The URL can be used to link to this page

Home My WebLink AboutERIO 008ERIO 8 Coyote Interval 1. August 11, 2022 CPAI application for Temp ERIO 2. September 2, 2022 Notice of public hearing, email list, bulk mail list, Affidavit of publication 3. September 8, 2022 CPAI email for rescheduling hearing 4. October 26, 2022 Second notice of public hearing, email list, bulk mail list, affidavit of publication 5. December 13, 2022 Hearing transcript and CPAI presentation 6. ----------------------- Progress reports STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION 333 West 7th Avenue Anchorage Alaska 99501 Re: THE APPLICATION OF ConocoPhillips Alaska for authorization for injection into the Coyote reservoir through a proposed waterflood pattern pilot project within and adjacent to the Kuparuk River Unit, North Slope Borough, Alaska ) ) ) ) ) ) ) ) ) Docket Number: ERIO-22-002 Enhanced Recovery Injection Order 8 Kuparuk River Unit Coyote Reservoir North Slope Borough, Alaska January 4, 2023 IT APPEARING THAT: 1. By application received August 12, 2022, ConocoPhillips Alaska, Inc. (CPAI) requested the Alaska Oil and Gas Conservation Commission (AOGCC) issue an order authorizing water (and potentially gas) injection into the Coyote reservoir as a pilot enhanced oil recovery (EOR) project within and adjacent to the Kuparuk River Unit (KRU) to test the injectivity of water (and potentially gas) and subsequent production response. 2. Pursuant to 20 AAC 25.540, the Alaska Oil and Gas Conservation Commission (AOGCC) tentatively scheduled a public hearing for October 6, 2022. On September 2, 2022, the AOGCC published notice of that hearing on the State of Alaska’s Online Public Notice website and on the AOGCC’s website, electronically transmitted the notice to all persons on the AOGCC’s email distribution list and mailed printed copies of the Notice of Public Hearing to all persons on the AOGCC’s mailing distribution list. On September 4, 2022, the notice was published in the Anchorage Daily News. 3. No comments on the application or request for hearing were received. 4. On October 6, 2022, the AOGCC convened the hearing and continued it until November 8, 2022. CPAI agreed with that new hearing date and time. 5. On October 26, 2022, the AOGCC rescheduled the public hearing from November 8, 2022 to November 29, 2022. On October 26, 2022, the AOGCC published notice of the rescheduled hearing on the State of Alaska’s Online Public Notice website and on the AOGCC’s website, electronically transmitted the notice to all persons on the AOGCC’s email distribution list and mailed printed copies of the Notice of Public Hearing to all persons on the AOGCC’s mailing distribution list. On October 30, 2022, the notice was published in the Anchorage Daily News. 6. On November 29, 2022, the AOGCC convened the hearing and continued it until December 13, 2022. 7. The hearing commenced at 10:00 a.m. on December 13, 2022. Testimony was received from representatives of CPAI. The hearing record closed on December 13, 2022. 8. CPAI’s testimony and application, AOGCC records, and public records provide sufficient information upon which to make an informed decision. PURPOSE AND NEED FOR THIS ORDER: Enhanced recovery regulations (20 AAC 25.402) are in place to ensure that EOR injection projects are conducted in a manner that will lead to increased ultimate recovery, prevent the injected fluids from escaping the injection interval, and protect sources of freshwater. Operators must apply for, and be granted, an order that authorizes EOR injection before they can commence injection operations. Part of the application process requires the operator to notify, and provide a copy of the application to, all operators and surface owners within a ¼-mile radius of the proposed injection ERIO 8 January 4, 2023 Page 2 of 6 well(s). For situations where the viability of a specific EOR process has not been demonstrated as being effective in a certain application, such as this proposal to conduct water injection for EOR purposes in the Coyote Interval, 20 AAC 25.450(b) allows the AOGCC to issue an injection order approving a pilot EOR injection project to allow for the gathering of information necessary to show whether or not it is viable before a full field project is pursued. Pilot project EOR orders are usually time limited and often require different data collection and reporting requirements than a conventional EOR injection order since the purpose of a pilot EOR injection project is to demonstrate feasibility of a process before pursuing it on a fieldwide basis. FINDINGS: 1. Affected Area: The Affected Area lies onshore within a portion of the KRU and adjacent non- unitized lease ADL 392374, which lies adjacent to western boundary of the KRU, North Slope Borough, Alaska. The proposed Coyote pilot EOR project will occur at KRU 3S-Pad drill site. 2. Owners and Landowners: CPAI is the owner and operator for the KRU and for lease ADL 392374. The State of Alaska, Department of Natural Resources, is the landowner of the Affected Area. 3. Exploration, Delineation, and Production History: Sinclair's Colville 1 first discovered oil in the Nanushuk Formation (Nanushuk) near the proposed pilot project area. Drilled and completed during winter 1965-66 about three miles south-southwest of 3S-Pad, the well encountered oil shows associated with C1 through C6+ gases in Nanushuk siltstone and sandstone between 4,090' and 4,220' MD (-4,057 and -4,187' TVDSS) and in underlying Torok sandstone from 5,290' to 5,440' MD (-5257 to -5407' TVDSS). The well also encountered oil associated with C5 and C6+ gases in overlying, possibly Tuluvak-equivalent, clay and siltstone strata between 2,590' and 2,710' MD (-2,557' to -2,677' TVDSS). In 2001, Phillips Alaska, Inc.’s Palm 1 exploratory well—drilled from what is now 3S-Pad— encountered oil shows with C1 through C5 gases in Nanushuk sandstone from 4,275’ to 4,570’ MD (-4,038’ to -4,279’ TVDSS). The well also displayed oil staining and C1 to C2 gases from in Tuluvak-equivalent strata from 2,520’ to 2,710’ MD (-2,459’ to -2,649’ TVDSS), and traces of oil stain and C1 and C2 gases from 3,260’ to 3,300’ MD (-3,186’ to -3,223’ TVDSS). Seven development and service wells drilled to deeper reservoirs within the Kuparuk River Unit have also penetrated the Coyote interval in and near the planned project area: 3S-03, 3S-21, 3S-22, 3S-23, 3S-24, 3S-24B, 3S-613, and 3S-625. Exploratory, redrilled well 3S-24B penetrated and tested the Coyote interval. 4. Pool Identification: A formal pool has not been established for the middle Cretaceous-aged (Albian-Cenomanian) Nanushuk reservoir sands of Kuparuk River Field. For the proposes of this order, CPAI defines the affected sediments of the Nanushuk as the informally named Coyote sands. These sands—and the accumulation of oil within them—are common to, and correlate with, the interval in reference well Palm 1 between 4,270 and 5,115 feet MD (-4,038’ and -4,720’ TVDSS). 