/4 T11N, R4E Section 31: N/2NW/4 & SW/4NW/4 T12N, R3E Section 36: E/2SE/4 T12N, R4E Section 19: E/2 T12N, R4E Section 20: SW/4NW/4, W/2SW/4, & SE/4SW/4 T12N, R4E Section 29: W/2, SW/4NE/4, W/2SE/4, & SE/4SE/4 T12N, R4E Section 30: E/2, SE/4NW/4, & E/2SW/4 T12N, R4E Section 31: E/2, SW/4, E/2NW/4, & SW/4NW/4 T12N, R4E Section 32: ALL T12N, R4E Section 33: W/2NW/4 & NW/4SW/4 EXHIBIT B Amendment to the Application to the Alaska Oil and Gas Conservation Commission (AOGCC) for Formation of the Minke Oil Pool As of February 5, 2025 SSecƟon D Reservoir Development Proposed Pilot InjecƟon Area The affected area for the temporary injecƟon order is as follows: Umiat Meridian, Alaska T11N, R3E Section 1: S/2 T11N, R3E Section 11: E/2E/2 T11N, R3E Section 12: ALL T11N, R3E Section 13: ALL T11N, R3E Section 14: E/2NE/4 T11N, R3E Section 24: E/2NW/4, NE/4, N/2SE/4, & SE/4SE/4 T11N, R4E Section 6: SW/4SW/4 T11N, R4E Section 7: W/2, W/2SE/4 T11N, R4E Section 18: ALL T11N, R4E Section 19: W/2, N/2NE/4, SW/4NE/4, & NW/4SE/4 5 December 20, 2024 Commissioner Jessie Chmielowski and Commissioner Greg Wilson Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage, Alaska 99501 Re: Response to Requests From the Minke Oil Pool and ERIO Hearing Dear Commissioners, I am writing to you on behalf of ConocoPhillips Alaska, Inc. (ConocoPhillips) regarding the questions posed by the Commission at the public hearing held on November 19, 2024 on ConocoPhillips’ application to establish the Minke oil pool and for approval of a temporary pilot enhanced recovery injection order (ERIO). ConocoPhillips’ responses are set forth below. Pursuant to AS 31.05.035, 20 AAC 25.537 and 20 AAC 25.540(c)(10), ConocoPhillips requests that Appendix A to this letter be treated as confidential as the information contains trade secrets or is commercially confidential and proprietary information entitled to confidential treatment.  Commission Request 1: Expand the well integrity list from the quarter mile radius from the proposed ERIO injectors to a half mile radius of the entire Minke Pool area. Response: See the table attached as Appendix A (Minke Pool Well Table) to this letter. This table includes all wells within a half mile radius of the Minke Pool area. The table also includes the following additional information:  The presence or absence of net sand and net pay within the Minke interval at a well level. Some wells have uncertainty in pay presence due to the lack of porosity log data to assess porosity and water saturation.  The presence of cement across the Minke interval and/or Nanushuk formation above the Minke. In some cases, while the Minke interval remains uncemented, the well had a stage cement job placed across the Nanushuk formation above the Minke interval.  Commission Request 2: Create a “pore-foot” map of the Nanushuk sands within the Minke Pool area. Response: Attached as Appendix B is a pore-foot map of the Nanushuk formation above the Minke reservoir that extends from the top K3 to the top Minke. The six wells used for this map were the only wells within the proposed Minke pool with sufficient logs to complete a petrophysical evaluation for reservoir presence. The map extent was determined by using a half mile buffer from the outer well control points up to the pool boundary. The map does not cover the entire pool area due to lack of well control outside of the mapped area. Net reservoir was identified using the petrophysical model developed in response to the 2022 CD1 incident for overburden screening, applying cutoffs of >25% porosity and <30% clay volume. Consequently, the pore-foot values range from a maximum of 1.91 pore-foot in 7 feet thick net reservoir to a minimum of 0.04 pore-foot in less than 1 foot of net reservoir. The gross interval thickness of the Nanushuk averages 550 feet in the mapped area and contains a small net reservoir thickness. December 20, 2024  Commission Request 3: Further criteria on OA pressure management. Response: ConocoPhillips proposes the following monitoring program to identify and mitigate potential out of zone injection: 1. All wells on CD5 and within a half mile of the proposed ERIO area are instrumented with tubing (TBG), Inner Annulus (IA), and Outer Annulus (OA) pressure transmitters which feed real-time pressure data to the process control and alarm system for the drillsite. This is a more modern level of instrumentation than most of the legacy drillsites on the North Slope. 2. In order to monitor and protect the surface casing shoe integrity, ConocoPhillips plans to reduce the Maximum Allowable (Outer) Annulus Surface Pressure (MAASP) for all wells within the half mile radius of the ERIO to the lesser of the calculated MAASP (based on as drilled leak off test (LOT) and current annular fluids in the well) or 1000 psi. See Appendix C – Tested LOT information for wells within a half mile radius of the ERIO. 3. The following actions will be taken during hydraulic fracturing operations: • Actively monitor all wells’ OA pressures within a half mile of any hydraulic fracturing operations. • If a significant pressure increase is observed in an offset well’s OA that is coincident with fracture operations, then: 1. Stage job will cut to flush for remainder of that stage. Cease hydraulic fracturing operations on stage after flush. 2. Evaluate pressure response and move to next stage as long as OA pressures have stabilized below MAASP. Continue monitoring off-set OAs through remainder of fracture operations. 4. The following actions will be taken during injection operations: • All wells that are partially cemented or uncemented across the Minke interval in the outer annulus and within a quarter mile radius of a Minke injection well will include language in the AnnComm database so that it is easily recognized that pressure anomalies could be due to Minke injection: The Minke formation in this well is not isolated by cement and lies less than a quarter mile away from a Minke injection well (well name). If sustained OA pressure in this well is observed, the Minke should be considered a potential source of that. • An OA alarm at MAASP pressure minus whichever is the greater of 20% or 150 psi below MAASP pressure will be set, such that Operations has time to react to rising pressure and keep the well within the established MAASP. December 20, 2024 • Offset wells will be monitored and managed according to ConocoPhillips’ existing well operating guidelines. For example, a single OA bleed on an injector or two OA bleeds within a month on a producer would automatically flag the well for an integrity review. • A well flagged for an integrity review exhibiting sustained casing pressure interpreted to be related to Minke injection will trigger an internal review to understand potential communication and whether continued injection into the Minke reservoir is appropriate. While we believe the above responses address the Commission’s questions, ConocoPhillips would also like to outline three additional steps that will be taken during the temporary pilot injection program to address the concerns raised by the Commission at the Minke hearing: 1. The lateral section of the planned Minke injection well, CD5-697, will be TD’d no closer than a half mile radius of existing well CD5-98. 2. Cumulative voidage replacement ratios will be monitored to align with ConocoPhillips’s intent of maintaining a voidage replacement without increasing average pressure in the Minke reservoir. 3. For the purposes of this ERIO, ConocoPhillips has reevaluated the maximum injection pressure necessary for a test of the Minke reservoir, and hereby amends the ERIO application to request a maximum injection pressure 0.6psi/ft. This will avoid extending existing fracture lengths within the Minke reservoir during normal injection operation. After acquiring the data from the pilot injection program, ConocoPhillips will reassess the maximum injection pressure in the context of a future area injection order application. The results of this temporary pilot injection program will be used to assess the potential for economic development of the Minke reservoir and the drilling of further development wells. The data acquired during this temporary pilot will be used to inform a future Minke AIO application if further Minke development proves feasible. Thank you for your time and attention to this matter. We look forward to your response. Sincerely, Michael Driscoll WNS Development Supervisor michael.d.driscoll@conocophillips.com 907-980-0957 Appendix B: Nanushuk Formation Pore-Foot Map ConocoPhillips 1 Type Well Characteristic 580 ftGross Interval Thickness 314 ftSandstone Thickness 1 ftReservoir Thickness 25%Reservoir Porosity 0.27Pore-Foot Nanushuk FormationSand Cut-off: 30%Volume Clay Reservoir Cut-off: 30% Volume Clay 25% Porosity Minke PA Minke Pool CD5 Nuiqsut 1 CD5-316 CD5-313 PB1 CD5-32X CD5-21 CD5-22 Wells w/petrophysics Type Log CD5-22 Minke Nov 19, 2024 AOGCC Public Hearing Response to Commision Request: Further criteria on OA Pressure Management Appendix C – Tested LOT information for wells within half-mile radius of the ERIO PTD #API #Well Name Well ID Penetrates Minke within 1/4mi of ERIO Injector Penetrates Minke within 1/2mi of ERIO Injector LOT TVD Shoe, ft Test Surface Pressure, psi MW Test, ppg Maximum Allowable (Outer) Annulus Surface Pressure, psi 216-031-0 501032073800 CD5-21 CD5-21 Y - CD5-633 Y - BOTH N 2194 925 9.9 >1000 223-109-0 501032087100 CD5-32X CD5-32X Y - CD5-697 Y - BOTH Y 2187 955 10.1 950 217-040-0 501032075600 CD5-316 CD5-316 N Y - CD5-633 N 2175 700 9.9 >1000 216-161-0 501032075200 CD5-20 CD5-20 N Y - CD5-697 Y 2183 900 9.6 >1000 217-89-0 501032075900 CD5-22 CD5-22 N Y - CD5-697 N 2184 970 9.6 >1000 219-034-0 501032080000 CD5-92 CD5-92 Y - CD5-697 Y - CD5-697 N 2189 1020 9.6 >1000 220-073-0 501032082700 CD5-93 CD5-93 Y - CD5-697 Y - CD5-697 Y 2188 810 9.6 >1000 217-121-0 501032076000 CD5-19 CD5-19 N Y - CD5-697 N 2187 955 9.6 >1000 215-137-0 501032071600 CD5-315 CD5-315 N Y - CD5-633 N 2159 890 9.8 >1000 219-059-0 501032080300 CD5-98 CD5-98 N Y - CD5-697 N 2178 1040 9.5 >1000 217-021-0 501032075500 CD5-314X CD5-314X Y - CD5-633 Y - CD5-633 N 2183 860 9.6 >1000 217-161-0 501032076500 CD5-25 CD5-25 N Y - CD5-697 N 2182 980 9.7 >1000 217-155-0 501032076100 CD5-23 CD5-23 N Y - CD5-697 N 2178 630 9.7 950 4 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. From:Coldiron, Samantha J (OGC) To:Hobbs, Greg S Subject:RE: Request for Extension on Minke Hearing Supplemental Filing Date:Thursday, December 5, 2024 3:36:00 PM Greg- The extension of time is granted. Regards, Samantha Coldiron AOGCC Special Assistant (907) 793-1223 From: Hobbs, Greg S <Greg.S.Hobbs@conocophillips.com> Sent: Thursday, December 5, 2024 3:19 PM To: AOGCC Permitting (CED sponsored) <aogcc.permitting@alaska.gov> Cc: Coldiron, Samantha J (OGC) <samantha.coldiron@alaska.gov> Subject: Request for Extension on Minke Hearing Supplemental Filing Good Afternoon, Please see the attached request to extend the submission timing for materials requested at the Minke Pool Rules and Enhanced Recovery Injection Order public hearing. Thank-you! Greg Greg Hobbs, P.E. Regulatory Engineer | Wells Team ConocoPhillips Alaska Inc. Office: 907-263-4749 Cell: 907-231-0515 Michael Driscoll Development Supervisor 700 G Street Anchorage, AK 99510 Office: 907-265-6383 Fax: 907-263-4966 michael.d.driscoll@cop.com December 5, 2024 Alaska Oil and Gas Conservation Commission 333 W. 7th Avenue Anchorage, AK 99501 Attn: Commissioner Jessie Chmielowski RE: Request for Extension on Minke Supplemental Filing North Slope, Alaska Dear Commissioner Chmielowski: ConocoPhillips Alaska, Inc. (“CPAI”) is diligently working to prepare the materials requested by the Alaska Oil and Gas Conservation Commission at the Minke Pool Rules and Enhanced Recovery Injection Order public hearing, but needs additional time to prepare the materials. CPAI respectfully requests an extension of two weeks until 5pm Friday, December 20 th, 2024 for the record to remain open for CPAI to make its supplemental filing. Thank you for your consideration. Regards, Via Electronic Mail aogcc.permitting@alaska.gov By Samantha Coldiron at 3:26 pm, Dec 05, 2024 3 Pool & Enhanced Recovery Injection Public Hearing Minke November 19th, 2024 Expert Witnesses Ethan Castongia: Geophysics •B.S. Geology with concentration in Geophysics, University of Illinois Urbana-Champaign •M.S. Geophysics, University of Wisconsin Madison •Industry experience •10 years, all with ConocoPhillips (~8 years in Alaska) –Field appraisal & development –Exploration –Technology ConocoPhillips 2 Federico Caldelas: Reservoir Engineering •B.S. in Petroleum Engineering, University of Texas at Austin •M.S. in Petroleum Engineering, University of Texas at Austin •Industry experience •1 year with DeGolyer & MacNaughton: Reserves Estimation •13 years with ConocoPhillips (~9 years in Alaska) –Voidage Management –Viscous Development –Strategy & Portfolio Management Matt Nagel: Drilling Engineering •B.S. in Petroleum Engineering, Texas Tech University • Industry experience: •12 years total –9 years with ConocoPhillips (~5 years in Alaska) •L48 unconventional drilling and completions •Alaska Development –3 years with Anadarko Petroleum Corporation •L48 unconventional drilling Erika Rodriguez: Geology •B.S. Geology, New Mexico Institute of Mining and Technology •M.S. Geology, Texas A&M University •Industry experience •19 years, all with ConocoPhillips (~4 years in Alaska) –LW 48 Development –Global New Ventures –Alaska Exploration –Alaska Development Dusty Ward: Completions Engineering •B.S. in Mechanical Engineering, George Fox University •M.S. in Industrial Engineering, Oregon State University •Industry experience: 11.5 years ConocoPhillips Alaska •5 years Integrated Asset Planner: Gas Fields and LNG •6.5 years Wells Engineer: –Rig Workovers, CTD, and Completion Engineering Agenda •Overview (Ethan Castongia) •Geology and Pool Description (Erika Rodriguez) •Resource and Recovery (Fede Caldelas) •Operations and Containment Assessment •Well Design (Matt Nagel) •Containment (Dusty Ward) •Injection Pressures & Fluids (Fede Caldelas) • Request for Finding, Summary, Proposed Rules, (Ethan Castongia) with additional CONFIDENTIAL Geology section (Erika Rodriguez) ConocoPhillips 3 AAC: Alaska Administrative Code ADL: Alaska Division of Lands AOGCC: Alaska Oil and Gas Conservation Commission API: American Petroleum Institute CIBP: Cast Iron Bridge Plug CD5: Coville Delta Pad 5 CPAI: ConocoPhillips Alaska, Inc. CPF: Central Processing Facility CRU: Colville River Unit DS: Drillsite DFIT: Diagnostic Fracture Injection Test ERIO: Enhanced Recovery Injection Order GLM: Gas Lift Mandrel GOR: Gas Oil Ratio LWD: Logging While Drilling MD: Measured Depth md: Millidarcy MI: Miscible Injectant MIT: Mechanical Integrity Test MMSTB: Million Stock Tank Barrels MOP: Minke Oil Pool P&A: Plug and Abandon PPG: Pounds Per Gallon PSI: Pounds Per Square Inch PW: Produced Water RST: Reservoir Surveillance Tool SHMIN: Minimum Horizontal Stress STOOIP: Stock Tank Original Oil In Place TOC: Top of Cement TVD: True Vertical Depth TVDSS/SSTVD: True Vertical Depth Subsea Acronyms List ConocoPhillips 4 Area Overview •Proposed Minke Oil Pool & pilot injection wells located in western portion of the Colville River Unit (CRU) •Operator: 100% ConocoPhillips Alaska, Inc. •Surface owners •Kuukpik Corporation •Bureau of Land Management •Area covered by 3D seismic & numerous historical penetrations in wells targeting deeper stratigraphic intervals •Typically, minimal data collection through Minke (basic log suites) •Provide good depth, thickness, and mapping control to delineate the reservoir ConocoPhillips 5 ~2 Miles Proposed Minke Pool Area Proposed Minke Participating Area Colville River Unit Legend Well Display Top Minke Penetration Plugged and Abandoned Producer Injector Key Well Greater Moose’s Tooth Unit Colville River Unit Geology and Pool Description Minke Oil Pool Definition (CD5-22 Type Log) ConocoPhillips 7 •Confining intervals •Upper: Flooding shale within the Nanushuk Formation. This interval is present in thicknesses of 100’ to more than 200’ TVD across the area. •Lower: Slope setting Torok mud dominated heterolithic sequences, more than 300’ TVD thick Geologic Overview •Structure/Trap •Generally low relief (~1 degree dip) •No mapped faulting •Plunges to east outboard of current shelf margin •Crest to the SW ConocoPhillips 8 Well Log Cross-Section (Structural Datum) ConocoPhillips 9 Top Minke Base Gross Minke Proposed Minke Oil Pool Upper Confining Interval Lower Confining Interval Completed interval-oil OWC -4400’TVDSS Cored Interval Top Minke Base Gross Minke OWC: -4,400 SSTVD Upper Confining Interval Proposed Minke Oil Pool Lower Confining Interval B’B A’A CD5-98 CD5-92 CD5-93 CD5-23 CD5-25 CD5-316 CD5-32X CD5-23 CD5-22 CD5-09 A B’ B A’ Minke Top Structure Map CI: 25ft Resource and Recovery In Place Volume and Recovery •Volumetric estimates are based off the mapping of core calibrated log model results from wells within and beyond the proposed pool area, guided by 3D seismic interpretations. •Expected ultimate recovery based on reservoir simulation, calibrated to CD5-32X performance and North Slope fields with similar rock and fluid properties. •Significant uncertainty remains; objective of initial development is to estimate recovery and optimize development plan. Minke Pool Properties (@ -4320ft TVDSS) Initial Pressure (psig)1,990 Temperature (F)106 GOR (scf/bbl)430 API Gravity (deg)34-35 Saturation Pressure (psig)1734 Oil Volume Factor (rb/stb)1.2 Oil Viscosity (cp)2.17 Gas Volume Factor (rb/mscf)1.5 Total Pool Area STOOIP (MMSTB)80-150 Well Count 3 Primary Recovery 5-10% Primary + Waterflood Recovery 20-30% Primary + Water Alternating Gas Under Evaluation ConocoPhillips 11 Operations and Containment Well Design •3-string or 2-string casing design •7-5/8” casing set in the reservoir and cemented to a minimum of 500’ MD / 250’ TVD above the highest hydrocarbon bearing zone •Uncemented and cemented 4-1/2” casing/liner within reservoir •Packer/isolation equipment may be located greater than 200' from top perforation/open interval (in lieu of 20 AAC 25.412(b) requirement of setting within 200' of top perforation/open interval) and shall be set within confining zone and at least 100’ below the top of cement •Fracture stimulated laterals with ~400’ stage spacing ConocoPhillips 13 CD5-32x History Match Prop Con 0 – 3 lb/ft2 0.5 1 2 3 ~350 ft 32 ft •Pressure history match completed on CD5-32x using GOHFER fracture modeling software. ̶Inputs based on CD5-32x well logs ✓Perf Depth 5018’ – 5023’ MD ̶History match did not show overburden fracture growth although CarboNRT logs showed potential for fracture growth into the overburden ✓2.0 lb/ft^2 limited to top 40’ calculated by model. ̶Cement streak near top of Minke pay appears influential to frac. ✓Significant downward growth modeled away from overburden ̶Estimated 350’ propped half-length from model. ✓PTA suggests a smaller, effectively propped, fracture half-length in the order of 150’ to 200’ is more probable. •CarboNRT results show remnants of fracture penetrating up into the top seal hydraulically (yellow) along the vertical well. However, good proppant coverage signal (orange) limited to top portion of Minke reservoir, with a streak of deeper proppant coverage, which is believed to be from proppant settling. ̶Correlates well with model for height. CarboNRT Log GOHFER Model ConocoPhillips 14 Injection Containment ConocoPhillips 1515DynamicStaticMDGRRhobPRYMEUCSFAPP and Stresses 0 150 1 3 1 0.45 0 3 0 7000 10 50 1000 5000 Minke fracture closure pressure gradient: 0.6 psi/ft Source: Interpreted closure pressure from DFIT during the frac. Overburden fracture closure pressure gradient: 0.71 psi/ft (4309’ SSTVD, 4393’ TVD) Source: MicroFrac via SLBs MDT tool ~500 psig Upper Confining Zone: Flooding shale within the Nanushuk. Present in thicknesses of 100’ to more than 200’ TVD across the area Upper Confining Zone Minke Mechanical Condition of Wells Within ¼ Mile Well Well Type Status Mech Integrity Notes CD5-21 WS ACTIVE Normal -Cemented across Minke. CD5-32X MINKE PROD ACTIVE Normal -Casing cemented around Minke. -Perforation and Frac connect tubing to Minke. CD5-92 ALPINE PROD ACTIVE Normal -OA has some of Minke uncemented CD5-93 ALPINE INJ ACTIVE Normal -OA has some of Minke uncemented CD5-98 ALPINE PROD ACTIVE Normal -OA uncemented across Minke CD5-314X NANUQ KUPARUK PROD ACTIVE Normal -OA uncemented across Minke CD5-629 MINKE PROD N/A N/A -To Be Drilled *Minke penetration lengths shown by red and green lines. Well Location Map ConocoPhillips 16 Primary Injection Fluids •Produced water and gas from all present and yet-to-be defined oil pools within the CRU & GMTU •Beaufort seawater sourced from the Oliktok Point seawater treatment plant which provides seawater for CRU •Under consideration (not initially included) Hydrocarbon gas: CRU lean gas blended with indigenous natural gas liquids Secondary Injection Fluids •Fluids used during hydraulic fracture stimulation in accordance with 20 AAC 25.283 •Tracer survey fluids to monitor reservoir performance •Fluids used to improve near-wellbore injectivity (solvents, acids, etc.) •Fluids used to seal wellbore intervals which negatively impact recovery (cement, resin, polymer, etc.) •Fluids associated with freeze protection (diesel, crude, glycol, methanol, etc.) •Standard oilfield chemicals (corrosion inhibitor, scale inhibitor, etc.) Water Compatibility •Analogous age and deposition reservoirs at CRU indicate no compatibility issue with seawater or producer water injection. •Potential for barium sulfate