5. Geology: a. Structure: At Coyote level, the regional structure is a paleo-shelf margin that plunges to the northeast and southeast, has limited relief (about 100 feet), and displays a few small four-way dip closures. b. Stratigraphy: The Coyote reservoir consists of thinly bedded, delta-front, distal delta- front, and pro-delta siltstones and sandstones deposited along a northeast-trending paleo-shelf margin. Gross sand for interval averages 650 feet true vertical thickness (TVT). ERIO 8 January 4, 2023 Page 3 of 6 c. Rock Properties: Coyote sandstone porosities average about 23 percent, and permeability ranges from 10 to 20 millidarcies. d. Faults: One fault has been mapped within the proposed pilot project area, near the heel of the planned production well. This small, normal fault strikes northwest, dips north- east, is about 2,000 feet long, and has about 30 feet of maximum vertical displacement. It is limited in vertical extent to the uppermost 200 feet of the Coyote reservoir and about 300 feet of the overlying Seabee Shale. e. Trap Configuration and Seals: Coyote is predominantly a stratigraphic trap. The reservoir sandstones pinch out to the west and shale out to the northeast, southeast and southwest. Stratigraphic compartments and four-way dip closures may be present within the reservoir and may contain small gas caps. Upper confinement is provided by about 350 true vertical feet of claystone, mudstone, and shale assigned to the Seabee Formation. Lower confinement is provided by about 300 true vertical feet of mudstone and siltstone assigned to the Torok Formation. 6. Reservoir Fluid Properties: Oil within the Coyote interval averages about 32° API gravity. Analysis of a water sample collected from the Coyote reservoir in KRU 3S-24B indicates total dissolved solids in the formation water exceed 21,000 mg/l. 7. In-Place Volume and Recoverable Estimates: CPAI estimates 31 million barrels of oil within the proposed pilot project area. Primary recovery factor is estimated to be 5 to 10 percent, and waterflood recovery is expected to be 20 to 30 percent. Potential injection of enriched gas is anticipated to recover an additional 1 to 5 percent. 8. Project Scope Plans: The initial scope of CPAI’s proposed, three-year pilot project consists of a central horizontal producer with one offsetting horizontal injector located about 1,500 feet to the west. Depending upon initial results, a second horizontal injector may be drilled about 1,500 feet east of the producer. 9. Confining Layers for Injection: Upper confinement is provided by about 350 true vertical feet of claystone, mudstone, and shale assigned to the Seabee Formation. Lower confinement is provided by about 300 true vertical feet of mudstone and siltstone assigned to the Torok Formation. 10. Injection Confinement and Pressure Monitoring within Nearby Wells: CPAI plans to fracture stimulate the proposed pilot project wells. Existing wells KRU 3S-03 and KRU 3S-21—that lie within a one-quarter mile radius of the pilot project and produce from, or inject into, the underlying Kuparuk Formation—are currently open to the Coyote interval. CPAI testified that the Coyote interval in KRU 3S-21 will be isolated with cement prior to fracture stimulation of the proposed pilot project wells. CPAI proposes to monitor the more distant well KRU 3S- 03 for pressure changes during Coyote fracture stimulation. 11. Injection Pressure: The target injection pressure gradient for this pilot project is 0.61 psi/ft to avoid fracturing the overlying Seabee Shale confining layer, which has an estimated fracture gradient of 0.65 psi/ft. Sand-face injection pressure in each injector will be based on the actual depth of the reservoir. CPAI plans further data collection to refine rock-strength estimates. 12. Fluid Compatibility: Produced water from 3S-24B and CPAI’s modeling indicates potential for calcium carbonate and barium sulfate scaling. The planned pilot project wells will be included in the Greater Kuparuk Area scale monitoring and inhibition program. CPAI plans to collect a whole core while drilling the planned wells and will conduct additional water compatibility testing as part of the core analysis program. 13. Injection Fluids: Planned injection fluids include produced water from KRU oil pools, Beaufort seawater from the Kuparuk seawater treatment plant, hydraulic fracture fluids, tracer survey fluids, wellbore injectivity improvement fluids, freeze protection fluids, and standard ERIO 8 January 4, 2023 Page 4 of 6 oil field chemicals such as corrosion and scale inhibitors. CPAI also proposes potential injection of produced gas from KRU oil pools and enriched hydrocarbon gas (indigenous produced gas and/or imported natural gas liquids), which is informally termed “miscible injectant.” CONCLUSIONS: 1. Pursuant to 20 AAC 25.402 and 20 AAC 25.450(b), an Enhanced Recovery Injection Order is appropriate to authorize the proposed pilot injection project in the Coyote interval within the KRU. 2. Waterflood injection into the Coyote interval should substantially improve oil recovery, but the technical and economic feasibility of conducting such an operation has not been demonstrated. 3. Restricting injection pressure to a gradient of 0.61 psi/ft at the sand face will prevent the overlying confining layer from fracturing. Collection, evaluation, and reporting of additional rock-strength data will allow maximum injection pressure to be adjusted appropriately. 4. An aquifer exemption is not needed. Available information indicates that formation water in the proposed Coyote injection interval exceeds 10,000 mg/l total dissolved solids; accordingly, the aquifer is not a potential source of drinking water. 5. Regular monitoring and reporting of pressure within nearby well KRU 3S-03 is appropriate for the duration of the proposed pilot project. However, the Coyote interval within KRU 3S- 03 must be cement-isolated immediately if a pressure increase is observed, or upon completion of the pilot project in conformance with 20 AAC 25.030. 