scale formation when mixing sulfate rich seawater with barium rich formation water. •Minke wells will be included in the CRU scale inhibition program which includes regular produced water sampling and scheduled inhibition treatments. Injection Fluids & Compatibility ConocoPhillips 17 Minke Interval Produced Water Analysis Name Value Unit Aluminum 0.34 mg/l Boron 11.63 mg/l Barium 1.42 mg/l Bicarbonate 656.3 mg/l Calcium 171 mg/l Carbonate 0 mg/l Chloride 10,581 mg/l Conductivity 17,540 uS/cm Iron 5.77 mg/l Formate 16 mg/l Potassium 61.09 mg/l Lithium 0.95 mg/l Magnesium 157 mg/l Manganese 0.077 mg/l Sodium 7,951 mg/l Phosphorus 0.12 mg/l PH 7.42 Silicon 8.57 mg/l Sulfate 253 mg/l Specific Gravity @ 60 degrees F 1.0124 Strontium 5.26 mg/l Sulfide 2 mg/l Zinc 0.06 mg/l CD5-32X Produced Water Sample: Minke Formation Sample date: 4/5/2024, analyses performed at Kuparuk Lab Sustained ~18% water cut produced from CD5-32X long-term production Total dissolved solids of produced water are in excess of 19,000 mg/l •Exceeds 10,000 mg/l cut-off for freshwater ConocoPhillips 18 Request for Finding of No Freshwater Aquifer •CPAI requests a finding in the MOP Order that no freshwater aquifers are present in the MOP area as it has been demonstrated by CPAI and concluded by AOGCC with the Alpine Pool application and amendments there are no freshwater aquifers in CRU and the MOP is within CRU. •Request is to avoid duplicative reviews of whether there are freshwater aquifers in the MOP area in future injection well permit to drill applications. ConocoPhillips 19 Summary Request for approval for the Minke Oil Pool and a pilot enhanced recovery injection order Pilot enhanced recovery injection order: •Duration: Three years •Interval of interest: Minke •Location: Western CRU •Fluids: As noted in application and this presentation 20ConocoPhillips Proposed Pool Rules Proposed Pool Rules •Rule 1: Field and Pool Name •The field is the Colville River Field, and the pool is the Minke Oil Pool. •Rule 2: Pool Definition •The Minke Oil Pool is defined as the accumulation of oil and gas common to and correlating with the interval within the CD5-22 well between the depths of 5,222 feet and 6,433 feet MD (-4,333 feet and -5,194 feet TVDSS, respectively). •Rule 3: Well Spacing •There shall be no restrictions as to well spacing except that no pay shall be opened to a well within 500’ of an external property line where the owners and landowners are not the same on both sides of the line. •Rule 4: Drilling and Completion Practices a)Alternate casing and completion programs, in addition to those specified in the regulations, may be administratively approved by the Commission upon application and presentation of data which demonstrate the alternatives are appropriate, based upon sound engineering principles. b)In lieu of the requirements under 20 AAC 25.050(b), CPAI proposes that permit(s) to drill shall include: plan view, vertical section, close approach data, and directional data. c)In lieu of the requirements under 20 AAC 25.071(a), CPAI proposes that only one well per drill site is required to be logged for the portion of the well below the conductor pipe by either a complete electrical log or a complete radio-activity log unless the commission specifies which type of log is to be run. This has already been satisfied for drill site CD5, the primary pad from which Minke development wells will be drilled. The AOGCC may, in its discretion, require additional wells on a pad to be logged using a complete petrophysical log suite. ConocoPhillips 22 Proposed Pool Rules, Continued •Rule 5: Automatic Shut-in Equipment •Injection wells must be equipped with a.A double check valve arrangement or b.A single check valve and a surface safety valve (SSV). A subsurface-controlled injection valve, or “SCSSV” satisfies the requirements of a single check valve •Rule 6: Reservoir Surveillance a)A bottom-hole pressure survey shall be conducted in each well prior to initial injection. b)The operator shall obtain the pressure surveys needed to manage properly the hydrocarbon recovery processes subject to the annual plan outlined in Rule 8 below. At a minimum, a pressure survey shall be acquired from at least one well in the Minke Oil Pool on each drill site each year c)The Reservoir Pressure Datum will be -4,320 feet TVDSS. d)Pressure surveys may consist of stabilized static pressure measurements at bottom-hole or be extrapolated from surface measurements (single phase fluid conditions), pressure fall-off measurements, pressure buildup measurements, multi-rate test results, drill stem test results, and open-hole formation tests or other methods approved by the AOGCC. e)A Reservoir Pressure Report, Form 10-412, shall be utilized for all surveys annually; all relevant data shall be attached to the report. The data submitted shall include, at a minimum, rate, pressure, depth, fluid gradient, temperature, and all other well conditions necessary for a complete analysis of each survey being conducted. f)The results and data from any special reservoir pressure monitoring tests or surveys shall also be submitted in accordance with paragraph (e) of this rule. ConocoPhillips 23 Proposed Pool Rules, Continued •Rule 7: Gas Oil Ratio Exemption •Wells producing from the Minke Oil Pool are exempt from the gas-oil ratio (GOR) limit set forth in 20 AAC 25.240(a) so long as the provisions of 20 AAC 25.240(b) apply. •Rule 8: Annual Reservoir Review •An annual reservoir surveillance report must be filed by April 1st of each year and include future Minke Oil Pool development plans, reservoir depletion plans, and surveillance information for the prior calendar year, including: a.The voidage balance, by month, of produced fluids and injected fluids. b.A summary and analysis of the reservoir pressure surveys within the pool. c.The results and, where appropriate, an analysis of production and injection log surveys, tracer surveys, observation well sur veys, and any other special monitoring. d.A review of pool production allocation factors and issues over the prior year. e.A review of the progress of the enhanced recovery project. ConocoPhillips 24 Proposed Pool Rules, Continued •Rule 9: Annular Pressures a.At the time of installation or replacement, the operator shall conduct and document a pressure test of tubulars and completio n equipment in each development well that is sufficient to demonstrate that planned well operations will not result in failure of well integrity, uncontrolled release of fluid or pressure, or threat to human safety. b.The operator shall monitor each development well daily to check for sustained pressure, except if prevented by extreme weather conditions, emergency situations, or unavoidable circumstances. Monitoring results shall be kept available for AOGCC inspections. c.The operator shall notify the AOGCC within three working days after the operator identifies a well as having (i) sustained inner annulus pressure that exceeds 2,000 psig or (ii) sustained outer annulus pressure that exceeds 1,000 psig. d.The operator shall submit in an Application for Sundry Approvals (Form 10-403) a proposal for corrective action or increased sur veillance for any development well having sustained pressure that exceeds a limit set out in paragraph (c) of this rule. The AOGCC may approve the operator’s proposal or require other actions or surveillance, including a mechanical integrity test or other approved diagnos tic tests. The operator shall give sufficient notice of the testing schedule to allow the AOGCC to witness the test. e.If the operator identifies sustained pressure in the inner annulus of a development well that exceeds 45 percent of the burst pressure rating of the well’s production casing for inner annulus pressure, or sustained pressure in the outer annulus that exceeds 45 percent of the burst pressure rating of the well’s surface casing for outer annulus pressure, the operator shall notify the AOGCC within three working days and take corrective action. Unless well conditions require the operator to take emergency corrective action before AOGCC approval can be obtained, the operator shall submit in an Application for Sundry Approvals (Form 10-403) a proposal for corrective action. The AOGCC may approve the operator’s proposal or require other corrective action, including a mechanical integrity test or other diagnostic tests. The operator shall give the AOGCC sufficient notice of the testing schedule to allow the AOGCC to witness the tests. ConocoPhillips 25 Proposed Pool Rules, Continued •Rule 9: Annular Pressures (Continued) f.Except as otherwise approved by the Commission under (d) or (e) of this rule, before a shut-in well is placed in service, any annulus pressure must be relieved to a sufficient degree: (1) that the inner annulus pressure at operating temperature will be below 2,000 psig, and (2) that the outer annulus pressure at operating temperature will be below 1,000 psig. A well subject to (c) but not (e) of this rule may reach an annulus pressure at operating temperature that is described in the operator’s notification to the AOGCC under (c) of this rule, unless the AOGCC prescribes a different limit. g.For purposes of this rule, I.inner annulus means the space in a well between tubing and production casing; II.outer annulus means the space in a well between production casing and surface casing; and III.sustained pressure means pressure that (A) is measurable at the casing head of an annulus, (B) is not caused solely by temper ature fluctuations, and (C) has not been applied intentionally. •Rule 10: Production Surface Commingling, Measurement, and Allocation a.Production from the Minke Oil Pool, CRU pools, GMTU pools, and future ACF contributing pools may be commingled in surface facilities prior to custody transfer. b.Wells must be tested at least twice per month. •Rule 11: Administrative Action •Upon proper application or its own motion, unless notice and a public hearing are otherwise required the AOGCC may administratively waive the requirements of any rule stated above or administratively amend this order as long as the change does not promote waste, jeopardize correlative rights, or compromise ultimate recovery and is based on sound engineering principles. ConocoPhillips 26 AOGCC 11/19/2024 ITMO: CONOCOPHILLIPS ALASKA'S APPLICATION Docktet No. CO-24-012 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 ALASKA OIL AND GAS CONSERVATION COMMISSION In the Matter of ConocoPhillips Alaska's ) Application for Pool Rules for the ) Development of the Minke Oil Pool in the ) Colville River Unit and an Enhanced ) Recovery Injection Order for the Minke ) Oil Pool. ) __________________________________________) Docket No.: CO-24-012 ERIO-24-001 PUBLIC HEARING Anchorage, Alaska November 19, 2024 10:00 o'clock a.m. BEFORE: Jessie Chmielowski, Commissioner Gregory Wilson, Commissioner AOGCC 11/19/2024 ITMO: CONOCOPHILLIPS ALASKA'S APPLICATION Docktet No. CO-24-012 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 Page 2 1 TABLE OF CONTENTS 2 Opening remarks by Commissioner Chmielowski 03 3 Testimony by Mr. Castongia 09 4 Testimony by Ms. Rodriguez 13 5 Testimony by Mr. Caldoas 16 6 Testimony by Mr. Nagel 17 7 Testimony by Mr. Ward 18 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 AOGCC 11/19/2024 ITMO: CONOCOPHILLIPS ALASKA'S APPLICATION Docktet No. CO-24-012 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 Page 3 1 P R O C E E D I N G S 2 (On record) 3 COMMISSIONER CHMIELOWSKI: All right. Good 4 morning. I will call this hearing to order. It is 5 approximately 10:00 a.m. on Tuesday, November 19th, 6 2024. This is a public hearing on docket numbers CO- 7 24-012 and ERIO-24-001, to consider ConocoPhillips 8 Alaska's application for pool rules to establish rules 9 for the development of the Minke oil pool in the 10 Colville River unit and an enhanced recovery injection 11 order to allow for pilot enhanced oil recovery or EOR 12 injection activities in the Minke oil pool. I am 13 Commissioner Jessie Chmielowski and with me is 14 Commissioner Greg Wilson. Today's hearing is being 15 held in person and via Microsoft Teams. The in person 16 location is the Alaska Oil and Gas Conservation 17 Commission office at 333 West 7th Avenue, Anchorage, 18 Alaska. 19 For those on Teams please be mindful of any 20 background noise and make sure you are muted when 21 you're not testifying or addressing the Commission. 22 If you require any special accommodation please 23 contact Samantha Coldiron. She can be reached at 907- 24 793-1223 or send her a message through the Microsoft 25 Teams chat icon and she will do her best to accommodate AOGCC 11/19/2024 ITMO: CONOCOPHILLIPS ALASKA'S APPLICATION Docktet No. CO-24-012 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 Page 4 1 you. 2 Samantha Coldiron will be recording the 3 hearing. Computer Matrix will be preparing the 4 transcript. Upon completion and preparation of the 5 transcript anyone desiring a copy will be able to 6 obtain it by contacting Computer Matrix. 7 This hearing is being held in accordance with 8 Alaska statute 44.62 and 20 AAC 25.540 of the Alaska 9 Administrative Code. 10 The notice of hearing was published on the 11 state of Alaska web -- online notices website as well 12 as the AOGCC's website and was sent through the AOGCC 13 email listserv on October 8th, 2024. The AOGCC also 14 published the notice in the Anchorage Daily News on 15 October 9th, 2024. To date the AOGCC has not received 16 any public comments on this matter. 17 As some background, the AOGCC prescribes pool 18 rules that govern the development of oil and gas pools 19 when a modification of the statewide regulation is 20 needed to facilitate development of the pool. Some 21 common rules are modification of the permit to drill 22 application process to streamline applications and of 23 the data collection requirements when additional data 24 would not add to the understanding of the geology in a 25 project area. Additionally the AOGCC approves AOGCC 11/19/2024 ITMO: CONOCOPHILLIPS ALASKA'S APPLICATION Docktet No. CO-24-012 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 Page 5 1 injection orders for several purposes including 2 enhanced oil recovery, EOR, storage and disposal either 3 on an individual well or an area-wide basis in Alaska. 4 EOR injection orders establish rules for conducting 5 operations that are intended to increase the amount of 6 oil and gas or gas that could be recovered from a pool 7 by one or more of the following mechanisms. 8 Maintaining reservoir energy, sweeping oil through the 9 reservoir to a production well or modifying the 10 properties of the oil to make it more mobile. This is 11 consistent with the portion of the AOGCC's mission that 12 seeks to promote greater ultimate recovery. 13 The Commissioners will ask questions during 14 testimony. We may also take a recess to consult with 15 Staff to determine whether additional information or 16 clarifying questions are necessary. 17 After ConocoPhillips presents and members from 18 the public have an opportunity to testify we will take 19 a moment to clear the room to begin the confidential 20 presentation from ConocoPhillips. 21 Representatives from ConocoPhillips, are you 22 ready to make your presentations. 23 (Inaudible response> 24 COMMISSIONER CHMIELOWSKI: Great. So I will 25 swear in the witnesses. So those of you who are going AOGCC 11/19/2024 ITMO: CONOCOPHILLIPS ALASKA'S APPLICATION Docktet No. CO-24-012 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 Page 6 1 to testify will you please raise your right hand and 2 respond. 3 (Oath administered) 4 IN UNISON: I do. 5 COMMISSIONER CHMIELOWSKI: Okay. Let the 6 record reflect the witnesses all responded in the 7 affirmative. 8 Do any of you presenting today wish to be 9 recognized as experts? 10 (Inaudible response) 11 COMMISSIONER CHMIELOWSKI: Yes. Okay. So 12 please identify your field of expertise and your 13 credentials and we'll start over here on the left, I 14 think you have a slide for that possibly, if you'd like 15 to speak to that then go ahead. 16 MR. CASTONGIA: Hello, my name is Ethan 17 Castongia here. This slide today lists all those who 18 will -- who will be testifying, their area of expertise 19 as well as years of experience. All those listed on 20 the slide wish to be sworn in as expert witnesses in 21 the area underlined. 22 Would you like us to go individually or is this 23 sufficient? 24 COMMISSIONER CHMIELOWSKI: Yeah, individual 25 will be great. AOGCC 11/19/2024 ITMO: CONOCOPHILLIPS ALASKA'S APPLICATION Docktet No. CO-24-012 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 Page 7 1 MR. CASTONGIA: Okay. My name is Ethan 2 Castongia. As there on the slide I have a bachelor's 3 of science in geology with a concentration in 4 geophysics from the University of Illinois Urbana- 5 Champaign and a master's of science in geophysics from 6 the University of Wisconsin Madison. I have 10 years 7 of experience all with ConocoPhillips, approximately 8 eight years in Alaska related to field appraisal and 9 development, exploration and technology. 10 COMMISSIONER CHMIELOWSKI: Thank you. 11 MR. WARD: Hello. My name's Dusty Ward. I'm a 12 Completions Engineer, bachelor of science in mechanical 13 engineering from George Fox University and a master of 14 science in industrial engineering from Oregon State 15 University. I have about 11 and a half years of oil 16 and gas experience with ConocoPhillips in Alaska, five 17 of those were in the Cook Inlet and six and a half of 18 those has been as a wells engineer. 19 COMMISSIONER CHMIELOWSKI: Thank you. 20 MR. NAGEL: Good morning. My name is Matt 21 Nagel and I am a drilling engineer. I have a 22 bachelor's of science in petroleum engineering from 23 Texas Tech University, I have 12 years of industry 24 experience, nine of those with ConocoPhillips, five 25 years in Alaska across various unconventional and AOGCC 11/19/2024 ITMO: CONOCOPHILLIPS ALASKA'S APPLICATION Docktet No. CO-24-012 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 Page 8 1 conventional assets. 2 COMMISSIONER CHMIELOWSKI: Thank you. 3 MS. RODRIGUEZ: Good morning. My name is Erika 4 Rodriguez, I'm the Geologist. I have a bachelor's of 5 science from the -- from New Mexico Institute of Mining 6 and Technology. I also have a master's of science from 7 Texas A&M University. I have about 19 years of 8 industry experience all with ConocoPhillips. I worked 9 in lower 48 development (indiscernible) ventures, 10 Alaska exploration and Alaska development. 11 Thanks. 12 MR. GONZALES: Good morning. My name is Cedric 13 Caldoas, I'm the Reservoir Engineer. I have a 14 bachelor's of science in petroleum engineering from the 15 University of Texas at Austin and a master's of science 16 in petroleum engineering from the University of Texas 17 at Austin. I have 14 years of industry experience, 13 18 of those with ConocoPhillips and nine of them in Alaska 19 in various development roles. 20 COMMISSIONER CHMIELOWSKI: Thank you. 21 Commissioner Wilson, are you satisfied with the 22 expertise and credentials as presented? 23 COMMISSIONER WILSON: I am. 24 COMMISSIONER CHMIELOWSKI: Great. I have no 25 objection. You will all be recognized as experts in AOGCC 11/19/2024 ITMO: CONOCOPHILLIPS ALASKA'S APPLICATION Docktet No. CO-24-012 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 Page 9 1 the field you identified. 2 Before we begin the presentation, Commissioner 3 Wilson, do you have any questions? 4 COMMISSIONER WILSON: Nothing at this time. 5 COMMISSIONER CHMIELOWSKI: Okay. Great. So 6 for those of you who are testifying please remember to 7 speak into the microphone, there's a really bright 8 green button, and so that we can capture your -- you 9 for the record. Also please reference your slides by 10 number or title so that someone reading the record can 11 follow along and then before you begin speaking please 12 state your name and title clearly and then please 13 begin. 14 ETHAN CASTONGIA 15 previously sworn, called as a witness on behalf of 16 ConocoPhillips, testified as follows. 17 MR. CASTONGIA: Thank you. My name is Ethan 18 Castongia on behalf of ConocoPhillips Alaska. We are 19 here today to present on the proposed applications for 20 the requested formation of the Minke oil pool and the 21 enhanced recovery area injection. Before we begin I'd 22 like to thank the AOGCC Staff who met with us and 23 provided feedback prior to final submission. 24 We're on slide 3 now. This is a simple agenda 25 for our presentation today. It also lists those AOGCC 11/19/2024 ITMO: CONOCOPHILLIPS ALASKA'S APPLICATION Docktet No. CO-24-012 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 Page 10 1 individuals who will be covering each topic in today's 2 presentation. Please note at the end there is an 3 additional confidential geology section we can cover if 4 it is deemed necessary. 5 Slide 4 now. This is purely a reference slide 6 that contains a list of acronyms that may be used 7 during the presentation today or found on the slides in 8 the presentation. 9 Slide 5. I will begin with an area overview. 10 The map on the right side of the slide shows the areas 11 of interest. Included on the map are highlighted in 12 yellow with the red border is the current Colville 13 River unit along with the Greater Moose's Tooth unit 14 which are operated and owned 100 percent by 15 ConocoPhillips. 16 The blue dashed polygon is the proposed area of 17 the Minke oil pool associated with our application 18 submitted to AOGCC. The black dashed polygon is the 19 proposed Minke participating area. The application for 20 the formation of this PA is also pending with DNR. The 21 green and blue lines within these two polygons are the 22 planned Minke horizontal wells as part of the Minke 23 enhanced recovery injection order associated with our 24 application submitted to AOGCC. The blue lines are the 25 injectors with CD 56-97 planned to be drilled in AOGCC 11/19/2024 ITMO: CONOCOPHILLIPS ALASKA'S APPLICATION Docktet No. CO-24-012 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 Page 11 1 December, 2024. The other wells, CD 56-33, with be 2 drilled as part of a lady -- later Minke development 3 phase. The green line is the producer. CD 56-29 4 planned to be drilled after CD 56-97 injector. These 5 two wells make up Minke phase I development. 6 Also shown on the map are the penetrations of 7 the Minke interval from the wells drilled in the area 8 that are available for mapping. These are indicated by 9 the green circles placed where each of these wellbores 10 intersect to the top of the Minke. Most of these wells 11 were drilled to deeper reservoirs and had a mix of data 12 collection through the Minke interval typically with 13 basic LWD suites including gamma ray resistivity. A 14 few wells have density logs and occasionally sonic. 15 These wells provide good depth, thickness and general 16 mapping control to define the Minke trend in the CD 5 17 area. Highlighted in the call out boxes and where they 18 penetrate Minke are ConocoPhillips key wells for Minke 19 and provide supporting data for our applications. 20 These include CD 5-32X, the first dedicated Minke well 21 drilled in 2024. This well included whole core 22 advanced logging, multiple short term pressure and flow 23 testing and is tied into CD 5 as a producer. CD 5-22 24 is the other well which is our proposed type well for 25 definition of the Minke oil pool. AOGCC 11/19/2024 ITMO: CONOCOPHILLIPS ALASKA'S APPLICATION Docktet No. CO-24-012 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 Page 12 1 Prior to leaving this slide I'd also like to 2 mention the surface owners who are within the blue 3 dashed polygon and a quarter mile buffer around it. 4 They include the Kuukpik Corporation and the Bureau of 5 Land Management. All have been notified and sent a 6 copy of our application -- applications. Sorry. 7 COMMISSIONER CHMIELOWSKI: Thank you, Mr. 8 Castongia. I believe drilling permits have been 9 received at the AOGCC for a couple of the wells at 10 least or one. 11 MR. CASTONGIA: Correct. 12 COMMISSIONER CHMIELOWSKI: So what is the 13 timing for drilling the pilot wells and what is, you 14 know, the timing for full development of the proposed 15 pool? 16 MR. CASTONGIA: The timing of the two wells 17 that have had the permit submitted so far, the first 18 one is scheduled to be in December of this year, 2024, 19 the CD 5-697 injector, followed up right afterwards in 20 January of 2025, the CD 5-629 producer subject to rig 21 schedule. The full development wells, that is an 22 ongoing scheduling determination that we are doing 23 based on the one rig scenario that we have in CRU and 24 other targets that we are also looking to drill such as 25 Narwhal and then GMT 2. AOGCC 11/19/2024 ITMO: CONOCOPHILLIPS ALASKA'S APPLICATION Docktet No. CO-24-012 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 Page 13 1 COMMISSIONER CHMIELOWSKI: Would you say it's a 2 couple years out possibly? 3 MR. CASTONGIA: Yes. 4 COMMISSIONER CHMIELOWSKI: Yeah. Okay. Thank 5 you. 6 MR. CASTONGIA: Also with that too is just the 7 existing well slots that STD 5 wouldn't cover the whole 8 Minke oil pool so a CD 5 expansion would be needed to 9 cover the whole oil pool. 10 COMMISSIONER CHMIELOWSKI: Okay. Thank you. 11 MR. CASTONGIA: So slide 6. Erika Rodriguez 12 will now present on the geology of the Minke oil pool. 13 ERIKA RODRIGUEZ 14 previously sworn, called as a witness on behalf of 15 ConocoPhillips, testified as follows. 16 MS. RODRIGUEZ: Good morning. I am Erika 17 Rodriguez and we are on slide 7. This slide shows the 18 proposed type log for the Minke oil pool which is a CD 19 5-22 well, drilled from the CD 5 pad within the 20 Colville River unit. Its location is highlighted on 21 the map in the middle of the slide. The proposed Minke 22 oil pool is highlighted in yellow on the log display 23 which has gamma ray on the first track followed by 24 resistivity and density neutron in the subsequent non- 25 depth track. The Minke reservoir interval is part of AOGCC 11/19/2024 ITMO: CONOCOPHILLIPS ALASKA'S APPLICATION Docktet No. CO-24-012 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 Page 14 1 the regional Nanushuk formation. It is bound below by 2 the lower confining interval which consists of slope 3 setting, mud dominated, heterolithic sequences 4 associated with the Torok formation present in 5 thicknesses greater than 300 feet TVD. It should be 6 noted that the Torok formation formed the lower 7 confining interval of the Colville River unit Conic oil 8 pool. The Minke interval is bound above by flooding 9 shells within the Nanushuk formation present in 10 thicknesses of 100 feet to greater than 200 feet TVD. 11 COMMISSIONER CHMIELOWSKI: Ms. Rodriguez, 12 looking at this CD 5-22 log, it looks like the Minke 13 oil pool's about 1,200 feet measured depth. Is it 14 similar in TVD? 15 MS. RODRIGUEZ: Yes. 16 COMMISSIONER CHMIELOWSKI: Yeah. Thank you. 17 MS. RODRIGUEZ: In slide 8 I have displayed a 18 depth structure map on the top of the proposed Minke 19 oil pool. The structure at this level is generally low 20 relief with structural dips of approximately one 21 degree. There are no seismically resolvable faults 22 maps on the stratigraph -- at this stratigraphic level. 23 The only area where dip is much greater than one degree 24 is the east out where Min -- which is the -- out where 25 Minke's final associated shelf margin. AOGCC 11/19/2024 ITMO: CONOCOPHILLIPS ALASKA'S APPLICATION Docktet No. CO-24-012 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 Page 15 1 We are on slide 9. This slide include two 2 structurally datum well log cross sections, A to A 3 prime and B to B prime at the bottom. The locations of 4 the cross sections can be seen in the inset structure 5 map on the right side of the slide. Both cross 6 sections have gamma ray to the left of the depth track 7 and resistivity to the right. All values greater than 8 seven ohm have been shaded in green. In the A to A 9 prime section on the upper portion of the slide, this 10 is a dip oriented section that trends from northwest to 11 southeast. The pay interval is at the top of the Minke 12 oil pool package, on this cross section you can see 13 that the pay interval thins to the west and thickens to 14 the east. The second section, B to B prime, is a 15 strike oriented cross section trending from southwest 16 to northeast. The Minke gross thicknesses are 17 generally consistent in a strike parallel orientation. 18 The oil/water contact is at 44 -- minus 4,400 TVD 19 subsea is displayed in both cross sections and the 20 structure map by a blue dashed line. Both sections 21 highlight the Minke interval in yellow shading and the 22 upper and lower confining intervals in gray shading. 23 COMMISSIONER WILSON: I have a question 24 regarding the oil/water contact. 25 MS. RODRIGUEZ: Yes. AOGCC 11/19/2024 ITMO: CONOCOPHILLIPS ALASKA'S APPLICATION Docktet No. CO-24-012 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 Page 16 1 COMMISSIONER WILSON: How is that defined in 2 the wells? 3 MS. RODRIGUEZ: The oil/water contact was 4 defined with the MBT log -- the MBT samples that were 5 collected in the CD 5-32X. We were able to capture the 6 entire column, both the oil and then the water which is 7 roughly at minus 4,400. 8 COMMISSIONER WILSON: Thank you. 9 CEDRIC CALDOAS 10 previously sworn, called as a witness on behalf of 11 ConocoPhillips, testified as follows. 12 MR. GONZALES: My name is Cedric Caldoas we're 13 on slide 10, resource and recovery. 14 Slide 11. This slide summarizes the reservoir 15 properties and volumetric in place for the Minke pool. 16 Volumetric estimates are based off the mapping of core 17 calibrated, log model results from wells within and 18 beyond the proposed pool area guided by 3D seismic 19 interpretation. The fluid properties are based off TVD 20 analysis of the MDT samples obtain from 30 -- CD 5-32X. 21 The recovery factors are preliminary from analog 22 reservoirs and type pattern mono reservoir simulations. 23 Neither Skall nor EORPPT is available at this time so 24 significant uncertainty remains in these recovery 25 factors. The initial development plan premise is water AOGCC 11/19/2024 ITMO: CONOCOPHILLIPS ALASKA'S APPLICATION Docktet No. CO-24-012 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 Page 17 1 flood only, gas injection is not initially premised, 2 but will be evaluated once your PPT work is completed. 3 Note that the well count shown covers the PA area only. 4 COMMISSIONER CHMIELOWSKI: Thank you. So the 5 reserve counts for the total proposed pool area? 6 MR. GONZALES: That's correct. 7 COMMISSIONER CHMIELOWSKI: Okay. Thank you. 8 MATT NAGEL 9 previously sworn, called as a witness on behalf of 10 ConocoPhillips, testified as follows. 11 MR. NAGEL: Good morning. Matt Nagel, Drilling 12 Engineer and I will be covering slide 13, well design. 13 The proposed three string well design is similar to 14 other wells drilled in WNS and specifically on the CD 5 15 pad. A teeth tearing design is still under evaluation 16 by ConocoPhillips. Surface casing will be cemented 17 back to surface fully covering the permafrost. 18 Intermediate casing will be set and cemented in the 19 Minke formation to isolate all hydrocarbon bearing 20 zones as per AOGCC regulation with cement quality logs 21 provided to demonstrate isolation. Production will 22 consist of both cemented and uncemented liner located 23 within the reservoir section. The production packer 24 may be located greater than the 200 feet measured depth 25 from the top of the intended injection interval which AOGCC 11/19/2024 ITMO: CONOCOPHILLIPS ALASKA'S APPLICATION Docktet No. CO-24-012 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 Page 18 1 shall be located with the -- within the confining zone 2 and at least a hundred feet below the top of cement. 3 All proposed drilling and completion operations will be 4 performed in accordance with applicable AOGCC 5 regulations. 6 COMMISSIONER CHMIELOWSKI: So just to clarify. 7 ConocoPhillips does not expect any significant 8 hydrocarbon zones in between the top of the cement and 9 the production casing and the surface casing? 10 MR. NAGEL: If any log indicate that there are 11 hydrocarbons they will be cemented. 12 COMMISSIONER CHMIELOWSKI: Okay. And is Conoco 13 using the updated criteria that was developed during 14 the CD 1 lease? 15 MR. NAGEL: That is correct. 16 COMMISSIONER CHMIELOWSKI: Thank you. 17 DUSTY WARD 18 previously sworn, called as a witness on behalf of 19 ConocoPhillips, testified as follows. 20 MR. WARD: Hello. My name's Dusty Ward, 21 Completions Engineer and I'll be covering the next few 22 slides. 23 Slide 14. Slide 14 covers information on the 24 fracture geometry of CD 5-32X. The stimulation of CD 25 5-32X well included carbo NRT tracer to help gather a AOGCC 11/19/2024 ITMO: CONOCOPHILLIPS ALASKA'S APPLICATION Docktet No. CO-24-012 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 Page 19 1 better understanding of fracture height growth in the 2 Minke. The results of the carbo NRT tracer log are 3 overlaid between the fracture model on the right and 4 the well log on the left. The now list just shows 5 there is fracture present over an approximately 161 6 foot interval and 4,394 MD to 5,135 feet MD which is 7 indicated by the bright yellow on the right track of 8 the log. The orange section in the second to right 9 track indicates strong proppant signal from 5,009 feet 10 measured depth to 5,050 feet measured depth and then at 11 deeper intervals from 5,112 measured depth to 5,135 12 foot measured depth. To the right of the carbo NRT 13 analysis is a fracture geometry created by matching the 14 bottom hole pressure during the stimulation using 15 Gopher Fracture modeling software. 16 The inputs for the history match for CD 5 32 17 log. The color scale on the right side of the fracture 18 image represents the proppant concentration through the 19 fracture scale from .5 to three pound per foot squared. 20 This history match simulated fracture geometry does not 21 show significant growth into the confining layer 22 although the tracer results do show some growth. 23 Perspectively prop fracture height in the 1.8 to 3 24 pound per foot squared range of the model largely 25 matches the stronger signal from the carbo NRT in the AOGCC 11/19/2024 ITMO: CONOCOPHILLIPS ALASKA'S APPLICATION Docktet No. CO-24-012 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 Page 20 1 upper 32 to 40 feet of the Minke interval. This status 2 suggests minimal and ineffective prop width in the 3 confining interval. As seen in the log on the left 4 there is also a cemented streak right at the top of the 5 Minke pay interval which was verified by Equotip 6 measurements at the core. This one to two foot hard 7 streak appears to help influence the fracture downward. 8 Lateral placement of CD 5-697 and CD 5-629 are planned 9 within the Minke formation and at least 10 feet below 10 the top of the Minke. This design should allow similar 11 proppant coverage where there's adequate connectivity 12 in the Minke, but not in the confining layer. 13 COMMISSIONER CHMIELOWSKI: Thank you. And just 14 to confirm the plan is -- would be to frack all three 15 wells, injectors and the producer? 16 MR. WARD: Correct. 17 COMMISSIONER CHMIELOWSKI: Yeah. 18 MR. WARD: That is the base plan. I will 19 continue at slide 15 on injection containment. On the 20 left side is a model of minimum horizontal stress. The 21 overburden fracture closure pressure gradient is 22 calculated to be approximately .71 PSI per foot. The 23 overburden data was calibrated using three microfrack 24 tests done on CD 5-32X with SLB's MBT tool. The Minke 25 fracture closure pressure gradient was calculated to be AOGCC 11/19/2024 ITMO: CONOCOPHILLIPS ALASKA'S APPLICATION Docktet No. CO-24-012 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 Page 21 1 0.6 PSI per foot approximately from the CD 5-32X frack. 2 The difference between these two gradients at Minke 3 depth equates to nominally a 500 PSI difference between 4 the Minke reservoir layer and the confining layer 5 fracture closure pressures. The injection pressure 6 will stay below the overburden fracture gradient like 7 other operating areas. On the right the micro frack 8 point are plotted as red triangles and TVD alongside 9 the Minke's initial pore pressure gradient, target 10 injection gradient and maximum injection gradient. For 11 example at 4,400 feet TVD it is estimate the initial 12 pore pressure is 2,050 PSI, the target injection 13 pressure would be 2,0625 PSI and maximum injection 14 pressure would be 3,100 PSI. 15 COMMISSIONER WILSON: I have a question and 16 it's probably a geology question and maybe go back to 17 slide 14 where you talked about minimal fracture into 18 the overburden. I'm just curious what is the minimum 19 vertical distance to any porosity I guess in the sand 20 stringers above the top of the Minke? 21 MS. RODRIGUEZ: Let me take a quick look here. 22 COMMISSIONER WILSON: Okay. Approximate is 23 good enough too. 24 MS. RODRIGUEZ: Yeah, I -- it's approximately I 25 would say about 300 feet above us we have sand. AOGCC 11/19/2024 ITMO: CONOCOPHILLIPS ALASKA'S APPLICATION Docktet No. CO-24-012 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 Page 22 1 There's four corseting upward packages still in the 2 Nanushuk above the Minke section. A lot of those sands 3 are -- have some porosity, but are generally pretty 4 tight. I think the first one is roughly 200 feet above 5 our Minke interval if that's what you mean. 6 COMMISSIONER WILSON: Okay. And does that 7 develop into Conic or another significant reservoir? 8 MS. RODRIGUEZ: Yes. So we do have also Conic 9 here. So and Conic here is tight. We do observe mud 10 gas shows in it whenever we drill through it, but we 11 don't see any reservoir quality. We also see a two 12 foot pay interval in the K3 sand so that would roughly 13 be about 650 feet above the top of the Minke. And that 14 has been identified in the CD 5-32X as having about I 15 think 25 percent porosity and about -- the water 16 saturation is in the sixties. So it's uncertain if 17 that would actually flow hydrocarbons, but we did see a 18 mud gas show in that interval as well. 19 COMMISSIONER WILSON: Okay. Thank you. 20 MR. WARD: And this is Dusty Ward, Completion 21 Engineer again. I will continue with slide 16. This 22 table lists well within a quarter mile of the proposed 23 area. No mechanical integrity issues are noted at this 24 time on any of the wells. Wells CD 5-21 and CD 5-32X 25 have cement isolation across the entire Minke interval AOGCC 11/19/2024 ITMO: CONOCOPHILLIPS ALASKA'S APPLICATION Docktet No. CO-24-012 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 Page 23 1 currently. CD 5 32X tubing is open to the Minke 2 formation. Wells without full outer analysis cement 3 across the Minke, CD 5-92, C 5-93, CD 5-98 and CD 5- 4 314X will be monitored for pressure on the outer 5 analysis at minimum daily for the life of the well. 6 During any fracture stimulation any wells with a half 7 mile radius of the fracture pore will be monitored 8 during the frack. 9 COMMISSIONER CHMIELOWSKI: Mr. Ward, would you 10 say that fracking is an integral part of this pilot 11 program? 12 MR. WARD: I would 13 COMMISSIONER CHMIELOWSKI: Okay. So do you 14 know -- do you have a list of the mechanical condition 15 of the wells within a half mile of the pilot area since 16 -- since they will be fracked, is that available? 17 MR. WARD: We are working on it for the frack 18 sundry..... 19 COMMISSIONER CHMIELOWSKI: Okay. 20 MR. WARD: .....to get ready for that. 21 COMMISSIONER CHMIELOWSKI: Okay. And then 22 Conoco's requesting a larger pool area to be approved. 23 Do you have -- do you have or would you have a list of 24 all the wells affected within a half mile of the full 25 area, you know, the full pool. I'm just trying to AOGCC 11/19/2024 ITMO: CONOCOPHILLIPS ALASKA'S APPLICATION Docktet No. CO-24-012 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 Page 24 1 understand the extent to consider approving this pool, 2 what's the extent of uncemented wells within the whole 3 proposed pool? Does that make sense? 4 MR. WARD: Yes. Let me consult real quick with 5 my..... 6 COMMISSIONER CHMIELOWSKI: Sure. Yeah. And 7 these are just questions I have, we could potentially 8 as always leave the record open if that's something we 9 decide we need..... 10 MR. WARD: Okay. 11 COMMISSIONER CHMIELOWSKI: .....to make a 12 decision. 13 MR. WARD: Okay. 14 COMMISSIONER CHMIELOWSKI: I'm not meaning just 15 to have it on the spot, but if you need to take a 16 moment go ahead. 17 MR. WARD: Okay. Thank you. Yeah, I think we 18 could get that data for you as it would span most of 19 the CD 5 pad it would bring in most of the legacy CD 5 20 wells as we evaluate that. So..... 21 COMMISSIONER CHMIELOWSKI: Okay. Great. So 22 we'll consult and decide if we want that information 23 and let you know. 24 MR. WARD: Okay. 25 COMMISSIONER CHMIELOWSKI: Great. On -- oh, go AOGCC 11/19/2024 ITMO: CONOCOPHILLIPS ALASKA'S APPLICATION Docktet No. CO-24-012 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 Page 25 1 ahead. I think we can go ahead and proceed. I 2 have..... 3 COMMISSIONER WILSON: I do have a question 4 regarding the cement still just to..... 5 COMMISSIONER CHMIELOWSKI: Okay. 6 COMMISSIONER WILSON: .....get a little bit 7 more detail. You quantify some as saying the outer 8 annulus has some of Minke uncemented and then could -- 9 could you -- and then you have outer annulus 10 uncemented. Could you describe I guess what some of 11 Minke uncemented means? 12 MR. WARD: Yes. 13 MS. RODRIGUEZ: Can I take this? 14 (Inaudible response) 15 MS. RODRIGUEZ: Okay. This is Erika Rodriguez. 16 So when we say partial cement we mean that most of the 17 section of Minke that has resistivities higher than 7 18 ohms which is roughly what we consider pay are covered 19 by cement, but usually there's a portion at the bottom 20 where we have lower net to gross or shaley intervals 21 and there's a couple of wells where those are not -- 22 that -- those intervals are not cemented, but the upper 23 part where the main part of the pay is is cemented. 24 COMMISSIONER WILSON: Would it be correct to 25 say where some of Minke is uncemented you've made an AOGCC 11/19/2024 ITMO: CONOCOPHILLIPS ALASKA'S APPLICATION Docktet No. CO-24-012 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 Page 26 1 attempt at cementing and where you say it's uncemented 2 there was no attempt. Is that a correct statement? 3 MS. RODRIGUEZ: Yeah. So when -- where it was 4 uncemented there was no attempt because both of those 5 wells were where the Minke pay had not been identified 6 priorly -- prior like when the well was drilled. 