6. Uncertainties including rock-strength estimates, unproven reservoir and confinement performance, and potential pressure effects on nearby wells that are currently open to the Coyote interval preclude injection of produced or enriched gas at this time. NOW THEREFORE IT IS ORDERED: The underground injection of fluids for pressure maintenance and enhanced recovery is authorized in the following area, subject to the following rules and 20 AAC 25, to the extent not superseded by these rules: Affected Area: Umiat Meridian Township, Range Sections T12N, R7E 24: E1/2, E1/2NW1/4 25: E1/2 T12N, R8E 18: S1/2SW1/4 19: W1/2, W1/2NE1/4, SE1/4 30: All Rule 1 Authorized Injection Strata for Enhanced Recovery Within the Affected Area, the Class II fluids specified in Rule 3 below may be injected for the purposes of pressure maintenance and enhanced recovery into strata that correlate with, and are common to, the interval in reference well Palm 1 between 4,270 and 5,115 feet MD. ERIO 8 January 4, 2023 Page 5 of 6 Rule 2 Fluid Injection Wells The injection of fluids must be conducted through a new well that has been permitted in conformance with 20 AAC 25.005 as a service well for injection, or through an existing well that AOGCC has approved for conversion to a service well for injection, in conformance with 20 AAC 25.280. Rule 3 Authorized Fluids for Injection for Enhanced Recovery Fluids authorized for injection are: a. Produced water from the KRU; b. Seawater from the Kuparuk Seawater Treatment Plant; c. Tracer survey fluids to monitor reservoir performance. and d. Fluids used to improve near wellbore injectivity (acids, solvents, etc.). Rule 4 Authorized Injection Pressure for Enhanced Recovery Injection pressures shall not exceed the maximum injection gradient of 0.61 psi/ft to ensure containment of injected fluids within the defined Affected Area and injection interval. Rule 5 Monitoring Tubing-Casing Annulus Pressure Inner annulus, outer annulus, and tubing pressures for all injection and production wells, and any well within the affected area that is not cemented across the Coyote interval shall be monitored and recorded at least daily, except if prevented by extreme weather condition, emergency situation, or similar unavoidable circumstances. All monitoring results shall be documented and provided to the AOGCC on a monthly basis. Rule 6 Demonstration of Tubing/Casing Annulus Mechanical Integrity The mechanical integrity of each injection well must be demonstrated before injection begins, before returning a well to service following any workover affecting mechanical integrity, and at least once every two years. An AOGCC-witnessed mechanical integrity test (MIT) must be performed after injection is commenced for the first time in a well, to be scheduled when injection conditions (e.g., temperature, pressure, rate, etc.) have stabilized. Should the duration for this pilot project be extended, subsequent tests must be performed at least once every two years thereafter. Rule 7 Well Integrity and Confinement Whenever any pressure communication, leakage, or lack of injection zone isolation is indicated by an injection rate, operating pressure observation, test, survey, log, or any other evidence (including outer annulus pressure monitoring of all wells within a one-quarter mile radius of where the Coyote reservoir is not cemented), the operator shall notify the AOGCC by the next business day and submit a plan of corrective action on a Form 10-403 for AOGCC approval. The Operator shall immediately shut in the well if continued operation would be unsafe or would threaten contamination of freshwater. A monthly report of daily tubing and casing annuli pressures and injection rates must be provided to the AOGCC for all injection wells for which well integrity failure or lack of injection zone isolation is indicated. Rule 8 Notification of Improper Class II Injection Injection of fluids other than those listed in Rule 3 without prior authorization is considered improper Class II injection. Upon discovery of such an event, the operator must immediately notify the AOGCC, provide details of the operation, and propose actions to prevent recurrence. This requirement is in addition to and does not relieve the operator of any other obligations under the ERIO 8 January 4, 2023 Page 6 of 6 notification requirements of any other State or Federal agency, regulation or law. Rule 9 Other Conditions If fluids are found to be fracturing the confining zone or migrating out of the approved injection stratum, the operator must immediately shut in the injection wells and immediately notify the AOGCC. Injection must not be restarted unless approved by the AOGCC. Rule 10 Expiration Date This Enhanced Recovery Injection Order shall expire three years after the month in which injection activity commences unless an extension is granted by the AOGCC. Rule 11 Reporting Requirements By April 1st of each year, starting in 2024, the operator must submit a progress report on the pilot injection project to the AOGCC. Within 90 days of the end of the pilot injection project, the operator must submit a final report to the AOGCC. These reports shall include: - Information on any adverse events related to the pilot injection project that may have occurred, - The average and maximum injection rates and pressures for each injection well during injection activities (data from shut in periods shall be excluded when calculating the average values), - The results of any surveillance and/or tracer testing that was conducted, - Discussion on whether an enhanced recovery response was noted in the producer(s), and - Discussion of plans for the upcoming year. DONE at Anchorage, Alaska and dated January 4, 2023. 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: 2023.01.04 10:49:06 -09'00' Gregory Wilson Digitally signed by Gregory Wilson Date: 2023.01.04 13:01:07 -09'00' From:Carlisle, Samantha J (OGC) To:AOGCC_Public_Notices Subject:[AOGCC_Public_Notices] Enhanced Recovery Injection Order 8 (Kuparuk River Unit) Date:Wednesday, January 4, 2023 2:25:03 PM Attachments:erio8.pdf Re: THE APPLICATION OF ConocoPhillips Alaska for authorization for injection into the Coyote reservoir through a proposed waterflood pattern pilot project within and adjacent to the Kuparuk River Unit, North Slope Borough, Alaska Samantha Carlisle AOGCC Special Assistant Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage, AK 99501 (907) 793-1223 __________________________________ List Name: AOGCC_Public_Notices@list.state.ak.us You subscribed as: samantha.carlisle@alaska.gov Unsubscribe at: https://list.state.ak.us/mailman/options/aogcc_public_notices/samantha.carlisle%40alaska.gov Bernie Karl K&K Recycling Inc. P.O. Box 58055 Fairbanks, AK 99711 mailed 1/4/23 6 March 14, 2024 Alaska Oil and Gas Conservation Commission 333 West 7 th Avenue, Suite 100 Anchorage, AK 99501 Attention: Commissioner Brett Huber RE: x 2023 ERIO6 Narwhal Pilot Injection Project Final Progress Report x Form 10-412 for ERIO6 Narwhal Undefined Oil Pool Dear Commissioner Huber, ConocoPhillips Alaska, Inc., as operator and sole working interest owner of the Colville River Unit, submits the 2023 annual progress report on the Narwhal pilot injection project in accordance with Rule 11. This will be the final report related to ERIO6 due to the termination of ERIO6 and its administrative approvals by