7 COMMISSIONER WILSON: Okay. Thank you. 8 MR. CALDOAS: This is Cedric Caldoas and we're 9 on slide 17. Slide 17 itemizes injection fluids for 10 Minke. Primary injection fluids, produced water or 11 seawater, will be injected into the reservoir to 12 replace voidage and to enhance recovery. As previously 13 mentioned gas injection is being evaluated pending TVTR 14 work. Secondary injection fluids include those used 15 during frack stimulation, for reservoir surveillance 16 such as tracers to improve near well or injectivity 17 such as solvents or acids. The seal wells or intervals 18 which negatively impact recovery such as cement, resins 19 and polymers for freeze protection such as diesel, 20 crude oil, glycol methanal and standard oilfield 21 chemicals such as corrosion inhibitor and scale 22 inhibitor. The conic water in the reservoir has the 23 potential for barium sulfate scale formation. Produced 24 water injection may reduce that risk. Minke wells will 25 be included in the Colville River unit scale inhibition AOGCC 11/19/2024 ITMO: CONOCOPHILLIPS ALASKA'S APPLICATION Docktet No. CO-24-012 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 Page 27 1 program which includes regular water sampling and 2 scheduled inhibition squeeze treatment. 3 COMMISSIONER CHMIELOWSKI: Oh. Sorry, Mr. 4 Caldaris -- Caldoas, sorry. On slide 17 just to 5 confirm ConocoPhillips is not asking for gas injection 6 at this time, just water? 7 MR. CALDOAS: That's correct. 8 COMMISSIONER CHMIELOWSKI: Thank you. 9 MR. CALDOAS: On slide 18. During the 10 production periods of CD 5-32X a sustained water cut of 11 approximately 18 percent was produced. A sample of 12 this water was collected on the 5th of April of 2024 13 and analyzed at the Kuparuk lab. Results of that 14 analysis are included in the table on the right-hand 15 side of this slide. Total dissolved solids of the 16 Minke interval produced water are in excess of 19,000 17 milligrams per liter which exceeds the 10,000 18 milligrams per liter cutoff for freshwater. 19 MR. CASTONGIA: We're on slide 19 and this is 20 Ethan Castongia again. ConocoPhillips Alaska requests 21 a finding in the Minke oil pool order that no 22 freshwater aquifers are present in the Minke pool -- 23 oil pool area. As it has been determined or 24 demonstrated, sorry, by ConocoPhillips Alaska and 25 concluded by AOGCC with the Alpine pool application and AOGCC 11/19/2024 ITMO: CONOCOPHILLIPS ALASKA'S APPLICATION Docktet No. CO-24-012 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 Page 28 1 amendments there are no freshwater aquifers in CRU and 2 the Minke oil pool is within CRU. This request is to 3 avoid duplicate reviews of whether there are freshwater 4 aquifers in the Minke oil pool area and future 5 injection well permit to drill applications. 6 We're now on slide 20. In closing 7 ConocoPhillips Alaska requests approval for the Minke 8 oil pool and a pilot enhanced recovery injection order. 9 This ERIO is for a period of three years for the Minke 10 interval located at CD 5 pad in the western portion of 11 the Colville River unit for the fluids outlined in this 12 presentation and that are contained within the 13 application. This will give ample time to understand 14 injectivity into the Minke interval, collect and 15 analyze additional data and potentially drill a follow- 16 up injector to complete a fully supported producer 17 centered pattern. 18 That concludes the prepared public presentation 19 materials. The following slides are simply a cut and 20 paste of the proposed rules from our pool application 21 for reference. I was not planning on reading through 22 them unless you'd like me to. Additionally there is 23 the confidential geology section which we can go to if 24 needed. At this point we'd be happy to discuss 25 anything specific that you haven't asked about or if AOGCC 11/19/2024 ITMO: CONOCOPHILLIPS ALASKA'S APPLICATION Docktet No. CO-24-012 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 Page 29 1 you have any questions with respect to the proposed 2 pool rules. 3 COMMISSIONER CHMIELOWSKI: Thank you. I have 4 some questions about understanding OA pressures, you 5 know, it's just like a proposal as far as understanding 6 uncemented -- wells that are uncemented across the 7 Minke. So and wells that are uncemented across the 8 Minke, is there a difference in the OA pressure between 9 uncemented and cemented wells across the Minke? 10 MR. CASTONGIA: You mean like currently..... 11 COMMISSIONER CHMIELOWSKI: Yeah. 12 MR. CASTONGIA: .....is there a difference? 13 I'd need to go back and review that. 14 COMMISSIONER CHMIELOWSKI: Just curious as, you 15 know, the issue has already been observed as far as the 16 Minke elevating OA pressure. 17 MR. CASTONGIA: So this is Ethan Castongia. 18 There are some CD 5 wells that do have some annular 19 disposal that goes on them and they do have some 20 elevated pressures that are different from the ones 21 that don't, but nothing that exceeds any limits that we 22 have done that we've applied for. 23 COMMISSIONER CHMIELOWSKI: Okay. Thank 24 MR. CASTONGIA: Uh-huh. 25 COMMISSIONER CHMIELOWSKI: So what -- so Conoco AOGCC 11/19/2024 ITMO: CONOCOPHILLIPS ALASKA'S APPLICATION Docktet No. CO-24-012 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 Page 30 1 mentioned a monitoring plan as far as monitoring the OA 2 and offset wells that are uncemented during fracking 3 and just during normal operations; is that correct? 4 (Inaudible response) 5 COMMISSIONER CHMIELOWSKI: So what would be the 6 threshold OA pressure to use as a trigger, are you -- 7 are you saying a thousand pounds or is there something 8 lower that would alert you to, you know, communication 9 with the Minke? 10 MR. CASTONGIA: I do believe that a thousand 11 pounds is what we put in for the pool rules and that's 12 what we would be using. 13 COMMISSIONER CHMIELOWSKI: Okay. So what 14 corrective action would ConocoPhillips take if OA 15 pressure reached a thousand pounds and it was suspected 16 that the Minke was involved? 17 MR. CASTONGIA: I mean, during -- during the 18 frack we would shutdown, go to flush and then we would 19 need to regroup at that time. Operationally long term 20 if we observed it we would note -- notify and work with 21 you guys through a plan forward to mitigate and stop 22 that. 23 COMMISSIONER CHMIELOWSKI: So with an OA 24 pressure say at 999, so it didn't exceed the threshold, 25 but you're right up there, could that -- where would AOGCC 11/19/2024 ITMO: CONOCOPHILLIPS ALASKA'S APPLICATION Docktet No. CO-24-012 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 Page 31 1 that pressure go, you think it would stay contained in 2 the OA or are there other zones in these uncemented 3 wells where this could go if it's from the Minke? 4 MR. CASTONGIA: Let me consult with my team. 5 COMMISSIONER CHMIELOWSKI: Okay. 6 MR. CASTONGIA: This is Ethan Castongia here. 7 So there aren't really any other intervals that we 8 think that it would go to other than some isolated not 9 continuously extensive sands such that got flagged with 10 the CD 5 32X since none of the other CD 5 wells had 11 seen anything from that with the updated overburden 12 screening. As far as in a scenario where we were to 13 get to approaching that limit I think that we would try 14 to bleed off the pressure and see if that mitigated the 15 issue there. If it came back that would be a scenario 16 where we would have to be consulting with AOGCC Staff 17 for hey, we are seeing increasing pressure that's not 18 going away and we'd come up with some recommendations 19 at that time for what we would do. 20 COMMISSIONER CHMIELOWSKI: Thank you. And I 21 realize my question might not have been clear. I guess 22 what I was thinking was if there's a zone that would 23 take fluids at 800 pounds. You might not see that at 24 surface, but you would still have out of zone 25 injection. Does that make sense? AOGCC 11/19/2024 ITMO: CONOCOPHILLIPS ALASKA'S APPLICATION Docktet No. CO-24-012 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 Page 32 1 MR. CASTONGIA: Yes, that does. I don't think 2 that we've done a study there for various pressures for 3 any of these non-pay intervals for if they would start 4 taking anything there. 5 COMMISSIONER WILSON: And then I guess for Mr. 6 Castongia, you've been fielding these, but as you can 7 see we are concerned about the uncemented or partially 8 cemented intervals and potential problems down the road 9 from that. And you said if you bled it off and it came 10 right back then you would consult with the AOGCC Staff 11 on a plan forward. But so as not to kick the can too 12 far down the road, what would you see as potential 13 mitigating actions you could take? 14 MR. CASTONGIA: Ultimately there would be 15 basically like we could go in and with a well 16 intervention which is what we are trying to avoid here, 17 to go and try to cement the Minke interval. That's not 18 a real likelihood chance of success and has a bunch of 19 issues for the currently active CD 5 Alpine wells here 20 which we like to keep online. Part of the reason why 21 we are coming with ERIO here is to on a test basis 22 gather some injection data here, see in a small area 23 around CD 5 that we feel like we have a good chance to 24 be able to gather some data that also minimizes the 25 risk here for which intervals, the -- that has AOGCC 11/19/2024 ITMO: CONOCOPHILLIPS ALASKA'S APPLICATION Docktet No. CO-24-012 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 Page 33 1 uncemented Minke through some better quality sections 2 if those do exist which again we haven't looked at all 3 the wells here to fully know that. 4 COMMISSIONER WILSON: Okay. Thank you. 5 COMMISSIONER CHMIELOWSKI: And then I have a 6 question about one of the pool rules to do with the -- 7 like the GOR waiver, what I was thinking of is that, 8 you know, Conoco requests to exempt wells from the GOR 9 waiver and I'm just wondering if that's premature since 10 there is -- the pilot phase is incomplete and so the 11 reservoir property and the (indiscernible) are not as 12 well understood as they might be after the pilot. So 13 it's -- is it appropriate to approve something like a 14 GOR Waiver at this time or should the pool rules be 15 postponed until after the pilot so that the reservoir 16 properties are better understood? 17 MR. CASTONGIA: I would like to take a chance 18 here to confer with my colleagues. Thank you. 19 MR. CALDOAS: This is Cedric Caldoas. I think 20 we're requesting the waiver initially as we analyze the 21 gas injection in the future as well as in case that we 22 are not able to maintain voidage initially. And then 23 as we collect data on how we're able to maintain that 24 voidage we're able to substantiate a long term plan for 25 the GOR limits. AOGCC 11/19/2024 ITMO: CONOCOPHILLIPS ALASKA'S APPLICATION Docktet No. CO-24-012 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 Page 34 1 COMMISSIONER CHMIELOWSKI: Any other questions, 2 Commissioner Wilson, are you ready for a recess? 3 COMMISSIONER WILSON: I'm ready for recess. I 4 think I would like the confidential portion. They said 5 if necessary. I think I would like the confidential 6 portion and then I may have questions there. 7 COMMISSIONER CHMIELOWSKI: All right. We -- I 8 think what we're going to do -- would you like to do 9 that now or towards the end like we had in the script? 10 COMMISSIONER WILSON: We can do it towards the 11 end. 12 COMMISSIONER CHMIELOWSKI: Okay. 13 COMMISSIONER WILSON: I'm just saying that I'll 14 withhold any questions. 15 COMMISSIONER CHMIELOWSKI: We'll make sure we 16 do that. Okay. Sounds good. So we are going to take 17 a recess. We'll take a recess and then we'll do an 18 opportunity for the public to testify and then we will 19 do the confidential section. So I'm going to give us 20 -- let's see, the time is currently 10:46. I'm going 21 to give us 20 minutes. Let's go -- we'll go 11:00, 22 how's that, 11:10 we'll reconvene. Sounds good? 23 (Inaudible response) 24 COMMISSIONER CHMIELOWSKI: All right. Thank 25 you. AOGCC 11/19/2024 ITMO: CONOCOPHILLIPS ALASKA'S APPLICATION Docktet No. CO-24-012 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 Page 35 1 (Off record - 10:46 a.m.) 2 (On record) 3 COMMISSIONER CHMIELOWSKI: We're back on the 4 record. We do have a couple questions. I would like 5 to ask about a question about the request to find no 6 freshwater. So there was a finding in the Alpine pool 7 rules about no freshwater, but the -- you know, the 8 Kuparuk, you know, has expanded substantially since 9 then. So is this proposed Minke area, was that 10 included in that area that was formerly found to have 11 -- previously found to have no freshwater? 12 MR. CASTONGIA: This is Ethan Castongia. In 13 the update or in the expansion of CRU in this area to 14 include Nanook, Kuparuk, an additional study was done 15 and that one did not find any freshwater. The wells 16 that were used in that were Nuiqsut 1, Clover A and 17 then CD 5-21. 18 COMMISSIONER CHMIELOWSKI: Okay. And that was 19 the unit expansion..... 20 MR. CASTONGIA: Yes, correct. 21 COMMISSIONER CHMIELOWSKI: .....for DNR? Okay. 22 MR. CASTONGIA: Uh-huh. Yep. And so then 23 there's the Alpine pool boundary is the Kogo River 24 unit. So then the pool expansion then covers that..... 25 COMMISSIONER CHMIELOWSKI: Okay. AOGCC 11/19/2024 ITMO: CONOCOPHILLIPS ALASKA'S APPLICATION Docktet No. CO-24-012 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 Page 36 1 MR. CASTONGIA: .....unit expansion as 2 well..... 3 COMMISSIONER CHMIELOWSKI: Right. 4 MR. CASTONGIA: .....to my area at some point. 5 COMMISSIONER CHMIELOWSKI: Thank you. 6 MR. CASTONGIA: Uh-huh. 7 COMMISSIONER CHMIELOWSKI: And then I have a 8 question again about the OA pressure and your proposed 9 threshold of a thousand pounds. So could you please 10 explain how a pressure limit of a thousand pounds on 11 the OA will ensure that there isn't out of zone 12 injection? 13 MR. CASTONGIA: Let us discuss a bit more. 14 COMMISSIONER CHMIELOWSKI: Okay. 15 (Pause) 16 MR. WARD: Thank you. This is Dusty Ward. We 17 would largely be monitoring the OAs and after injection 18 begins we could compare with historical OA pressures as 19 a means to help us identify any issue. And then as 20 stated earlier we'd try to avoid, but there could be 21 other -- if we were to discover that then we would 22 reach out to AOGCC to look for mitigation plans at that 23 point. But comparing with historicals would probably 24 be our main knob (ph) beyond the thousand pound 25 threshold. Yeah, so we can't ensure even with AOGCC 11/19/2024 ITMO: CONOCOPHILLIPS ALASKA'S APPLICATION Docktet No. CO-24-012 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 Page 37 1 monitoring that there wouldn't be out of zone. 2 COMMISSIONER CHMIELOWSKI: So you're saying 3 that Conoco would have its different internal 4 monitoring pressure that was not a thousand pounds, it 5 would be somewhat lower to identify a potential out of 6 zone injection? 7 MR. WARD: One second. Thank you. 8 (Pause) 9 MR. WARD: Thank you. We'd like to leave the 10 record open and come back to you guys with a more 11 defined proposal. 12 COMMISSIONER CHMIELOWSKI: That sounds great. 13 Thank you. I think at the very end of the hearing 14 we'll decide how much time is appropriate, but to 15 follow-up on a previous question about the data, you 16 know, Conoco is asking for this larger pool area and 17 since fracking seems to be an integral part of the 18 project we would request something similar to what's on 19 slide 16, you know, identifying the cement for a half 20 mile radius for your proposed pool. That would be 21 great. So and we can again decide how much time that 22 would take at the end of the hearing. 23 That's what I have for now. Commissioner 24 Wilson, do you care to proceed with public comments. 25 COMMISSIONER WILSON: I am. AOGCC 11/19/2024 ITMO: CONOCOPHILLIPS ALASKA'S APPLICATION Docktet No. CO-24-012 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 Page 38 1 COMMISSIONER CHMIELOWSKI: Great. So now I 2 would like to offer to any member of the public the 3 opportunity to testify and provide comments before we 4 begin the confidential presentation. No written 5 comments were received on this matter. According to 6 the sign in sheet I don't see anybody in the room who 7 wishes to testify, but I'll just take a quick scan. If 8 anybody has changed their mind please raise your hand. 9 (No comments) 10 COMMISSIONER CHMIELOWSKI: Okay. Great. So 11 same -- is there anyone on Teams who has indicated the 12 needed to testify or..... 13 MS. COLDIRON: No. 14 COMMISSIONER CHMIELOWSKI: No one on Teams at 15 all? 16 MS. COLDIRON: No. 17 COMMISSIONER CHMIELOWSKI: Okay. There's zero 18 people on Teams or just AOGCC Staff. Okay. Well, 19 we're going to do the full 60 seconds for comment 20 purposes. So if there's anyone on -- on the phone or 21 on Teams who wishes to comment the code to enmity is 22 star, six. If you have technical difficulties Samantha 23 Coldiron can be reached at 907-793-1223 or you can call 24 the AOGCC main number at 907-279-1433. And we will 25 pause for 60 seconds to allow people time to enmity. AOGCC 11/19/2024 ITMO: CONOCOPHILLIPS ALASKA'S APPLICATION Docktet No. CO-24-012 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 Page 39 1 Again the code to enmity is start, six. And we'll 2 start our clock. 3 (Pause) 4 COMMISSIONER CHMIELOWSKI: Okay. Time is up. 5 So we will go into the confidential section. And so we 6 will ask members of the public to leave the room. 7 AOGCC Staff..... 8 MS. RODRIGUEZ: Excuse me. 9 COMMISSIONER CHMIELOWSKI: Yeah. 10 MS. RODRIGUEZ: Before we go into the 11 confidential section I -- we have an additional figure 12 to share that is not included in this, but we would 13 like to discuss. 14 COMMISSIONER CHMIELOWSKI: Sure. Okay. And so 15 if you could provide this to Samantha we can make sure 16 it's in the docket..... 17 MS. RODRIGUEZ: Okay. 18 COMMISSIONER CHMIELOWSKI: .....that would be 19 great at the end of the hearing. 20 MS. RODRIGUEZ: Okay. 21 COMMISSIONER CHMIELOWSKI: Okay. So we're 22 looking at a slide titled CD 5 wells one-quarter mile 23 from Minke injectors. 24 MS. RODRIGUEZ: That is correct. 25 COMMISSIONER CHMIELOWSKI: Okay. AOGCC 11/19/2024 ITMO: CONOCOPHILLIPS ALASKA'S APPLICATION Docktet No. CO-24-012 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 Page 40 1 MS. RODRIGUEZ: My name is Erika Rodriguez. So 2 in -- this is a cross section that has gamma ray and 3 resistivity for the wells where we had petrophysical 4 logs, so logs that do petrophysics. We have a pay flag 5 in green and then the right most column is a flag, a 6 gray flag, which kind of shows the interval where there 7 is cement for all of these wells that are a quarter- 8 mile from the injectors. And I think I just wanted to 9 show for the left most well which is the CD 5-98 that 10 is a well where there was no cement. The presence for 11 -- now the -- the pay presence for that well is 12 uncertain. There is one thin sand at the top that 13 could be cemented or could be pay, we don't know. And 14 then all the other wells, the two middle wells, the CD 15 5-92 and CD 5-93, those are the ones that we said were 16 partially cemented, but as you can see on that figure 17 the main part of the sand is covered by cement, it's 18 only that shaley section below where pay is unlikely to 19 be present, that it was left uncemented. And then the 20 right most well which is the CD 5-314X, this well has a 21 heterolithic package at the time it was drilled. No 22 pay was identified there. And this is also a well 23 where pay could be uncertain. A large portion of this 24 interval is also below the 4,400 -- minus 4,400 TVD 25 subsea so it's possible that a large portion of this is AOGCC 11/19/2024 ITMO: CONOCOPHILLIPS ALASKA'S APPLICATION Docktet No. CO-24-012 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 Page 41 1 in the water column. Oh, one more thing. On the map 2 you can see the outline of the cross section in red and 3 then you have the three proposed wells with the one- 4 quarter mile radius around them and then each well has 5 a little gray flag that just shows where the cement in 6 the intermediate one section is. And then -- oh, the 7 locations of each -- the well cross section -- well 8 cross section type points is on the top of the Minke 9 reservoir. 10 COMMISSIONER CHMIELOWSKI: Thank you very much. 11 That's a great addition. 12 MS. RODRIGUEZ: You're welcome. 13 COMMISSIONER CHMIELOWSKI: Any questions on 14 that, Commissioner Wilson? 15 COMMISSIONER WILSON: None from me. 16 COMMISSIONER CHMIELOWSKI: Okay. Then if we're 17 ready to go to the confidential section we'll just ask 18 members of the public please to leave the room. AOGCC 19 Staff and anyone from Conoco, just make sure everyone 20 who's here is okay to be here and we'll -- if we could 21 close the door, if someone wouldn't mind closing the 22 door that would be great. 23 (Indiscernible response) 24 COMMISSIONER CHMIELOWSKI: Yes. So we're going 25 to go off record for one second so that we can start a AOGCC 11/19/2024 ITMO: CONOCOPHILLIPS ALASKA'S APPLICATION Docktet No. CO-24-012 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 Page 42 1 new Teams separately to record this next section. So 2 we're off record for a minute. 3 (Off record) 4 ** (CONFIDENTIAL PORTION) ** 5 (On record) 6 COMMISSIONER CHMIELOWSKI: Thank you. We're 7 back on the record. So we're at the end of the 8 presentation, thank you very much for your 9 presentation. Just want to summarize I think our data 10 requests for you and then ask you how much time you'd 11 like to keep the record open. So what I have is, you 12 know, a expanded list of the wells -- mechanical 13 condition of wells one-half mile within the -- from the 14 proposed pool. You are going to I guess get back to us 15 with some further criteria on OA pressure management; 16 is that correct and then Commissioner Wilson had a 17 request for a map that he made. 18 Is there anything else that I'm forgetting, 19 Commissioner Wilson? 20 COMMISSIONER WILSON: No, the map would just be 21 a pore foot -- a pore foot map of the Nanushuk 22 formation above the Minke within the area of the pool 23 request. 24 COMMISSIONER CHMIELOWSKI: So I'm just looking 25 at it. ConocoPhillips, is there anything else you AOGCC 11/19/2024 ITMO: CONOCOPHILLIPS ALASKA'S APPLICATION Docktet No. CO-24-012 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 Page 43 1 captured from AOGCC that I might have forgotten? 2 MR. CASTONGIA: This is Ethan Castongia. It 3 does not appear that there's anything else that we've 4 captured..... 5 COMMISSIONER CHMIELOWSKI: Okay. 6 MR. CASTONGIA: .....that you might have 7 forgotten. 8 COMMISSIONER CHMIELOWSKI: Great. So we're 9 totally flexible on how long you want to keep the 10 record open. So if you just let us know -- if you 11 could do so right now we -- we'll do it. So today's 12 the 19th, so like we could do the end of next week, the 13 29th, or really whenever you like. I'd just like to 14 say if for some reason whatever day you pick doesn't 15 work you could just let us know and we can I think 16 expand the length of time you need. 17 MR. CASTONGIA: Yes. Thank you for that. 18 Given that next week is Thanksgiving holiday we'll go 19 to the -- we request for the next Friday, December 6th. 20 COMMISSIONER CHMIELOWSKI: Okay. So we'll keep 21 the record open until close of business on Friday, 22 December 6th. Great. 23 Commissioner Wilson, anything else. 24 COMMISSIONER WILSON: No, I'm good. Thanks. 25 COMMISSIONER CHMIELOWSKI: All right. Hearing AOGCC 11/19/2024 ITMO: CONOCOPHILLIPS ALASKA'S APPLICATION Docktet No. CO-24-012 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 Page 44 1 no other business this hearing is now adjourned. 2 Thank you. 3 (Off record) 4 (END OF PROCEEDINGS) 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 AOGCC 11/19/2024 ITMO: CONOCOPHILLIPS ALASKA'S APPLICATION Docktet No. CO-24-012 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 Page 45 1 TRANSCRIBER'S CERTIFICATE 2 I, Salena A. Hile, hereby certify that the 3 foregoing pages numbered 02 through 45 are a true, 4 accurate, and complete transcript of proceedings in 5 Docket No.: CO-24-012; ERIO-24-001, transcribed under 6 my direction from a copy of an electronic sound 7 recording to the best of our knowledge and ability. 8 9 _________________ _______________________________ 10 DATE SALENA A. HILE, (Transcriber) 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 CD5 wells ¼ mile from Minke Injectors (CD5-697 & CD5-633) ConocoPhillips 1 Minke Top & Base ¼ mile buffer Intermediate cement Well cross section w/tie points on Minke TopCemented Minke payCemented Minke payCemented Minke payNo cementPay unlikelyno cement- pay presence uncertainno cement- pay presence uncertainNo cementPay unlikely 2 Notice of Public Hearing STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION RE: Docket Numbers: CO-24-012 and ERIO-24-001 By application dated September 25, 2024, ConocoPhillips Alaska, Inc. (CPAI), as the operator of the Colville River Unit (CRU), requests that the Alaska Oil and Gas Conservation Commission (AOGCC) approve Pool Rules to establish rules for the development of the Minke Oil Pool (MOP) in the CRU and an Enhanced Recovery Injection Order (ERIO) to allow for pilot enhanced oil recovery (EOR) injection activities in the MOP. The AOGCC prescribes Pool Rules that govern development of oil and gas pools when a modification of a statewide regulation is needed to facilitate development of the pool. Some common rules are modification of the permit to drill application process to streamline applications and modify the data collection requirements when additional data would not add to the understanding of the geology in the project area. Additionally, the AOGCC approves injection orders for several purposes, including EOR, storage, and disposal either on an individual well or area wide basis in Alaska. EOR injection orders establish rules for conducting operations that are intended to increase the amount of oil or gas that could be recovered from a pool by one or more of the following mechanisms, maintain reservoir energy, sweeping oil through the reservoir to a production well, or modifying the properties of the oil to make it more mobile. An ERIO is a type of EOR injection order for conducting pilot injection projects when an EOR process hasn’t been proven to be effective in a given pool and allow the operator to gather performance data that will allow for the EOR injection process to be optimized before implementing on a pool wide basis. This is consistent with the portion of the AOGCC’s mission that seeks to promote greater ultimate recovery. This notice does not contain all the information filed by CPAI. To obtain more information, contact the AOGCC’s Special Assistant, Samantha Coldiron, at (907) 793-1223 or Samantha.Coldiron@alaska.gov. A public hearing on the matter has been scheduled for November 19, 2024, at 10:00 a.m. The hearing, which may be changed to full virtual, if necessary, will be held in the AOGCC hearing room located at 333 West 7th Avenue, Anchorage, AK 99501. The audio call-in information is (907) 202-7104 Conference ID: 349 722 430#. Anyone who wishes to participate remotely using MS Teams video conference should contact Ms. Coldiron at least two business days before the scheduled public hearing to request an invitation for the MS Teams. In addition, written comments regarding this application may be submitted to the AOGCC, at 333 west 7th Avenue, Anchorage, AK 99501 or Samantha.Coldiron@alaska.gov. Comments must be received no later than the conclusion of the November 19, 2024, hearing. If, because of a disability, special accommodations may be needed to comment or attend the hearing, contact Samantha Coldiron, at (907) 793-1223, no later than November 12, 2024. Jessie L. Chmielowski Gregory C. Wilson Commissioner Commissioner Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2024.10.03 09:19:40 -08'00' Gregory Wilson Digitally signed by Gregory Wilson Date: 2024.10.07 14:49:23 -08'00' From:Coldiron, Samantha J (OGC) To:AOGCC_Public_Notices Subject:[AOGCC_Public_Notices] Public Hearing Notice, CO-24-012 and ERIO-24-001 (CPAI) Date:Tuesday, October 8, 2024 8:38:16 AM Attachments:CO-24-012 and ERIO-24-001 public hearing notice establishing pool rules and an ERIO for the MOP in CRU.pdf 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 Lisi Misa being first duly sworn on oath deposes and says that she is a representative of the An- chorage Daily News, a daily newspaper. That said newspaper has been approved by the Third Judicial Court, Anchorage, Alaska, and it now and has been published in the English language continually as a daily newspaper in Anchorage, Alaska, and it is now and during all said time was printed in an office maintained at the afore- said 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 AFFIDAVIT OF PUBLICATION ______________________________________ Notary Public in and for The State of Alaska. Third Division Anchorage, Alaska MY COMMISSION EXPIRES ______________________________________ 10/09/2024 and that such newspaper was regularly distrib- uted 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 Account #: 100869 ST OF AK/AK OIL AND GAS CONSERVATION COMMISSION333 W. 7TH AVE STE 100, ANCHORAGE, AK 99501 Order #: W0048593 Cost: $362.2 Notice of Public HearingSTATE OF ALASKAALASKA OIL AND GAS CONSERVATION COMMISSION RE: Docket Numbers: CO-24-012 and ERIO-24-001 By application dated September 25, 2024, ConocoPhillips Alaska, Inc. (CPAI), as the operator of the Colville River Unit (CRU), requests that the Alaska Oil and Gas Conservation Commission (AOGCC) approve Pool Rules to establish rules for the development of the Minke Oil Pool (MOP) in the CRU and an Enhanced Recovery Injection Order (ERIO) to allow for pilot enhanced oil recovery (EOR) injection activities in the MOP. The AOGCC prescribes Pool Rules that govern development of oil and gas pools when a modification of a statewide regulation is needed to facilitate development of the pool. Some common rules are modification of the permit to drill application process to streamline applications and modify the data collection requirements when additional data would not add to the understanding of the geology in the project area. Additionally, the AOGCC approves injection orders for several purposes, including EOR, storage, and disposal either on an individual well or area wide basis in Alaska. EOR injection orders establish rules for conducting operations that are intended to increase the amount of oil or gas that could be recovered from a pool by one or more of the following mechanisms, maintain reservoir energy, sweeping oil through the reservoir to a production well, or modifying the properties of the oil to make it more mobile. An ERIO is a type of EOR injection order for conducting pilot injection projects when an EOR process hasn’t been proven to be effective in a given pool and allow the operator to gather performance data that will allow for the EOR injection process to be optimized before implementing on a pool wide basis. This is consistent with the portion of the AOGCC’s mission that seeks to promote greater ultimate recovery. This notice does not contain all the information filed by CPAI. To obtain more information, contact the AOGCC’s Special Assistant, Samantha Coldiron, at (907) 793-1223 or Samantha.Coldiron@ alaska.gov. A public hearing on the matter has been scheduled for November 19, 2024, at 10:00 a.m. The hearing, which may be changed to full virtual, if necessary, will be held in the AOGCC hearing room located at 333 West 7th Avenue, Anchorage, AK 99501. The audio call-in information is (907) 202-7104 Conference ID: 349 722 430#. Anyone who wishes to participate remotely using MS Teams video conference should contact Ms. Coldiron at least two business days before the scheduled public hearing to request an invitation for the MS Teams. In addition, written comments regarding this application may be submitted to the AOGCC, at 333 west 7th Avenue, Anchorage, AK 99501 or Samantha.Coldiron@alaska.gov. Comments must be received no later than the conclusion of the November 19, 2024, hearing. If, because of a disability, special accommodations may be needed to comment or attend the hearing, contact Samantha Coldiron, at (907) 793-1223, no later than November 12, 2024. Jessie L. Chmielowski Gregory C. Wilson Commissioner Commissioner Pub: Oct. 9, 2024 STATE OF ALASKA THIRD JUDICIAL DISTRICT ______________________________________2024-10-10 2028-07-14 Document Ref: KJEJ8-YOMK4-YLN5L-RVHYP Page 7 of 22 1 Michael Driscoll Michael Driscoll Development Supervisor ConocoPhillips Company 700 G Street Anchorage, AK 99501 OƯice: 907-265-6383 Fax: 907-263-4966 michael.d.driscoll@conocophillips.com September 25, 2024 Jessie Chmielowski Commissioner, Alaska Oil and Gas Conservation Commission 333 W. 7th Ave Anchorage, Alaska 99501-3539 RE: Application for Minke Oil Pool and PilotInjection, North Slope, Alaska Dear Commissioner Chmielowski, ConocoPhillips Alaska, Inc. as operator of the Colville River Unit, submits to the Alaska Oil and Gas Conservation Commission the attached applications requesting formation of the Minke Oil Pool andforapproval of Pilot Injection into the Minke Oil Pool. Please ﬁnd digital copies of the applications attached to this email. Please contact Ethan Castongia (907-263-4358,ethan.e.castongia@conocophillips.com) if you have any questions or require additional information. Regards, By Samantha Coldiron at 8:04 am, Sep 26, 2024 Application to the Alaska Oil and Gas Conservation Commission (AOGCC) for Formation of the Minke Oil Pool Colville River Unit September 25,2024 Application to the AOGCC for Formation of the Minke Oil Pool 2 Contents Section A Introduction .................................................................................................................................. 4 Document Scope ....................................................................................................................................... 4 Project Background ................................................................................................................................... 6 Section B Geology ......................................................................................................................................... 6 Pool Description ........................................................................................................................................ 6 Upper Confining Interval ....................................................................................................................... 6 Proposed Pool ....................................................................................................................................... 7 Lower Confining Interval of the Proposed Minke Oil Pool ................................................................... 7 Minke Trap and Structure ......................................................................................................................... 8 Minke Deposition, Stratigraphy and Reservoir Quality ............................................................................ 9 Section C Reservoir ..................................................................................................................................... 11 Reservoir Properties ............................................................................................................................... 11 Reservoir Fluids and Pressure, Volume and Temperature (PVT) Properties .......................................... 11 Original Oil in Place (OOIP) ..................................................................................................................... 11 Section D Reservoir Development .............................................................................................................. 11 Current Development Approach ............................................................................................................. 11 Hydrocarbon Recovery ........................................................................................................................... 12 Recovery Process Selection..................................................................................................................... 12 Future Optimization ................................................................................................................................ 12 Producing Gas Oil Ratio (GOR) Expectations .......................................................................................... 13 Well Conversion Strategy ........................................................................................................................ 13 Section E Drilling ......................................................................................................................................... 13 Drilling/Well Design ................................................................................................................................ 13 Drilling Fluids ........................................................................................................................................... 17 Annular Disposal ..................................................................................................................................... 17 Blowout Prevention ................................................................................................................................ 17 Directional Drilling .................................................................................................................................. 17 Well Spacing ............................................................................................................................................ 17 Logging Operations ................................................................................................................................. 17 Section F Well Operations .......................................................................................................................... 18 Well Design and Completions ................................................................................................................. 18 Artificial Lift ............................................................................................................................................. 18 Application to the AOGCC for Formation of the Minke Oil Pool 3 Sidetracks ................................................................................................................................................ 18 Reservoir Surveillance ............................................................................................................................. 18 Well Work Operations ............................................................................................................................ 19 Stimulation Methods .............................................................................................................................. 19 Surface Safety Valves .............................................................................................................................. 19 Section G Facilities ...................................................................................................................................... 20 Introduction and Scope ........................................................................................................................... 20 Production Equipment ............................................................................................................................ 20 Production Allocation ............................................................................................................................. 20 Section H Proposed Minke Oil Pool Rules .................................................................................................. 21 Rule 1: Field and Pool Name .................................................................................................................. 21 Rule 2: Pool Definition ........................................................................................................................... 21 Rule 3: Well Spacing ............................................................................................................................... 21 Rule 4: Drilling and Completion Practices .............................................................................................. 22 Rule 5: Automatic Shut-in Equipment ................................................................................................... 22 Rule 6: Reservoir Surveillance ................................................................................................................ 22 Rule 7: Gas Oil Ratio Exemption ............................................................................................................. 22 Rule 8: Annual Reservoir Review ............................................................................................................ 23 Rule 9: Annular Pressures ....................................................................................................................... 23 Rule 10: Production Surface Commingling, Measurement, and Allocation .......................................... 24 Rule 11: Administrative Action .............................................................................................................. 