the Alaska Oil and Gas Conservation Commission as of December 19, 2023. Sincerely, Ian Ramshaw Manager Western North Slope Asset Development Ian Ramshaw WNS Asset Development Manager ConocoPhillips Alaska, Inc. PO Box 100360 Anchorage, Alaska 99510-0360 Phone: (907) 263-4464 2023 ERIO6 Narwhal Pilot Injection Project Final Progress Report 2023 ERIO6 Narwhal Pilot Injection Project Final Progress Report ConocoPhillips Alaska, Inc., as operator and sole working interest owner of the Colville River Unit, submits the 2023 annual progress report on the Narwhal pilot injection project in accordance with Rule 11. Rule 11 reporting requirements state that by April 1 of each year, starting in 2021, the operator must submit a progress report on the pilot injection project to the Alaska Oil and Gas Conservation Commission (AOGCC). Within 90-days of the end of the pilot injection project the operator must submit a final report to the AOGCC. These reports shall include: x Information on any adverse events related to the pilot injection project that may have occurred, x The average and maximum injection rates and pressures for each injection well during injection activities (data from shut in periods shall be excluded when calculating the average values), x The results of any surveillance and/ or tracer testing that was conducted, x Discussion on whether an enhanced recovery response was noted in CD4 -595, and x Discussion of plans for the upcoming year. A: Information on any Adverse Events Related to the Pilot Injection Project that may have Occurred No adverse events related to the pilot injection project were noted. B: The Average and Maximum Injection Rates and Pressures for each Injection Well During Injection Activities CD4-594 and 597 are currently active injectors in the Narwhal pilot program. Average monthly water injection rate and wellhead pressure for CD4-594 are shown on the table below: Month Inj. BWPD Wellhead psi Jan-23 1725 1094 Feb-23 1512 1097 Mar-23 1698 1094 Apr-23 947 1083 May-23 0 0 Jun-23 0 0 Jul-23 0 0 Aug-23 0 0 Sep-23 0 0 Oct-23 0 0 Nov-23 0 0 Dec-23 843 846 Jan-24 1971 893 2023 ERIO6 Narwhal Pilot Injection Project Final Progress Report The maximum daily rate of CD4-594 in 2023 was 2,879 BWPD and maximum daily wellhead pressure in 2023 was 1,172 psi. Average monthly water injection rate and wellhead pressure for CD4-597 are shown on the table below: Month Inj. BWPD Wellhead psi Jan-23 0 0 Feb-23 0 0 Mar-23 0 0 Apr-23 0 0 May-23 0 0 Jun-23 0 0 Jul-23 0 0 Aug-23 0 0 Sep-23 0 0 Oct-23 1688 210 Nov-23 61 252 Dec-23 987 268 Jan-24 2148 318 The maximum daily rate of CD4-597 in 2023 was 3,119 BWPD and maximum daily wellhead pressure in 2023 was 1,440 psi. C: The Results of any Surveillance and/or Tracer Testing that was Conducted Downhole pressure monitoring indicated sand continuity between injector and producer during injection pulse testing. No inter-well tracer testing was performed to confirm continuity. No new surveillance specific tests have been conducted since the last report. The wells are now on long term production & injection. D: Discussion on Whether an Enhanced Recovery Response was Noted in CD4-595 CD4-597 was frac’ed and brought online in 2023. All wells in the pattern (CD4-595, CD4-597, and CD4-594) are now on long term production & injection. The rates achieved in each well continue to agree with their respective forecasts which suggests water injection support between wells. Formation gas/oil ratio continues to be stable indicating waterflood support in the pattern. E: Discussion of Plans for the Upcoming Year. All wells in the pattern will remain on long term injection and production. No further changes in the operating plan are expected at this time. Following the approval of AIO 35A, ERIO6 has been terminated and ERIO6 wells incorporated in AIO 35A. Attachment 1: 10-412 Reservoir Pressure Report 5 AOGCC 12/13/2022 ITMO: CONOCOPHILLIPS AK Docket No. ERIO-22-002 329 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 the Application of ) ConocoPhillips Alaska for an Enhanced ) Recovery Injection Order for the Coyote ) Interval. ) __________________________________________) Docket No.: ERIO-22-002 PUBLIC HEARING December 13, 2022 10:00 o'clock a.m. BEFORE: Jessie Chmielowski, Commissioner Greg Wilson, Commissioner AOGCC 12/13/2022 ITMO: CONOCOPHILLIPS AK Docket No. ERIO-22-002 329 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 Remarks by Mr. Perfetta 06 4 Remarks by Mr. Castongia 14 5 Remarks by Ms. Alshire 17 6 Remarks by Mr. Sisemore 20 7 Remarks by Mr. Callahan 27 8 Remarks by Mr. Morrow 31 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 AOGCC 12/13/2022 ITMO: CONOCOPHILLIPS AK Docket No. ERIO-22-002 329 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 - 10:00 a.m.) 3 COMMISSIONER CHMIELOWSKI: Good morning. I 4 will call this hearing to order. It is approximately 5 10:00 a.m. on Tuesday, December 13, 2022. This is a 6 public hearing on Docket number ERIO-22-002 to consider 7 ConocoPhillips Alaska's application for an enhanced 8 recovery injection order for the Coyote interval. I am 9 Commissioner Jessie Chmielowski and with me is 10 Commissioner Greg Wilson. 11 Today's hearing is being held in person and via 12 Microsoft Teams. The in person location is the Alaska 13 Oil and Gas Conservation Commission office at 333 West 14 7th Avenue, Anchorage, Alaska. For those on Teams 15 please be mindful of any background noise and make sure 16 you are muted when you are not testifying or addressing 17 the Commission. 18 If you require any special accommodation please 19 contact Samantha Carlisle. She can be reached at 907- 20 793-1223 or send her a message through the Microsoft 21 Teams chat icon and she will do her best to accommodate 22 you. 23 Computer Matrix will be recording the hearing. 24 Upon completion and preparation of the transcript 25 persons desiring a copy will be able to obtain it by AOGCC 12/13/2022 ITMO: CONOCOPHILLIPS AK Docket No. ERIO-22-002 329 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 contacting Computer Matrix. 2 This hearing is being held in accordance with 3 Alaska Statute 44.62 and 20 AAC 25.540 of the Alaska 4 Administrative Code. 5 The notice of hearing was published on the 6 State of Alaska Online Notices website as well as the 7 AOGCC's website and was sent through the AOGCC Email 8 List Serv on September 2nd, 2022. The AOGCC also 9 published the notice in the Anchorage Daily News on 10 September 4th, 2022. 11 To date the AOGCC has not received any public 12 comment on the matter. 13 Before asking ConocoPhillips to begin their 14 presentation, Commissioner Wilson, do you have any 15 comments or questions? 