24 Application to the AOGCC for Formation of the Minke Oil Pool 4 SSection A Introduction Document Scope This application for formation of the Minke Oil Pool is submitted for approval by the Alaska Oil and Gas Conservation Commission (AOGCC) to define the proposed Minke Oil Pool and establish Pool Rules for the oil pool pursuant to 20 AAC 25.520. ConocoPhillips Alaska, Inc. (CPAI), submits this application to the AOGCC in its capacity as Operator of the Colville River Unit (CRU). The scope of this application includes a discussion of geological and reservoir properties of the proposed Minke Oil Pool as they are currently understood, and CPAI’s plans for reservoir development, reservoir surveillance, and well construction. CPAI requests the AOGCC establish pool rules for the Minke Oil Pool that will provide for economic development of the Minke oil resources, promote greater ultimate recovery from the proposed oil pool, and prevent waste within the Minke Oil Pool. This application includes information identified as confidential data and interpretations concerning the Minke Reservoir. CPAI requests that the information marked as confidential be maintained confidential by the AOGCC in accordance with the provisions of AS 31.05.035 and 20 AAC 25.537. The proposed area for the Minke Oil Pool is shown in Figure 1. The entire area of the proposed Minke Oil Pool is within the western portion of the CRU and is an area notionally developable from Colville Delta 5 (CD5) pad. CPAI proposes that the Minke Oil Pool be defined as the accumulation of hydrocarbons common to and correlating with the interval between the measured depths of 5,222 and 6,433’ MD (-4,333’ and -5,194‘ TVDSS, respectively) in the CD5-22 well (Figure 2). CPAI also proposes that the base of the Minke Oil Pool be defined by the top of the Torok Formation (6,433’ MD) and the top of the Minke Oil Pool be defined by the top of the Minke Formation (5,222’ MD) (Figure 2 and Figure 3). Application to the AOGCC for Formation of the Minke Oil Pool 5 Figure 1: Location Map Application to the AOGCC for Formation of the Minke Oil Pool 6 Project Background The Minke reservoir has numerous historical penetrations from wells drilled to deeper targets dating back to the late-1990s, with most wells drilled from the early 2000s to late 2010s. The Minke interval was historically overlooked due to its subtle petrophysical response (driven by thin-bed suppression) along with variable fluid signatures. The interval was first flow tested by CPAI in the CD5-32X well in 2024. The CD5-32X well allowed for long-term production testing, long-term pressure build-ups, fracture height data, and overburden strength calibration. Positive results from the CD5-32X led to the planning and proposed future drilling of the first horizontal producer/injector well pair (CD5-629/CD5-697) in 2024-25. The plan for these two wells is to successfully demonstrate production from, and injection into, the Minke reservoir. In addition, CPAI also plans to confirm pressure communication at 1,250’ well spacing between the horizontal producer and horizontal injector. Numerous on-pad development wells, and off-ice vertical exploration wells drilled to deeper intervals have provided other data for static characterization of the Minke reservoir. CPAI has also acquired and analyzed 3D seismic, including merged and reprocessed depth migrated data. CPAI plans to develop the Minke Oil Pool from the existing CD5 drill site. On the surface, Minke Oil Pool production will be commingled with other CRU production as it is routed to the Alpine Central Processing Facility (ACF). All Minke production will be measured as described in Section G of this application. Subject to AOGCC approval of the facilities and measurement program, no separate approval for commingling is necessary under 20 AAC 25.215, as CPAI intends to determine the quantity of Minke production by monthly well tests in the same manner that CPAI determines the quantity of production from other commingled CRU PAs. SSection B Geology Pool Description CPAI proposes that the Minke Oil Pool be defined as the accumulation of hydrocarbons common to and correlating with the interval between the measured depths of 5,222 and 6,433’ MD (-4,333’ and -5,194‘ TVDSS, respectively) in the CD5-22 well (Figure 2). The Minke reservoir is part of the Brookian Nanushuk formation. The Nanushuk was deposited in a shallow marine to upper slope setting in the Colville foreland basin. The Colville basin was created by loading from the south from the emerging Brooks Range and pinning to the north by the antecedent Jurassic rift shoulder (‘Barrow Arch’, or ‘North Slope Anticlinorium’). The basin was dominantly filled axially from west to east, with sediments originating from an uplift region in the Chukotka area of what is now eastern Russia. The sedimentary fill sequence is broadly divided into two time-transgressive formations that are delineated by their gross environments of deposition. The ‘topset’ Nanushuk Formation forms a series of eastward prograding deltaic - shoreface - uppermost slope sediments. The equivalent middle - lower slope - basin floor sediments are grouped into the Torok formation. The Minke reservoir is located at the eastern section of this progradational system and on the western edge of CRU, deposited prior to other CRU Nanushuk sands such as Narwhal on the eastern edge of CRU. Upper Confining Interval The upper confining interval of the Minke Oil Pool is represented by flooding shale within the Nanushuk Formation. This interval is present in thicknesses of 50’ to more than 200’ TVD across the area. Application to the AOGCC for Formation of the Minke Oil Pool 7 Proposed Pool CPAI proposes that the Minke Oil Pool be defined as the accumulation of hydrocarbons common to and correlating with the interval between the measured depths of 5,222 and 6,433’ MD (-4,333’ and -5,194‘ TVDSS, respectively) in the CD5-22 well (Figure 2). A detailed description is provided under the Stratigraphy and Sedimentology section of this application. Lower Confining Interval of the Proposed Minke Oil Pool The lower confining interval of the proposed pool was deposited in a slope setting of the Cretaceous Torok Formation, it comprises of mud dominated heterolithic sequences, which are present in thicknesses greater than 300’ TVD across the area. This formation forms the lower confining interval of the Colville River Unit Qannik Oil Pool, as approved by the AOGCC in Conservation Order No. 605, as amended, as shown in Figure 2 below. Application to the AOGCC for Formation of the Minke Oil Pool 8 Figure 2: Type log, CD5-22, UWI: 501032087100 Minke Trap and Structure The Minke reservoir is contained in a combination structural-stratigraphic trap. An up-dip pinch-out constrains the interpreted western and southern edge of the reservoir and shales out and dips below an interpreted hydrocarbon water contact (~-4,400’ TVDSS) to the east and north. The top Minke structure is very low relief within the development area, with structural dips averaging ~1-2 degrees (Figure 3). The exception to this is where the interval plunges basin-ward at the ultimate Minkeshelf-margin.Very limited faulting is present at the Minke reservoir level, as seen on the structure map in Figure 3. Application to the AOGCC for Formation of the Minke Oil Pool 9 Minke Deposition, Stratigraphy and Reservoir Quality The gross Minke trend is a generally west to east progradational system that is elongated in a northeast to southwest direction (3). The trend has similar width in the stratigraphic dip direction (west to east) along the entire length in the stratigraphic strike direction (south to north). The gross environment of deposition for the Minke interval is delta-front to distal delta-front. The best reservoir quality within the gross Minke package is located at the top. There are general trends of decreasing net to gross and grain size with depth that cause a degradation in reservoir quality. The reservoir is thinly bedded throughout. When combined with the presumed oil-water-contact and measured/modeled fracture geometry, the primary target interval of the gross Minke package is the upper ~100’ of the interval. Depositional dip and depositional strike well log cross-sections are included in Figures 4 and 5 for reference. Figure 3: Top Minke depth structure map Application to the AOGCC for Formation of the Minke Oil Pool 10 Figure 4: Depositional dip well log cross-section (structural datum) Figure 5: Depositional strike well log cross-section (structural datum) Application to the AOGCC for Formation of the Minke Oil Pool 11 SSection C Reservoir Reservoir Properties The Minke Reservoir consists of Lower Cretaceous Nanushuk deltaic deposits comprised of thinly laminated, very fine-grained sandstones, siltstones, and mudstones as described in the one whole core that has been acquired in the Minke reservoir (CD5-32X). Confidential net-reservoir interpretations supporting this application are provided in Appendix 1. Reservoir Fluids and Pressure, Volume and Temperature (PVT) Properties Reservoir fluid PVT and oil characterization studies have been completed on fluids gathered from the CD5- 32Xwell. Minke Reservoir and fluid properties are (-4,320TVDSS datum): - Initial Reservoir pressure: 1990 psig - Reservoir temperature: 106 degF - GOR: 424 scf/bbl - API gravity: 34.8 deg API - Bubble point pressure: 1734 psig - Oil formation volume factor: 1.2 rb/stbo - Oil viscosity: 2.17 cp - Gas formation volume factor: 1.5 bbl/mscf (at saturation pressure) Original Oil in Place (OOIP) The stock tank OOIP volumetric estimates for the proposed Minke Oil Pool range from 80 to 150MMSTB for the area encompassing conceptual development currently planned from the CD5 drillsite (Figure1) . The volumetric estimates are based off the mapping of core calibrated log model results from wells within and beyond the proposed pool area, guided by 3D seismic interpretations. An oil net pay map for a medium OOIP scenario is shown in Figure 8 (Confidential, Appendix 1). Section D Reservoir Development Current Development Approach The Minke Oil Pool will be developed in a phased approach from existing CRU drill site CD5, which is currently connected to CRU Alpine Central Processing Facility (ACF). An estimated 9 horizontal multi- staged fracture stimulated producers and 8 horizontal multi-staged fracture stimulated injectors may be drilled to develop the Minke reservoir which will be refined after gathering long term production and injection data from the first horizontal producer and injector planned for Q4 2024 into Q1 2025. The base development plan will employ a horizontal well line drive pattern waterflood with the possibility of employing water alternating gas (WAG) to enhance recovery from the reservoir. Initially, due to the thinly bedded nature of the reservoir, all the wells (including injectors) will be hydraulically fracture stimulated to enhance productivity and improve vertical sweep. However, the possibility of injection above reservoir parting pressure may prove efficient vertical sweep without the need to fracture injectors. CPAI is seeking a temporary injection order to gather data to evaluate this possibility, and will provide the Application to the AOGCC for Formation of the Minke Oil Pool 12 AOGCC with a definitive development plan when it seeks an Area Injection Order for the Minke Oil Pool area. Wells will be oriented southeast to northwest generally aligned with the maximum principal stress direction to improve waterflood performance and will range in length from ~4,000’ to ~10,000’ within the reservoir. Wells will be arranged end to end to form alternating rows of injectors and producers in a line- drive flood pattern. Studies suggest a 1,000 - 1,500’ inter-well spacing is optimal assuming modest secondary response. CPAI will provide the AOGCC with a more definitive development plan when it seeks an Area Injection Order after data from the initial development wells is gathered and analyzed. Hydrocarbon Recovery Fluid quality requires adoption of a secondary recovery mechanism to obtain an economic production profile. Water injection has been the main improved recovery process for the CRU to date and is also planned for the proposed Minke Oil Pool. This waterflood technique has been widely used across the North Slope with consistent success. CPAI estimates that primary recovery will recover approximately 5-10% of the OOIP and that waterflood recovery will range from 15-25% incremental recovery of OOIP, yielding a total recovery after waterflood of 20-30%. Gas injection, whether miscible or immiscible, is being evaluated to estimate the incremental recovery in the Minke Oil Pool. Resource recovery for floods is heavily dependent on injection throughput, waterflood recovery efficiency, and gas injection recovery efficiency. Recovery Process Selection Due to the low expected primary depletion recoveries, waterflooding is the recovery method selected, with lean and miscible gas injection evaluated as potential future recovery improvements. The largest remaining uncertainty for the Minke development is the question of interconnectivity of the reservoir at the proposed development scale of 1,000-1,500’ well spacing. The highly interbedded nature of the proposed Minke Oil Pool could result in poor inter-well communication at that distance. A horizontal pattern developed around existing CD5-32X well will confirm pressure communication at an inter-well distance of 1,250’, and CPAI will provide additional information on the planned recovery process from the reservoir when CPAI applies for an area injection order after gathering and analyzing the data from the initial development wells. Future Optimization Optimizing field development will be an ongoing process requiring additional data, laboratory studies, and reservoir modeling. The effective length and skin of the model wells is being tuned based on well test data. PVT studies to determine miscibility and incremental recovery from CRU WAG injection are also underway. The results of the initial development wells may allow for further optimization. Currently, the team is evaluating alternative well orientation to along reservoir strike (vs initial maximum principal stress) as well as injecting above reservoir parting pressure (vs fracture stimulating injectors). Other optimization concepts not listed may arise from the data gathered from the initial development wells. CPAI will update the AOGCC on the planned development approach when it seeks an area injection order for the Minke Oil Pool area. Application to the AOGCC for Formation of the Minke Oil Pool 13 Producing Gas Oil Ratio (GOR) Expectations In the case that WAG injection is implemented, CPAI requests that the requirements described in 20 AAC 25.240 be waived for the proposed Minke Oil Pool. As a result, the GOR is expected to rise above solution GOR in some wells. The breakthrough of re-injected gas may also cause GORs of some producing wells to exceed limits set forth in 20 AAC 25.240. However, if undertaken, gas re-injection would be expected to enhance ultimate recovery. Well Conversion Strategy The Minke Oil Pool development will target a voidage replacement ratio of 1.0. The injector/producer ratio will be dictated by the voidage replacement performance and well spacing relative to the developable area. Dependent on facility constraints, pre-production of injection wells may occur. After the pre-production period, these wells will be converted to injection, unless service conversion is determined beneficial for ultimate recovery or necessary to meet the voidage replacement ratio target. SSection E Drilling Drilling/Well Design The Minke Oil Pool will be accessed from wells drilled from the CD5 gravel pad utilizing drilling procedures, well designs, and casing and cementing programs consistent with current practices in other North Slope fields. Figures 6 and 7 below illustrate generic Minke 2-string and 3-string well designs. Producers and injectors will both be completed with the same well design. Conductor casing will either be driven or drilled and cemented at least 75’ below the pad. Cement returns to surface will be verified by visual inspection. Surface holes will be drilled and set below the base of the C40 Formation. This casing setting depth provides sufficient depth for kick tolerance, yet shallow enough to initiate build sections for high departure wells. Within the planned development area, the base of permafrost is interpreted to be between -1100’ and -1,300’ TVDSS. Surface casing strings will be cemented in accordance with 20 AAC 25.030(d)(4). No hydrocarbon bearing intervals have been encountered to this depth in previous wells. The blowout prevention equipment (“BOPE”) will be installed and tested in accordance with 20 AAC 25.035 requirements. A Formation Integrity Test (“FIT”) will be performed in accordance with 20 AAC 25.030(f). In 3-string well designs, the intermediate hole will be drilled to a casing point within the upper Minke interval at approximately 85 degrees inclination. In 2-string wells, the crossover from 7-5/8” to 4- 1/2” casing will be at approximately the same depth. In both designs, cement will be brought to a minimum of 500’ MD/250’ TVD above the top of the Minke interval in accordance with 20 AAC 25.030(d)(5). The section between the proposed surface casing shoe and the top of the Minke Reservoir consists primarily of mudstones and siltstones with very few minor very fine grained sandstones. Based on current knowledge of reservoir characteristics, CPAI expects to develop the Minke Oil Pool using horizontal wells with cemented and uncemented production casing/liners with frac sleeves to facilitate staged hydraulic fracture stimulation treatments. Both injection and production wells will likely be completed with 4-1/2” tubing to potentially facilitate hydraulic stimulation. Cemented liners are included in the drilling plans on an “as-needed” basis. For example, wellbores that encounter significant shale or lost circulation intervals may receive slotted liners with external casing Application to the AOGCC for Formation of the Minke Oil Pool 14 packers (“ECP”). At some point in the future coil tubing workovers may place slotted or cemented liners within the proposed pool. In addition to horizontal wells with cemented solid liners including frac sleeves to facilitate staged hydraulic fracture stimulation treatments, CPAI proposes that the Minke Oil Pool Rules also authorize the following alternative completion methods: A. Open-hole liner or casing and perforated completions with the option of hydraulic fracture stimulation treatments. B. Slotted liners, wire-wrapped screen liners, or combinations thereof, landed inside of cased hole and which may then be gravel packed. C. Vertical or “conventional” open-hole completions. Open-hole completions may subsequently be completed with slotted or perforated liners, wire-wrapped screen liners, or combinations thereof, and may be gravel packed. D. Horizontal or “high angle” completions with liners, slotted or perforated liners, wire-wrapped screens, or combination thereof, landed inside the horizontal extension, and which may be cemented and perforated, or gravel packed. E. Multi-lateral type completions in which more than one wellbore penetration is completed in a single well, with production gathered and routed back to a central wellbore. Other casing and completion methods may be approved by the Commission by administrative approval upon request by CPAI supported by data demonstrating that such alternatives are based on sound engineering principles. Application to the AOGCC for Formation of the Minke Oil Pool 15 Figure 6: Proposed 2-String Minke Well Schematic Application to the AOGCC for Formation of the Minke Oil Pool 16 Figure 7: Proposed 3-String Minke Well Schematic Application to the AOGCC for Formation of the Minke Oil Pool 17 Drilling Fluids The drilling fluid program designed for wells within the Minke Oil Pool will be prepared and implemented in accordance with 20 AAC 25.033. Formation pressures for the strata to be penetrated will be estimated and documented based on the current wells targeting the Minke Reservoir as well as from the WNS wells which have already penetrated the proposed Minke Oil Pool. Annular Disposal In the event annular disposal of drilling wastes is deemed necessary, disposal will be proposed in accordance with 20 AAC 25.080 in annuli of wells with surface casing set below the permafrost. Based on the extensive development in the Colville River Unit area over the last thirty plus years, no freshwater sands have been encountered and there are no freshwater aquifers present in the Colville River Unit. Historical AOGCC findings state that there are no freshwater aquifers present in the CRU. Those prior findings and conclusions remain valid. CPAI requests a finding that no freshwater aquifers are present in the Minke Oil Pool area. Blowout Prevention General well control for drilling and completion operations will be performed in accordance with 20 AAC 25.035. Directional Drilling CPAI requests that the requirements described in 20 AAC 25.050(b) be waived for the proposed Minke Oil Pool to relieve administrative burden. In lieu of the requirements under 20 AAC 25.050(b), CPAI proposes that permit(s) to drill shall include: 1) Plan view 2) Vertical section 3) Close approach data 4) Directional data Well Spacing CPAI requests that the requirements described in 20 AAC 25.055 be waived for the proposed Minke Oil Pool because the horizontal well development of the proposed Minke Oil Pool, via line-drive flood pattern, will yield greater recovery than a conventional vertical/slant well development plan with a minimum spacing rule. In lieu of the requirements under 20 AAC 25.055, CPAI proposes that the only spacing limitation be that without prior approval, development wells may not be completed any closer than 500’ to an external boundary where the owners and landowners are not the same on both sides of the line. Logging Operations The basic log suite planned in the Minke Reservoir includes gamma ray (GR) and resistivity logs for the purpose of facies interpretation. If log identification of formation facies is not possible, rate of penetration (ROP) and cuttings will become the reservoir quality determinants. At some point in the future, it is possible that Minke wells could be drilled using GR as well as other drilling indicators to locate the pay zones. Application to the AOGCC for Formation of the Minke Oil Pool 18 CPAI requests that the requirements described in 20 AAC 25.071(a) be waived for the proposed Minke Oil Pool since these requirements will not significantly add to the geologic knowledge of the area considering the information that is available from the numerous well penetrations in the area. In lieu of the requirements under 20 AAC 25.071(a), CPAI proposes that only one well per drill site is required to be logged for the portion of the well below the conductor pipe by either a complete electrical log or a complete radio-activity log unless the Commission specifies which type of log is to be run. As the first Minke reservoir targeted well on drill site CD5 (CD5-32X) was successfully investigated with a suite of gamma ray/resistivity/neutron/density/sonic logs, additional log investigation of formations from the CD5 drill site of the proposed Minke Oil Pool would be performed at CPAI’s discretion. SSection F Well Operations Well Design and Completions Both injectors and producers are planned to be completed with 4-1/2” tubing and production liner to facilitate hydraulic stimulation and to exploit the production potential of horizontal wells. All wells will be equipped with at least one gas lift mandrel and a production packer to anchor the tubing in place during stimulation and to provide isolation for the tubing-casing annulus. The 4-½” liners will generally be set with a combination of a liner hanger and/or packer system. Frac sleeves will be integral to the production liner portion of the production string, although alternative completion methods are included as additional potential options above. (Tubular size and other well design elements are, of course, planned and subject to change.) For injection wells, a landing nipple below the base of permafrost will be used to install a check-style SSSV. Artificial Lift The current development plan utilizes gas lift as the artificial lift mechanism to produce from the Minke Oil Pool. If favorable for recovery in the future, CPAI may employ alternative lift techniques (jet pump, electrical submersible pumps, etc.) to optimize reservoir pressure drawdown, provide lift for long reach horizontal wells, and enhance production rates at increased water cuts, which are anticipated following waterflood response. Sidetracks In the event early waterflood breakthrough is encountered due to high permeability intervals, the initial completions may be plugged back and sidetracked to improve sweep and enhance recovery. Sidetracks may also become necessary if the parent wellbore does not produce/inject as expected or no longer supplies required integrity. In addition to pattern conformance, sidetracks could increase water injection, sidestep faulting or penetrate bypassed oil. Sidetracking scenarios can be expected to target maturing reservoir sections for increased injectivity, reach undrained or isolated pockets, and improve enhanced recovery techniques. As such, sidetracks can be expected to radiate out laterally from the parent wellbore. This further supports the request for a waiver of regulation 20 AAC 25.055. Reservoir Surveillance The initial reservoir pressure of the Minke Oil Pool, as required by 20 AAC 25.270(a), was measured in the CD5-32X well. Application to the AOGCC for Formation of the Minke Oil Pool 19 CPAI requests that the Commission approves the proposed reservoir pressure monitoring plan: x Static bottom-hole pressure surveys will be conducted in all new wells prior to initiating injection. x Static surveys will be performed on production wells at the discretion of CPAI. x For annual pressure surveillance, a minimum of one (1) pressure survey will be conducted annually in the Minke Oil Pool. x Since lengthy horizontal wells require extended shut-in periods, often months long, to achieve stabilized bottom-hole pressures, the alternative pressure survey methods below can be implemented: o open-hole wireline formation fluid pressure measurements, o cased hole pressure buildups with bottom-hole pressure measurement, o injector surface pressure fall-off, o readings from permanent downhole pressure/temperature gauges o static pressure surveys following extended shut-in periods, or o bottom-hole pressures calculated from wellhead pressure and fluid levels in the tubing of a stabilized shut-in injection well. x All pressure surveys will be reported annually, rather than monthly, to reduce paperwork due to the limited number of surveys. While the top of the pool extends between approximately -4,150’ TVDSS and -4,950’ TVDSS, a representative common datum for reporting should be -4,320’ TVDSS. The -4,320’ TVDSS datum will be representative of the targeted depth since the estimated oil/water contact depth is approximately -4,400’ TVDSS. Well Work Operations Well work operations in the Minke Oil Pool will include routine mechanical integrity tests of each wellbore and artificial lift maintenance. Operations will also include remedial management of scale, paraffin, etc. with slickline or hot diesel treatments. Unlike more typical multi-zone or multi-layer fields on the North Slope, the Minke Oil Pool represents a single hydrocarbon accumulation based on current data. Production from a single pool minimizes profile modifications. For ongoing well work CPAI requests that the Minke Oil Pool be included in the existing CRU sundry matrix, CO 735.001. This is intended to reduce the paperwork burden on both the Commission and CPAI. Summary reports and records will continue to be kept in accordance with 20 AAC 25.280(c) and (d). Stimulation Methods Stimulation techniques will be used to enhance productivity of the Minke Oil Pool. Stimulation to remove drilling induced formation damage and enhance near wellbore flow characteristics may be performed to increase the commercial flow rates in this reservoir. Additional hydraulic fracture stimulation (in addition to initial hydraulic fracturing during completion) may also be performed to increase the commercial flow rates of the Minke Reservoir. Wellbore trajectories, cementing programs, and tubulars will be designed to accommodate hydraulic fracture stimulation techniques. Hydraulic stimulation operations will also be performed in accordance with 20 AAC 25.283. Surface Safety Valves Wells will be equipped with appropriate well safety valve systems in accordance with 20 AAC 25.265. Application to the AOGCC for Formation of the Minke Oil Pool 20 Periodic inspections and testing, at least semi-annually, will be conducted following notification of the Commission. SSection G Facilities Introduction and Scope The Minke Oil Pool will be developed from the existing CRU drill site CD5, which is connected to CRU ACF. The CD5 onshore gravel drill site was selected for the initial development due to the ability to target the Minke Oil Pool from existing facility infrastructure. The CD5 drill site delivers fluids to ACF (~7 miles away), where processing for sales occurs. To accommodate the full production potential of the Minke Oil Pool while continuing production from existing CD5 pools, upgrades to the current infrastructure are expected. One of the earliest upgrades is likely to include a header expansion for additional surface well locations and an additional Remote Electrical and Instrumentation Module (REIM) to accommodate the additional surface slots. Injection water will consist of seawater, with the future potential of injecting produced water. Injection gas will be sourced from CRU processing facilities. Although the future availability of gas for injection purposes cannot be predicted, some form of IWAG/MWAG may occur in one or more injection patterns. The Minke trend extends outside the proposed Minke Oil Pool to both the southwest and the northeast. The proposed Minke Oil Pool is an area notionally developable from CD5. Future Minke Oil Pool expansion options are being evaluated. Production Equipment Minke Oil Pool wells will be produced to existing CRU drill site CD5. Minke production will be commingled with other CD5 production through a common cross country line to ACF. ACF receives production from CPAI operated drill sites and provides separation into oil, gas, and water. Oil is sold. Gas is dehydrated and compressed for artificial lift, reinjection gas, and fuel gas to support the facility. Produced water is used for reinjection at CRU and GMTU. Production Allocation Production will be measured with equipment in accordance with 20 AAC 25.228. Each well at CD5 is connected to the CD5 test separator. The CD5 test separator will provide direct well measurement for Minke wells at CD5. Production will be allocated based on well test data, which is used to create performance curves for each well. The summation of these curves on a fieldwide basis creates a theoretical production for the field. This is compared to sales total to calculate the CRU allocation factor. The CRU allocation factor is applied to each individual well’s theoretical production to allocate oil to the individual well A separate participating area is planned for the Minke Oil Pool. The Minke project area is also subject to the CRU Agreement. The Arctic Slope Reginal Corporation (“ASRC”), and the Bureau of Land Management (“BLM”) are the royalty owners. The control system for the Minke Oil Pool wells will continuously gather operating data from the wells and the test separators. To accurately allocate the production the following actions will be followed: x All wells will be tested twice a month consistent with CRU practices. Application to the AOGCC for Formation of the Minke Oil Pool 21 x The stabilization and test duration of each test will be optimized by CPAI to obtain a representative test. x Well and field operating condition information required for the construction of a field production history will be maintained. x Major test separator meters and major gas system meters will be installed and maintained according to industry recommended practices or standards. x CPAI will maintain records that permit verification of the satisfactory execution of the approved production allocation methodologies. SSection H Proposed Minke Oil Pool Rules The rules set forth apply to the following area referred to in this order: Township, Range Sections T11N, R03E Section 1: S/2 Section 11: E/2 NE/4, E/2 SE/4 Sections 12-13: All Section 14: E/2 NE/4 Section 24: E/2 NW/4, NE/4, N/2 SE/4, SE/4 SE/4 T11N, R04E Section 6: SW/4 SW/4 Section 7: W/2, W/2 SE/4 Sections 18: All Sections 19: W/2, N/2 NE/4, SW/4 NE/4, NW/4 SE/4 Rule 1: Field and Pool Name The field is the Colville River Field, and the pool is the Minke Oil Pool. Rule 2: Pool Definition The Minke Oil Pool is defined as the accumulation of oil and gas common to and correlating with the interval within the CD5-22 well between the depths of 5,222 feet and 6,433 feet MD (-4,333 feet and - 5,194 feet TVDSS, respectively). Rule 3: Well Spacing There shall be no restrictions as to well spacing except that no pay shall be opened to a well within 500’ of an external property line where the owners and landowners are not the same on both sides of the line. Application to the AOGCC for Formation of the Minke Oil Pool 22 Rule 4: Drilling and Completion Practices a) Alternate casing and completion programs, in addition to those specified in the regulations, may be administratively approved by the Commission upon application and presentation of data which demonstrate the alternatives are appropriate, based upon sound engineering principles. b) In lieu of the requirements under 20 AAC 25.050(b), CPAI proposes that permit(s) to drill shall include: plan view, vertical section, close approach data, and directional data. c) In lieu of the requirements under 20 AAC 25.071(a), CPAI proposes that only one well per drill site is required to be logged for the portion of the well below the conductor pipe by either a complete electrical log or a complete radio-activity log unless the commission specifies which type of log is to be run. This has already been satisfied for drill site CD5, the primary pad from which Minke development wells will be drilled. The AOGCC may, in its discretion, require additional wells on a pad to be logged using a complete petrophysical log suite. Rule 5: Automatic Shut-in Equipment Injection wells must be equipped with a. A double check valve arrangement or b. A single check valve and a surface safety valve (SSV). A subsurface-controlled injection valve, or “SCSSV” satisfies the requirements of a single check valve Rule 6: Reservoir Surveillance a) A bottom-hole pressure survey shall be conducted in each well prior to initial injection. b) The operator shall obtain the pressure surveys needed to manage properly the hydrocarbon recovery processes subject to the annual plan outlined in Rule 8 below. At a minimum, a pressure survey shall be acquired from at least one well in the Minke Oil Pool on each drill site each year c) The Reservoir Pressure Datum will be -4,320 feet TVDSS. d) Pressure surveys may consist of stabilized static pressure measurements at bottom-hole or be extrapolated from surface measurements (single phase fluid conditions), pressure fall-off measurements, pressure buildup measurements, multi-rate test results, drill stem test results, and open-hole formation tests or other methods approved by the AOGCC. e) A Reservoir Pressure Report, Form 10-412, shall be utilized for all surveys annually; all relevant data shall be attached to the report. The data submitted shall include, at a minimum, rate, pressure, depth, fluid gradient, temperature, and all other well conditions necessary for a complete analysis of each survey being conducted. f) The results and data from any special reservoir pressure monitoring tests or surveys shall also be submitted in accordance with paragraph (e) of this rule. Rule 7: Gas Oil Ratio Exemption Wells producing from the Minke Oil Pool are exempt from the gas-oil ratio (GOR) limit set forth in 20 AAC 25.240(a) so long as the provisions of 20 AAC 25.240(b) apply. Application to the AOGCC for Formation of the Minke Oil Pool 23 Rule 8: Annual Reservoir Review An annual reservoir surveillance report must be filed by April 1st of each year and include future Minke Oil Pool development plans, reservoir depletion plans, and surveillance information for the prior calendar year, including: a. The voidage balance, by month, of produced fluids and injected fluids. b. A summary and analysis of the reservoir pressure surveys within the pool. c. The results and, where appropriate, an analysis of production and injection log surveys, tracer surveys, observation well surveys, and any other special monitoring. d. A review of pool production allocation factors and issues over the prior year. e. A review of the progress of the enhanced recovery project. Rule 9: Annular Pressures a. At the time of installation or replacement, the operator shall conduct and document a pressure test of tubulars and completion equipment in each development well that is sufficient to demonstrate that planned well operations will not result in failure of well integrity, uncontrolled release of fluid or pressure, or threat to human safety. b. The operator shall monitor each development well daily to check for sustained pressure, except if prevented by extreme weather conditions, emergency situations, or unavoidable circumstances. Monitoring results shall be kept available for AOGCC inspections. c. The operator shall notify the AOGCC within three working days after the operator identifies a well as having (i) sustained inner annulus pressure that exceeds 2,000 psig or (ii) sustained outer annulus pressure that exceeds 1,000 psig. d. The operator shall submit in an Application for Sundry Approvals (Form 10-403) a proposal for corrective action or increased surveillance for any development well having sustained pressure that exceeds a limit set out in paragraph (c) of this rule. The AOGCC may approve the operator’s proposal or require other actions or surveillance, including a mechanical integrity test or other approved diagnostic tests. The operator shall give sufficient notice of the testing schedule to allow the AOGCC to witness the test. e. If the operator identifies sustained pressure in the inner annulus of a development well that exceeds 45 percent of the burst pressure rating of the well’s production casing for inner annulus pressure, or sustained pressure in the outer annulus that exceeds 45 percent of the burst pressure rating of the well’s surface casing for outer annulus pressure, the operator shall notify the AOGCC within three working days and take corrective action. Unless well conditions require the operator to take emergency corrective action before AOGCC approval can be obtained, the operator shall submit in an Application for Sundry Approvals (Form 10-403) a proposal for corrective action. The AOGCC may approve the operator’s proposal or require other corrective action, including a mechanical integrity test or other diagnostic tests. The operator shall give the AOGCC sufficient notice of the testing schedule to allow the AOGCC to witness the tests. f. Except as otherwise approved by the Commission under (d) or (e) of this rule, before a shut-in well is placed in service, any annulus pressure must be relieved to a sufficient degree: (1) that the inner annulus pressure at operating temperature will be below 2,000 psig, and (2) that the outer annulus pressure at operating temperature will be below 1,000 psig. A well subject to (c) but not (e) of this rule may reach an annulus pressure at operating temperature that is Application to the AOGCC for Formation of the Minke Oil Pool 24 described in the operator’s notification to the AOGCC under (c) of this rule, unless the AOGCC prescribes a different limit. g. For purposes of this rule, I. inner annulus means the space in a well between tubing and production casing; II. outer annulus means the space in a well between production casing and surface casing; and III. sustained pressure means pressure that (A) is measurable at the casing head of an annulus, (B) is not caused solely by temperature fluctuations, and (C) has not been applied intentionally. Rule 10: Production Surface Commingling, Measurement, and Allocation a. Production from the Minke Oil Pool, CRU pools, GMTU pools, and future ACF contributing pools may be commingled in surface facilities prior to custody transfer. b. Wells must be tested at least twice per month. Rule 11: Administrative Action Upon proper application or its own motion, unless notice and a public hearing are otherwise required the AOGCC may administratively waive the requirements of any rule stated above or administratively amend this order as long as the change does not promote waste, jeopardize correlative rights, or compromise ultimate recovery and is based on sound engineering principles. Application to the Alaska Oil and Gas Conservation Commission for Approval of Pilot Injection into the Minke Reservoir Colville River Unit 9/25/2024 Application to the AOGCC for Approval of Pilot Water Injection into the Minke Reservoir Colville River Unit Page 2 ConocoPhillips Alaska, Inc. Table of Contents Introduction.................................................................................................................................................... 3 20 AAC 25.402(c)(1) Plat of Wells Penetrating Injection Zone ..................................................................... 5 20 AAC 25.402(c)(2) Operators and Surface Owners within One Quarter Mile of Injection Operations ...... 6 20 AAC 25.402(c)(3) Affidavit of Regarding Notice to Surface Owners ....................................................... 7 20 AAC 25.402(c)(4) Description of the Proposed Operation ....................................................................... 8 20 AAC 25.402(c)(5) Description and Depth of Pool to be Affected ............................................................. 9 20 AAC 25.402(c)(6) Description of the Formation ..................................................................................... 10 20 AAC 25.402(c)(7) Logs of the injection wells ......................................................................................... 12 20 AAC 25.402(c)(8) Mechanical Integrity of Injection Wells ...................................................................... 13 20 AAC 25.402(c)(9) Injection Fluid Analysis and Injection Rates ............................................................. 15 20 AAC 25.402(c)(10) Estimated Average and Maximum Injection Pressures .......................................... 16 20 AAC 25.402(c)(11) Fracture Information ................................................................................................ 17 20 AAC 25.402(c)(12) Quality of Formation Water ..................................................................................... 18 20 AAC 25.402(c)(13) Aquifer Exemption Reference ................................................................................. 19 20 AAC 25.402(c)(14) Incremental Hydrocarbon Recovery ....................................................................... 20 20 AAC 25.402(c)(15) Mechanical Condition of Wells Within ¼ Mile of Proposed Area ............................ 21 List of Figures Figure 1: Proposed Minke Pilot Injection Project Well Locations.................................................................. 4 Figure 2: ¼ Mile Circle/Tangent with Proposed Injectors and Formation Penetrations................................ 5 Figure 3: CD5-22 Type Log........................................................................................................................... 9 Figure 4: Minke Top Structure Map ............................................................................................................ 11 Figure 5: Schematic of Proposed Injection Well ......................................................................................... 14 Figure 6: Fracture Gradient of Minke Upper Confining Layer ..................................................................... 