16 COMMISSIONER WILSON: Yeah. Before beginning 17 today's hearing I would like to put on the public 18 record that I was previously employed at ConocoPhillips 19 and retired in May of 2021. Out of an abundance of 20 caution and in accordance with procedures outlined in 21 the Executive Branch Ethics Act prior to today's 22 hearing I requested an ethics determination from my 23 designated ethics supervisor as to whether I may make 24 decisions on ConocoPhillips matters that come before 25 the AOGCC. After receiving guidance from the Attorney AOGCC 12/13/2022 ITMO: CONOCOPHILLIPS AK Docket No. ERIO-22-002 329 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 General's Office, my ethics supervisor has informed me 2 that I may participate in this ConocoPhillips matter 3 and there would be no violation of the Executive Ethics 4 Act to do so. 5 COMMISSIONER CHMIELOWSKI: Based on that 6 disclosure and pursuant to the Executive Branch Ethics 7 Act procedures, I do not object to Commissioner 8 Wilson's participation in this matter. 9 All right. So the Commissioners will ask 10 questions during testimony. We may also take a recess 11 to consult with Staff to determine whether additional 12 information or clarifying questions are necessary. 13 ConocoPhillips representatives, are you ready 14 to make your presentation? 15 MR. PERFETTA: We are. 16 COMMISSIONER CHMIELOWSKI: Great. For those 17 testifying please keep in mind that you must speak into 18 the microphone, that light should be bright green. 19 Also remember to reference your slides so that someone 20 reading the public record can follow along. For 21 example refer to slides by their numbers if numbered or 22 by their titles if not numbered. Please state your 23 names and job titles clearly for the record and please 24 begin. 25 MR. PERFETTA: Okay. Thank you. Slide one. AOGCC 12/13/2022 ITMO: CONOCOPHILLIPS AK Docket No. ERIO-22-002 329 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 Good morning, Commissioners. My name is Patrick 2 Perfetta, I'm the project lead and also the project 3 geologist for the Coyote project. On behalf of 4 ConocoPhillips Alaska and my colleagues, Lynn Alshire, 5 Mike Callahan, Ethan Castongia, Dustin Morrow and 6 Nathan Sisemore we're here to testify as expert 7 witnesses as it relates to the application for a pilot 8 enhanced recovery injection order associated with the 9 Coyote reservoir. 10 Before I begin I wish to be recognized as an 11 expert in geology. 12 COMMISSIONER CHMIELOWSKI: Okay. Please state 13 your educational background and work history. 14 MR. PERFETTA: I earned a bachelor of science 15 degree in geology from Indiana University of 16 Pennsylvania and a master's in geology from University 17 of Missouri at Columbia also in geology. I have 18 approximately 24 years of industry experience, all with 19 ConocoPhillips and its heritage companies. I've worked 20 project from every phase, from new ventures exploration 21 to field development. I've also held technical lead 22 roles in ConocoPhillips. I've worked in Alaska for 23 approximately 14 years. 24 COMMISSIONER CHMIELOWSKI: Thank you. I have 25 no objection. AOGCC 12/13/2022 ITMO: CONOCOPHILLIPS AK Docket No. ERIO-22-002 329 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 COMMISSIONER WILSON: No objections. 2 PATRICK PERFETTA 3 previously sworn under oath, called as a witness on 4 behalf of ConocoPhillips, stated as follows: 5 MR. PERFETTA: Okay. I'll be brief in my 6 initial comments. Thank you to the Commissioners for 7 granting us on behalf of ConocoPhillips Alaska the 8 opportunity to speak to you about the Coyote 9 application for temporary injection. We would also 10 like to recognize the AOGCC's Staff who provided 11 feedback on a preliminary version of our application 12 prior to official submittal. 13 Slide two. This is just a list of acronyms 14 that can be found in the presentation. If you have any 15 questions related to them please let us know, it's 16 purely for reference. 17 Slide three. This is a brief description of 18 the objective of the presentation as well as our 19 agenda. The objective is to supply AOGCC with the 20 information necessary to approve CPAI's Coyote enhanced 21 recovery injection order application. The agenda and 22 person or persons that will be covering that topic are 23 listed in the presentation outline. 24 I'd like to ask the Commissioners if they'd 25 like to swear folks in all at once or as we progress AOGCC 12/13/2022 ITMO: CONOCOPHILLIPS AK Docket No. ERIO-22-002 329 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 through the presentation? 2 COMMISSIONER CHMIELOWSKI: We can do that all 3 at once. 4 MR. PERFETTA: Okay. So we can start with 5 Ethan Castongia. 6 COMMISSIONER CHMIELOWSKI: Well, we can do it 7 all at once if you all just want to I guess raise your 8 right hand. 9 MR. PERFETTA: Oh, okay. 10 (Oath administered) 11 IN UNISON: Yes. 12 COMMISSIONER CHMIELOWSKI: Great. Thank you. 13 You're all sworn in. 14 MR. PERFETTA: We'll move to slide four which 15 is just a -- will now give a brief description of the 16 project request. 17 Now we're moving to slide five. It covers a 18 brief history of the exploration activity associated 19 with testing the Coyote interval on ConocoPhillips' 20 acreage and the request for approval of the pilot 21 injection project. The slide includes a map showing 22 the location of the area of interest within the western 23 portion of the Kuparuk River unit at drill site 3S. 24 The Coyote interval was drilled, stimulated and tested 25 in the 3S24B borehole during late 2021 and early 2022. AOGCC 12/13/2022 ITMO: CONOCOPHILLIPS AK Docket No. ERIO-22-002 329 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 map on the right-hand side of the slide shows the 2 location of the borehole highlighted by the yellow 3 star. In order to accomplish this test the 3S24A 4 Kuparuk well was plugged and abandoned and then 5 sidetracked in order to obtain a vertical borehole 6 cemented across the Coyote interval. The well was then 7 fracture stimulated and flow tested. This test proved 8 good productivity of the Coyote interval on 9 ConocoPhillips' acreage, prompting us to want to 10 proceed with a horizontal injection pilot as part of a 11 horizontal producer/injector well pair. 12 ConocoPhillips is requesting approval for an 13 injection pilot covering the area highlighted by the 14 blue rectangle on the map. This map is located 15 adjacent to drill site 3S on the western side of the 16 Kuparuk River unit and in an adjoining lease that 17 currently resides outside of the unit. The duration of 18 the proposed pilot injection period is requested to be 19 three years. This will provide enough time for us to 20 understand injectivity into the Coyote interval and if 21 pressure support between the planned producer and 22 injector is seen. 23 Planned drilling of the initial horizontal 24 producer/injector will take place in Q4 of 2022 through 25 Q1 of 2023. These are the dashed blue and green lines AOGCC 12/13/2022 ITMO: CONOCOPHILLIPS AK Docket No. ERIO-22-002 329 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 on the map. Both the injector and producer will be 2 fracture stimulated. As part of this drilling program 3 a vertical pilot hole will be drilled for dedicated 4 data collection including hole core and advanced 5 logging. The requested three year duration of the 6 pilot injection period will allow ample time for 7 surveillance, integration of the robust data set being 8 collected and if warranted allow time to drill an 9 offset injector to the northeast of the producer in 10 order to complete a fully supported producer centered 11 pattern. 