17 Application to the AOGCC for Approval of Pilot Water Injection into the Minke Reservoir Colville River Unit Page 3 ConocoPhillips Alaska, Inc. Introduction This application to the Alaska Oil and Gas Conservation Commission (AOGCC) seeks authorization for water injection into the Minke reservoir through a proposed waterflood pattern pilot. This project involves injecting water into the Minke reservoir (the Minke reservoir is defined in the section covering 20 AAC 25.402(c)(5) Description and Depth of Pool to be Affected) in order to test the injectivity of water and subsequent production response. The feasibility of water injection into the Minke reservoir has not been established and is therefore considered a “pilot” project. This pilot project will aid in determining the commercial viability of developing Minke as an enhanced oil recovery project. The impacted area of the pilot project is depicted below in Figure 1. The requested duration of this order is 3 years. This will allow time to drill the first injector, test injection performance, analyze results of the first injector, drill the second injector, test injection performance, and observe and analyze the results. After gathering analyzing the data from the pilot project, CPAI expects to return to the AOGCC with an area injection order application informed by the pilot project. In January 2024, the CD5-32X exploration well was drilled to understand the ability to drill, complete, and produce the Minke horizon. The well was drilled as an exploration well within the Colville River Unit (CRU). Concurrent with this application, CPAI has applied to establish pool rules for the Minke reservoir (see Minke Oil Pool application submitted concurrently with this application). Drilling of the first offset injector is planned for December 2024, with injection commencing on or around January 2025. Drilling timing of the second injector is contingent on the results of the first. The final development design for the Minke reservoir is expected to be a line-drive water alternating gas (WAG) flood with horizontal producers and injectors drilled along the maximum principal stress. The pilot results will inform whether this development concept is optimal. If pilot results are favorable and further development is sanctioned, then ConocoPhillips will apply at that time to the AOGCC for an area injection order. Application to the AOGCC for Approval of Pilot Water Injection into the Minke Reservoir Colville River Unit Page 4 ConocoPhillips Alaska, Inc. Figure 1: Proposed Minke Pilot Injection Project Well Locations Application to the AOGCC for Approval of Pilot Water Injection into the Minke Reservoir Colville River Unit Page 5 ConocoPhillips Alaska, Inc. 20 AAC 25.402(c)(1) Plat of Wells Penetrating Injection Zone The attached map (Figure 2) shows the proposed Minke injection wells penetrating the injection zone. A ¼ mile radius around each injection lateral is displayed. Figure 2: ¼ Mile Circle/Tangent with Proposed Injectors and Formation Penetrations Application to the AOGCC for Approval of Pilot Water Injection into the Minke Reservoir Colville River Unit Page 6 ConocoPhillips Alaska, Inc. 20 AAC 25.402(c)(2) Operators and Surface Owners within One Quarter Mile of Injection Operations Operators: No operators other than CPAI within ¼ mile of injection. Surface Owners: Kuukpik Corporation Mr. Joe Nukapigak PO Box 187 Nuiqsut, Alaska 99789-0187 United States Department of Interior Bureau of Land Management Attn: Wayne M. Svejnoha, Branch Chief Energy & Minerals 222 West 7th Ave., Suite #13 Anchorage, Alaska 99513 Application to the AOGCC for Approval of Pilot Water Injection into the Minke Reservoir Colville River Unit Page 7 ConocoPhillips Alaska, Inc. 20 AAC 25.402(c)(3) Affidavit of Mateo J. Bahamonde Regarding Notice to Surface Owners Mateo J. Bahamonde, on oath, deposes and says: 1. I am a Senior Land Negotiator employed by ConocoPhillips Alaska, Inc., the Operator of the Colville River Unit, and I have responsibilities within the State of Alaska and personal knowledge of the matters set forth in this affidavit. 2. On ____________ ___, 2024, I caused copies of the Application for Approval of Pilot Injection in the Minke Reservoir within the Colville River Unit to be provided to the surface owners and operators of all land not operated by ConocoPhillips Alaska, Inc. within a quarter mile of the proposed injection wells as listed below: a. Kuukpik Corporation Attn: Mr. Joe Nukapigak PO Box 187 Nuiqsut, Alaska 99789-0187 b. United States Department of Interior Bureau of Land Management Attn: Wayne M. Svejnoha, Branch Chief Energy & Minerals 222 West 7th Ave., Suite #13 Anchorage, Alaska 99513 Dated this ___ day of ___________, 2024. Mateo J. Bahamonde STATE OF ALASKA ) ) ss. THIRD JUDICIAL DISTRICT ) SUBSCRIBED AND SWORN to before me this ___ day of _____________, 2024. NOTARY PUBLIC IN AND FOR ALASKA My Commission Expires: Application to the AOGCC for Approval of Pilot Water Injection into the Minke Reservoir Colville River Unit Page 8 ConocoPhillips Alaska, Inc. 20 AAC 25.402(c)(4) Description of the Proposed Operation This application to the Alaska Oil and Gas Conservation Commission (AOGCC) seeks authorization for a pilot injection project in the Minke Reservoir within the Colville River Unit (CRU). The Minke pilot injection project involves drilling two offset injectors and one producer. The first injector to be drilled will be named CD5-697 and be located 1,000 to 1,500 feet east of the to be drilled producer that will be named CD5-629. The optimum pattern spacing and which wells for WAG development in this reservoir is still under analysis. Completion of the CD5-697 injection well will allow interference and injection testing of the Minke reservoir to help establish the optimal pattern spacing and justify commerciality of the reservoir. Depending on the outcome of this first injection well and its testing, a second injection well CD5-633 may be drilled to continue a long-term injection and production test with a fully supported producer pattern centered around CD5-629. The requested duration of this order is 3 years. This will allow time to drill the first injector, test injection performance, analyze results of the first injector, drill the second injector, test injection performance, and observe and analyze the results. Application to the AOGCC for Approval of Pilot Water Injection into the Minke Reservoir Colville River Unit Page 9 ConocoPhillips Alaska, Inc. 20 AAC 25.402(c)(5) Description and Depth of Pool to be Affected The CD5-697 injection well is a pilot development well within the CRU. A Minke Oil Pool application is concurrently being submitted with this application. The Minke reservoir is defined by the CD5-22 well with Sub Sea True Vertical Depth (SSTVD) limits of -4,333 to -5,194 feet with a corresponding Measured Depth (MD) of 5,222 to 6,433 feet. Figure 3: CD5-22 Type Log Application to the AOGCC for Approval of Pilot Water Injection into the Minke Reservoir Colville River Unit Page 10 ConocoPhillips Alaska, Inc. 20 AAC 25.402(c)(6) Description of the Formation Stratigraphy and Sedimentology The Late Cretaceous Minke sandstone represents a north-south elongate, eastward prograding deltaic marine sand. The Nanushuk Group is broadly age equivalent to the Minke sands. The Minke sands in the CRU represent a Brookian topset play in which deltaic marine sands (over 500 ft gross) are trapped stratigraphically. Over the length of the field, Minke extends for approximately 29 miles parallel to depositional strike (north- south) and two miles in a depositional dip direction. Up-dip, to the west, these sands pinch-out due to either onlap or truncation beneath a ravinement surface. The Minke reservoir has been penetrated by approximately 41 wells in the CRU and an additional 3 wells in the vicinity of the CRU and Greater Mooses Tooth (GMT) Units. The range of core properties from the CD5-32X well in the net sand are 17-25% porosity, 1-114 millidarcies air permeability, and 15-58% water saturation. The sands are lower very fine to lower fine-grained lithic arenites with average compositions of 51% quartz, 18% feldspar, and 31% lithics. Sands with porosities of less than 15% are generally non- pay. Structure and Trap Configuration The top composite Minke structure elevation ranges from 3,800 SSTVD to 6,000 SSTVD as depicted below in Figure 4. Structural dips between wells generally range from 1 to 2 degrees. The Minke accumulation is a combined structural-stratigraphic trap. Well & seismic structure data suggests a hydrocarbon column greater than 300 feet. 3D seismic indicates that there are no large faults in the development area that displace the Minke clinothem at the reservoir level. Sub-seismic faults may exist. At the Brookian level, borehole breakout data shows a maximum principle stress orientation oriented at N30W similar to the existing reservoirs produced through the Alpine Central Facility. However, the lack of mappable faults suggests a potential decrease in overall stress compared to Alpine level. Seals Confining zones are shown in Figure 3 and are: Upper Confining Interval A Flooding shale of the Cretaceous Nanushuk Group overlies the top Minke reservoir. Total thickness varies from 50 ft to greater than 200 ft. Lower Confining Interval Mud dominated heterolithic sequences deposited in a slope setting of the Cretaceous Torok Group. Thickness in excess of 300 ft. Application to the AOGCC for Approval of Pilot Water Injection into the Minke Reservoir Colville River Unit Page 11 ConocoPhillips Alaska, Inc. Figure 4: Minke Top Structure Map Application to the AOGCC for Approval of Pilot Water Injection into the Minke Reservoir Colville River Unit Page 12 ConocoPhillips Alaska, Inc. 20 AAC 25.402(c)(7) Logs of the Injection Wells Upon drilling of the injection wells, logs will be sent to the Commission in accordance with applicable AOGCC regulations. Application to the AOGCC for Approval of Pilot Water Injection into the Minke Reservoir Colville River Unit Page 13 ConocoPhillips Alaska, Inc. 20 AAC 25.402(c)(8) Mechanical Integrity of Injection Wells See Figure 5 below for a proposed injection well schematic. The injection well design is similar to wells in the Colville River Unit (Alpine Field) but contain an additional casing string to manage borehole instability and facilitate use of managed pressure drilling (MPD) when drilling the highly deviated section of overburden between the surface shoe and the reservoir. MPD will be used to minimize borehole pressure cycling and provide sufficient overbalance to hold back the weak, mechanically unstable clay rich formations penetrated at >80 degrees. Surface casing set below the C40 marker in the Colville Group will be cemented back to surface. Within the pilot area, the base of permafrost is interpreted to be 1,300 ft. TVD. The intermediate hole will be drilled in one interval with the casing point being approximately 85 degrees inclination below the Minke sand top. The intermediate section between the proposed surface casing shoe and the top of Minke consists of clay matrix formations with interbedded siltstones and sandstones. Top of cement for the casing will extend a minimum of 500 feet measured depth or 250 feet true vertical depth, whichever is greater, above the shoe or higher if any hydrocarbon bearing formations are encountered in accordance with 20 AAC 25.030(d)(5). The Minke sand will be drilled horizontally and completed open hole with solid liner containing ball drop fracture sleeves and liner top hanger and packer as needed. External swell packers or cement may be added to isolate out of pay excursions and / or fault crossings along the lateral or to provide zonal control of the stimulation and future injection. The well will be completed with 4 ½ inch tubing to minimize hydraulic friction. The tubing/casing annulus pressure of each injection well will be tested in accordance with 20 ACC 25.412(c). Drilling and completion operations will be performed in accordance with applicable AOGCC regulations. In accordance with 20 AAC 25.412(d), cement quality logs, or other data approved by the Commission, will be provided for all injection wells to demonstrate isolation of the injected fluids to the approved interval. Application to the AOGCC for Approval of Pilot Water Injection into the Minke Reservoir Colville River Unit Page 14 ConocoPhillips Alaska, Inc. Figure 5: Schematic of Proposed Injection Well Application to the AOGCC for Approval of Pilot Water Injection into the Minke Reservoir Colville River Unit Page 15 ConocoPhillips Alaska, Inc. 20 AAC 25.402(c)(9) Injection Fluid Analysis and Injection Rates The Minke Pilot Injection Project will occur at the CD5 drill site, a satellite drill site that is connected to the Alpine Central Processing Facility (ACF). ACF and its network of drill sites were built to allow only one type of water, either produced or sea, on a drill site at a time. Water service for each drill site is selected to optimize the production potential of the entire asset. CD5 is currently on sea water service, but this could change over the duration of the pilot project. ACF has demonstrated the compatibility of both produced water and sea water in Brookian age reservoirs over the past 10 years. No issues are expected with injection of either fluid into the Minke formation. Part of the purpose for this pilot is to confirm compatibility. Injection rates between 2,000 and 8,000 bbl/d are expected at each injection well drilled for the pilot project. Primary injection fluids include: x Beaufort seawater sourced from the Kuparuk seawater treatment plant x Produced water from all present and yet-to-be defined oil pools within the CRU and GMTU Other fluids may also be injected for reservoir stimulation, reservoir performance evaluation, freeze protection, chemical inhibition, or to otherwise ensure efficient and safe operation of the Minke injection wells. These fluids are not planned for continuous injection, or as a means for enhanced recovery. The volumes of these other fluids are not expected to hinder the recovery efficiency of performance. These other fluids include: x Fluids used during hydraulic stimulation x Tracer survey fluids to monitor reservoir performance x Fluids used to improve near wellbore injectivity (acid, solvents, etc.) x Fluids used to seal wellbore intervals which negatively impact recovery (cement, resin, etc.) x Fluids associated with freeze protection (diesel, crude, glycol, methanol, etc.) x Standard oilfield chemicals (corrosion inhibitor, scale inhibitor, etc.) x Sump fluid, hydrotest fluid (excluding fluids derived from tests of transportation pipelines), rinsate generated from washing mud hauling trucks, excess well work fluids, and treated camp effluent and mixtures involving such fluids Barium sulfate scale formation in production wells, as has been experienced to various degrees in CRU pools, is possible due to the mixing of seawater (containing sulfate) and formation water (containing barium). A scale inhibition treatment program, like that performed in CRU pools, will be performed at Minke as required. Application to the AOGCC for Approval of Pilot Water Injection into the Minke Reservoir Colville River Unit Page 16 ConocoPhillips Alaska, Inc. 20 AAC 25.402(c)(10) Estimated Average and Maximum Injection Pressures The flowing bottom hole pressure of the pilot injection wells will be maintained within the strength of the Nanusuk Group seal. Microfracture measurements in the overburden from CD5-32X and analysis of available data in the seal interval yielded a fracture gradient greater or equal to 0.7 psi/ft. The pilot project will target an injection gradient of 0.6 psi/ft with an operating maximum below 0.7 psi/ft, but this is subject to change as more information is gathered. The pilot project will initially operate at the fracture gradient of the Minke reservoir sandstone which has demonstrated a fracture gradient of 0.58 psi/ft in the CD5-32X well DFIT test. Injection periods above the Minke reservoir fracture gradient (and below the top seal fracture gradient) may be done to evaluate increased injectability. As we learn more from the Minke reservoir, this target may be modified to above Minke reservoir sandstone fracture gradient indefinitely but will remain below the top seal fracture gradient. At 4,320’ SSTVD (datum) the initial target injection pressure will be 2,500 psi (0.58 psi/ft), with potential operational deviations up to a maximum of 3,015 psi (0.7 psi/ft). The operating pressure of each injector will be set based on the realized depth of the reservoir. Application to the AOGCC for Approval of Pilot Water Injection into the Minke Reservoir Colville River Unit Page 17 ConocoPhillips Alaska, Inc. 20 AAC 25.402(c)(11) Fracture Information In the CD5-32X area, the Minke reservoir is overlain by a 50 to 300 true vertical depth (TVD) foot thick, claystone section with thin siltstone and shale beds within the overlying Nanushuk group to the top Minke reservoir sandstone; here referred to as the Nanushuk Seal. The underlying confining zone beneath the Minke reservoir consists of shaly slope mudstones and shales of the Torok group that thicken to the east/southeast in excess of 300 feet TVD. The calculated hydraulic fracture gradient for the Nanushuk Seal is based on the available MicroFrac via SLBs MDT tool (Diagnostic Fracture Initiation Test (DFIT)) within the seal interval. The plot below in Figure 6 shows the resulting estimate for the fracture closure pressure for hydraulic fracture of the Nanushuk claystone seal in TVD below sea level and pore pressure (red line). Also shown is the pore pressure of the Minke reservoir sandstone (grey) and the planned range of injection pressures for the Minke pilot injection project. Figure 6: Fracture Gradient of Minke Upper Confining Layer Application to the AOGCC for Approval of Pilot Water Injection into the Minke Reservoir Colville River Unit Page 18 ConocoPhillips Alaska, Inc. 20 AAC 25.402(c)(12) Quality of Formation Water Water samples are available from the area of the pilot project. The water samples were acquired from the CD5-32X well. The salinity of this water was found to be about 16,000 ppm. Application to the AOGCC for Approval of Pilot Water Injection into the Minke Reservoir Colville River Unit Page 19 ConocoPhillips Alaska, Inc. 20 AAC 25.402(c)(13) Aquifer Exemption Reference In the original Alpine Pool application, CPAI demonstrated there are no freshwater aquifers in the Colville River Unit. In finding number 18 of CO 443, the Commission stated: “Calculated water salinity ranges from 15,000 to 18,000 milligrams per liter (mg/l) total dissolved solids (TDS) throughout the Cretaceous and older stratigraphic section in the Colville Delta area. Water samples collected from drill stem and production testing of several wells in the Colville Delta area yielded 18,500 to 24,000 mg/l TDS.” In conclusion number 5 of CO 443, the Commission stated: “There are no freshwater aquifers in the Colville River Unit”. This prior finding and conclusion remains valid. None of the subsequent oil pools and area injection orders in the Colville River Unit have found any freshwater aquifers to exist within the Colville River Unit area. Application to the AOGCC for Approval of Pilot Water Injection into the Minke Reservoir Colville River Unit Page 20 ConocoPhillips Alaska, Inc. 20 AAC 25.402(c)(14) Incremental Hydrocarbon Recovery A full characterization of the in-place fluids across the Minke trend is not currently available. Data gathered from the exploration well shows a reservoir which is slightly undersaturated, by approximately 300 psi, and an initial pressure of ~1,990 psi. This does not leave much driving force for primary depletion. The expected recovery without injection support is 5-10%. Reservoir modeling and analog data predict a recovery factor upwards of ~30% under waterflood. The Minke pilot injection project calls for a horizontal injection and production well offset the current CD5-32X vertical well along with an additional horizontal injection well at a later phase. These wells will allow us to test communication across a production half-pattern to full pattern and help ascertain if the expected recovery benefit of injection is feasible. Application to the AOGCC for Approval of Pilot Water Injection into the Minke Reservoir Colville River Unit Page 21 ConocoPhillips Alaska, Inc. 20 AAC 25.402(c)(15) Mechanical Condition of Wells Within ¼ Mile of Proposed Area There will be eight (8) wellbores, which penetrate the Minke interval within ¼ mile of proposed injection operations area (Figure 2). The nearest well will be CD5-32X as a monitoring well. The intended recipient of pressure support from proposed injection operations is CD5-629 at the edge of the area. Proposed wells will be drilled in accordance with applicable AOGCC drilling regulations. The seven (7) wells that currently exist are listed in Table 1 below. Only CD5-32X and CD5-21 have confirmed cement across the entire Minke. Annuli monitoring will occur daily while injection activities exist within ¼ mile of any uncemented annuli. All surface casings are set above the Minke interval. Table 1. Wells within ¼ mile injection radius of proposed area. Well NameATDB Status / Online Status / AnnC Status / ATDB Well TypeMech Integrity Comments / NotesCD5-21ACTIVE / N/A / Normal / WSSC landing ring ~3" high in conductor. Cement top job performed to bring cement up to landing ring for added stability.Has full cement plug across the Minke interval.CD5-92ACTIVE / Y / Normal / PRODNo Issues with Production or Intermediate casings.CD5-93ACTIVE / Y / Normal / INJNo Issues with Production or Intermediate casings.CD5-98ACTIVE / Y / Normal / PRODNo Issues with Production or Intermediate casings.CD5-32XACTIVE / N / Normal / PRODNo Issues with Production or Intermediate casings.Cemented across Minke with perfs to the Minke.CD5-314XACTIVE / Y / Normal / PRODOOAxForm Salt water flowing up conductor by surface casing annulus--listed as charging OA, but is actually 'charging conductor'. Down spout and catch drum installed on conductor. **Limit IA test pressure to 2500 psi if ever MITIA or CMIT on this producer due to derated casing.**CD5-316ACTIVE / Y / Normal / INJNo Issues with Production or Intermediate casings.CD5-629N/A / N/A / N/A / PROD N/ATo Be Drilled. Off-Set Producer for this Injector-Producer Pair.