12 COMMISSIONER CHMIELOWSKI: Thank you. So the 13 producer/injector pair is planned for three years plus 14 a possible second injector? 15 MR. PERFETTA: That is correct..... 16 COMMISSIONER CHMIELOWSKI: Okay. 17 MR. PERFETTA: .....yes. Part of the initial 18 drilling will be the producer and injector. 19 COMMISSIONER CHMIELOWSKI: Thanks. 20 MR. PERFETTA: Slide six. I will now 21 transition and give a brief land overview including a 22 plat of the wells penetrating the injection zone and 23 operators within a quarter mile of the -- of the 24 operations. 25 Slide seven. The plat provided shows the AOGCC 12/13/2022 ITMO: CONOCOPHILLIPS AK Docket No. ERIO-22-002 329 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 lateral section of two injector wells on either side of 2 our producer well. The black boundary around the well 3 denotes a one-quarter mile boundary from the wellbore. 4 The only surface owner in the area is the state of 5 Alaska and there are no other operators within the one- 6 quarter mile buffer of either wellbore. A portion of 7 the producer and a portion of the northeastern injector 8 extend into a lease not currently within the Kuparuk 9 River unit. An application to expand the unit will be 10 submitted in the coming months. 11 Slide eight. We'll now move to a geologic 12 overview of the Coyote interval and its confining 13 zones. 14 Slide nine. The Coyote interval is part of the 15 Cretaceous, Brookian, Nanushuk sequence. It represents 16 a generally west to east progradational sequence. The 17 depositional environment of the Coyote is likely delta 18 front to distal delta front deposits. It is part of a 19 elongate northeast to southwest system that parallels 20 ophelia shelf margin. Average sand porosities are in 21 the order of 23 to 24 percent with permeabilities 22 averaging 10 to 20 millidarcies. 23 In the area of the proposed injection pilot the 24 gross Coyote interval has a thickness in excess of 600 25 feet TVD. A type log for the Coyote interval from the AOGCC 12/13/2022 ITMO: CONOCOPHILLIPS AK Docket No. ERIO-22-002 329 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 Palm 1 well is shown on the right-hand side of the 2 slide. The location of the Palm 1 well relative to the 3 area of the proposed injection pilot can be found on 4 the inset structure map. This is highlighted by the 5 yellow star on the inset map. Highlighted in yellow on 6 the log display is the gross Coyote interval with top 7 Coyote at approximately 4,270 feet measured depth and 8 base Coyote at approximately 5,115 feet measured depth. 9 From left to right the curvastein displayed are gamma 10 ray, resistivity, density neutron and compressional and 11 sheer sonic. 12 The upper confining zone of the Coyote interval 13 consists of approximately 350 feet TVD of distal 14 (indiscernible) slope CV formation claystones and 15 siltstone. This package is consistent across the 3S 16 pad area. The lower confining zone of the Coyote 17 interval consists of approximately 300 feet TVD of 18 distal (indiscernible) slope Torok mudstones. This 19 package is also consistent across the area and 20 represents the upper confining zone of the Kuparuk 21 River Torok oil pool. 22 The Coyote is predominantly a stratigraphic 23 trap with pinch out to the west and shale out to the 24 northeast and southwest. Structurally the Coyote is 25 low relief. The structure maps are shown on the lower AOGCC 12/13/2022 ITMO: CONOCOPHILLIPS AK Docket No. ERIO-22-002 329 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 left of the slide. A subregional map and a zoomed in 2 version of the area of the proposed injection pilot are 3 included here. Structural high areas on the map are in 4 reddish colors with the blue to purplish colors being 5 structural lows. The top Coyote structure does have 6 the presence of a small, low relief four way dip 7 closure and that's interpreted to harbor a small gas 8 cap in the 3S area. 9 There is limited faulting in the top Coyote 10 structure. One small offset, laterally discontinuous 11 fault at the top of the Coyote is present to the 12 northeast of heel of the proposed Coyote horizontal 13 producer as seen on the inset structure map. Happy to 14 take any questions on this. And if not I will turn it 15 over to Ethan Castongia. 16 COMMISSIONER CHMIELOWSKI: Please proceed. And 17 state your name and affiliation or your name and title 18 for the record, please. 19 MR. CASTONGIA: Oh, yes. I am Ethan Castongia, 20 project geophysicist and that is my current position 21 with ConocoPhillips. And I wish to be recognized as an 22 expert witness in geophysics. 23 COMMISSIONER CHMIELOWSKI: Okay. Please state 24 your credentials. 25 MR. CASTONGIA: I have a bachelor's degree in AOGCC 12/13/2022 ITMO: CONOCOPHILLIPS AK Docket No. ERIO-22-002 329 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 geology from University of Illinois Urbana-Champaign 2 and a master's degree from University of Wisconsin 3 Madison in geophysics. I have approximately eight 4 years of industry experience all with ConocoPhillips. 5 I've worked projects at most phases from exploration to 6 field development as well as a geophysical technology 7 role. I've worked Alaska project for approximately six 8 years. 9 COMMISSIONER CHMIELOWSKI: I have no 10 objections. 11 COMMISSIONER WILSON: No objections. 12 ETHAN CASTONGIA 13 previously sworn under oath, called as a witness on 14 behalf of ConocoPhillips, stated as follows: 15 MR. CASTONGIA: Okay. Thank you. We are on 16 slide 10. Shown are three schematic sections showing 17 some seismic face interpretations along with a map 18 previously shown highlighting the proposed injection 19 area with the planned injector in blue and the planned 20 producer in green and possible future injector in gray. 21 The map also has overlays of the lines of sections and 22 the mapped fault in the proposed injection area. First 23 section on the left is along the planned horizontal 24 injector part of the wellbore from A to A prime. It 25 shows subtle dip changes along the plan with a AOGCC 12/13/2022 ITMO: CONOCOPHILLIPS AK Docket No. ERIO-22-002 329 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 thickening overall Coyote package with no features from 2 a drilling concern. 3 In the middle from B to B prime is an obliqued 4 planned wells oriented section that passes through a 5 single, small displacement mapped fault at top Coyote, 6 the heel of the planned producer is expected to cross. 7 Expected max displacement of the fault is approximately 8 30 feet and a length from tip to tip of approximately 9 2,000 feet. It cuts the top Coyote and extends 300 10 feet into the overburden where it loses throw and 11 extends into the Coyote reservoir by 200 feet where it 12 also loses throw. The fault is interpreted to be 13 sealing where it displaces reservoir against overlying 14 CB shale. It is uncertain whether the fault is sealing 15 not where it juxtaposes reservoir against reservoir. 16 This is the only expected fault that intersects the 17 Coyote interval resolved by seismic in the proposed 18 injection area. 19 The third section from C to C prime is the same 20 orientation as previous section, just translated to the 21 southeast past the extent of the fault to show the 22 fault is interpreted to be limited in extent and not 23 expected in the possible future horizontal injector nor 24 the planned horizontal injector as shown in the first 25 section from A to A prime. AOGCC 12/13/2022 ITMO: CONOCOPHILLIPS AK Docket No. ERIO-22-002 329 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 Any questions? 2 COMMISSIONER CHMIELOWSKI: Did you already say 3 what the little symbols are on the maps, they look like 4 broken up circles? 5 MR. CASTONGIA: That is the cross section 6 expected place for where the horizontals will be 7 at..... 8 COMMISSIONER CHMIELOWSKI: Okay. 9 MR. CASTONGIA: .....within depth. 10 COMMISSIONER CHMIELOWSKI: Got it. 11 MR. CASTONGIA: If there are no further 12 questions then we will move on to slide 11 and I will 13 past it over to Lynn. 14 MS. ALSHIRE: My name's Lynn Alshire, I'm a 15 staff surveillance reservoir engineer and I'd like to 16 be recognized as an expert in petroleum engineering. 17 COMMISSIONER CHMIELOWSKI: Okay. Please state 18 your credentials. 19 MS. ALSHIRE: Sure. I earned a bachelor of 20 science from South Dakota School of Mines in geological 21 engineering. I further went on to a master's degree in 22 civil engineering from the University of Alaska 23 Anchorage and a second master's in Arctic engineering 24 also from UAA. I've about 17 years of petroleum 25 engineering experience all in the state of Alaska. It AOGCC 12/13/2022 ITMO: CONOCOPHILLIPS AK Docket No. ERIO-22-002 329 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 includes Cook Inlet offshore production, OCS lease 2 resource evaluation and North Slope production and 3 reservoir engineering. 4 COMMISSIONER CHMIELOWSKI: I have no 5 objections. 6 COMMISSIONER WILSON: No objections. 7 MS. ALSHIRE: Thank you. 8 LYNN ALSHIRE 9 previously sworn under oath, called as a witness on 10 behalf of ConocoPhillips stated as follows: 11 MS. ALSHIRE: Slide 12. And we're going to 12 look at primary injection fluids. These will be from 13 the same sources as current injection in the greater 14 Kuparuk area. Those sources are produced water from 15 current and future pools within the unit, seawater from 16 the Beaufort by the Oliktok Point seawater treatment 17 plant and an enriched gas blended from KRU lean gas and 18 indigenous or imported NGLs. Secondary fluids would be 19 those that are typically used at Kuparuk, frac fluids, 20 tracer survey fluids, fluids used to improve 21 injectivity, fluids used to improve conformance by 22 sealing intervals, freeze protect fluids and then the 23 standard oil field chemicals for corrosion and scale 24 inhibitors. 25 The sketch on the right at the top is a high AOGCC 12/13/2022 ITMO: CONOCOPHILLIPS AK Docket No. ERIO-22-002 329 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 level view of the fluid sources and the flowlines at 2 Kuparuk. The water comparability within the formation 3 is that analysis is underway. Initial sampling and 4 modeling indicate the potential for calcium carbonate 5 and barium sulfate to form in the producers. Coyote 6 wells will be included in the GKA scale and condition 7 program which includes regular produced water sample 8 and scheduled inhibition treatments. Complete 9 compatablity testing is planned as part of the core 10 analysis program previously mentioned. 11 Are there any questions on..... 12 COMMISSIONER CHMIELOWSKI: Did you say barium 13 sulfate scale? 14 MS. ALSHIRE: Yes. 15 COMMISSIONER CHMIELOWSKI: Is that very typical 16 in Kuparuk? 17 MS. ALSHIRE: It is when there's seawater 18 flood. 19 COMMISSIONER CHMIELOWSKI: Okay. 20 MS. ALSHIRE: So we intend to use produced 21 water so the risk is lower, but where there are 22 seawater patterns we see issues with..... 23 COMMISSIONER CHMIELOWSKI: Okay. 24 MS. ALSHIRE: Okay. 25 COMMISSIONER CHMIELOWSKI: And do you have an AOGCC 12/13/2022 ITMO: CONOCOPHILLIPS AK Docket No. ERIO-22-002 329 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 inhibition program for barium sulfate? 2 MS. ALSHIRE: Yes. It's in treating the 3 producers with squeezes..... 4 COMMISSIONER CHMIELOWSKI: Okay. 5 MS. ALSHIRE: .....to allow it -- the barium to 6 the surface rather than..... 7 COMMISSIONER CHMIELOWSKI: Right. That's a 8 trickier one. Yeah. 9 MS. ALSHIRE. Indeed. Yes. 10 COMMISSIONER CHMIELOWSKI: Yeah. 11 MS. ALSHIRE: Very much so. 12 COMMISSIONER CHMIELOWSKI: Thank you. 13 MS. ALSHIRE: Uh-huh. If there's no other 14 questions I will turn this over to Nathan I believe. 15 MR. SISEMORE: Hello. My name is Nathan 16 Sisemore, I'm the reservoir engineer for the Coyote 17 project. I request the Commission recognize me as an 18 expert in reservoir engineering. 19 COMMISSIONER CHMIELOWSKI: Okay. Please state 20 your credentials. 21 MR. SISEMORE: I received a bachelor's of 22 science in petroleum engineering from the University of 23 Houston. I have nine years of oil and gas experience 24 primarily in mature asset development. The last four 25 years have been spent with COP Alaska working in field AOGCC 12/13/2022 ITMO: CONOCOPHILLIPS AK Docket No. ERIO-22-002 329 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 development in the greater Kuparuk area. 2 COMMISSIONER CHMIELOWSKI: I have no 3 objections. 4 COMMISSIONER WILSON: No objections. 5 NATHAN SISEMORE 6 having been previously sworn under oath, called as a 7 witness on behalf of ConocoPhillips, stated as follows: 8 MR. SISEMORE: Nathan Sisemore presenting slide 9 13 on rock strength and injection pressure. As 10 previously stated the 3S24B is a vertical penetration 11 that was perforated and stimulated in the application 12 area of interest. To the left on the log suite we have 13 a suite for the 3S24B. From left to right we have 14 gamma ray log in the first track, shaded by a shale 15 percentage. Tracks two and three are total vertical 16 depth subsea and measured depth respectively. The 17 black bars in track four represent the top and the base 18 of the Coyote formation and the black bars in track 19 five represent the Coyote perforations. Track six 20 displays open hole deresistivity (ph) and track seven 21 displays neutron porosity and density logs. Track 22 eight has compressional and sheer sonic curves and 23 track 9 shows fracture gradient curves in both PSI per 24 foot and pounds per gallon. 25 A fracture gradient of 0.62 PSI per foot was AOGCC 12/13/2022 ITMO: CONOCOPHILLIPS AK Docket No. ERIO-22-002 329 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 captured while hydraulically fracturing 3S24B. This 2 data point which is represented as a red dot on the 3 right most log was used as a calibration point to 4 estimate the fracture gradient for the overlying CD 5 formation which is estimated to be 0.65 PSI per foot. 6 We will continue to refine this estimate early next 7 year by conducting a diagnostic fracture injection test 8 or DFIT on the CD formation in the 3S24B. We will also 9 perform geomechanical testing of the core from the 10 upper confining interval in the 3S701 hole core. We 11 plan to limit injection to 0.61 PSI per foot to stay 12 below the Coyote and CD gradients and keep injection 13 confined to the Coyote reservoir. At 4,109 feet subsea 14 this equates to roughly 165 PSI difference between our 15 target injection pressure and the overlying confining 16 fracture pressure. 17 Do you have any questions on this slide? If 18 not I'll hand it back to Pat to talk about fluid 19 quality. 20 COMMISSIONER WILSON: Did you say it was 100 21 and what PSI difference? 22 MR. SISEMORE: 165. 23 COMMISSIONER CHMIELOWSKI: And you're able to 24 maintain that pretty reliably with your injection 25 monitoring? AOGCC 12/13/2022 ITMO: CONOCOPHILLIPS AK Docket No. ERIO-22-002 329 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 MR. SISEMORE: We are. 2 COMMISSIONER CHMIELOWSKI: Okay. Thanks. 3 MR. SISEMORE: Now we'll go to Pat to talk 4 about water quality, formation water quality. 5 MR. PERFETTA: Okay. This is Pat Perfetta, I'm 6 on slide 14. As Nathan mentioned I'll now cover 7 quality information water, the aquifer exemption 8 reference and potential for shall freshwater. 9 Okay. Moving to slide 15. During the 10 production periods of the 3S24B sustained watercut of 11 approximately 10 to 11 percent was produced in that 12 well. A sample of that water was collected and 13 analyzed at the Kuparuk lab. Results of that analysis 14 from a sample collected on January 28th, 2022 are 15 included in the table on the right-hand side of the 16 slide. Total dissolved solids of the Coyote interval 17 are in excess of 21,000 milligrams per liter. This 18 exceeds the 10,000 milligrams per liter cutoff for 19 freshwater. 20 Okay. Moving to slide 16. This slide covers 21 the aquifer exemption granted to the Kuparuk River 22 unit. In 1984 the Environmental Protection Agency as 23 per the Code of Federal Regulations, section 147.102 24 related to aquifer exemptions exempted the area beneath 25 and within one-quarter mile of the Kuparuk River unit. AOGCC 12/13/2022 ITMO: CONOCOPHILLIPS AK Docket No. ERIO-22-002 329 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 AOGCC adopted this exemption by reference to 25.440(c) 2 of the Alaska Administrative Code in 1986. For 3 reference shown on the slides are three maps. The one 4 on the right has been shown previously in the 5 presentation, the two on the left are regional and 6 zoomed in view of the current Kuparuk River unit shown 7 in the reddish color. The black lines on these maps 8 show the extent of the Kuparuk River unit in 1984 when 9 the EPA aquifer exemption was put into place. 10 Also included on these maps is the location of 11 the proposed Coyote injection pilot. As previously 12 mentioned ConocoPhillips plans to expand the Kuparuk 13 River unit to include lease 392374. This lease was 14 previously inside the Kuparuk River unit when the 15 aquifer exemption was granted. That being the case the 16 area of the planned injection pilot is currently, was 17 or is planned to be within the Kuparuk River unit 18 boundary. 19 COMMISSIONER CHMIELOWSKI: So all wells are 20 within the aquifer exemption regardless of the lease 21 status..... 22 MR. PERFETTA: That's..... 23 COMMISSIONER CHMIELOWSKI: .....currently? 24 MR. PERFETTA: .....that's correct. 25 COMMISSIONER CHMIELOWSKI: Okay. AOGCC 12/13/2022 ITMO: CONOCOPHILLIPS AK Docket No. ERIO-22-002 329 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 COMMISSIONER WILSON: The reasoning seems 2 straightforward and logical, but I was just curious did 3 you seek an opinion from the EPA on the in and out 4 lease? 5 MR. PERFETTA: No, we have not seeked an 6 opinion. 7 COMMISSIONER WILSON: Okay. 8 MR. PERFETTA: Moving on to slide 17. Aside 9 from the aquifer exemption mentioned on the previous 10 slide this covers the topic of potential existence of 11 freshwater within the 3S area. The log display on the 12 right is from the Palm 1 well. The interval shown is 13 where the well intersects the base of permafrost in the 14 3S area. The Ugnu sands lie near the base of the 15 permafrost in this area. The log display has gamma ray 16 on the left and resistivity on the right. For 17 background purposes resistivity in clean sands greater 18 than or equal to approximately 100 ohmmeters, are a 19 (indiscernible) approximation for the base of 20 permafrost. As can be seen on the log display there's 21 a transitional zone in the base of the Ugnu sand 22 section where resistivity is approached 100 ohmmeters 23 in the depth interval from approximately 1,610 feet 24 measured depth to 1,905 feet measured depth. There are 25 two potential interpretations for this interval, one AOGCC 12/13/2022 ITMO: CONOCOPHILLIPS AK Docket No. ERIO-22-002 329 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 it's a transitional package with a mixture of ice and 2 water or two, it's a zone of porous freshwater bearing 3 sand. If the zone is freshwater bearing it would have 4 a calculated salinity of approximately 2,000 parts per 5 million. It should be noted that this zone is in 6 excess of 2,000 feet TVD above the Coyote interval and 7 is cemented behind surface casing in all wells in the 8 area. The location of the surface casing set depth in 9 the Palm 1 is displayed in the log just below 2,500 10 feet subsea TVD. 11 COMMISSIONER CHMIELOWSKI: So to restate for 12 the record all potential sources of fresh groundwater 13 will be behind case cement -- case -- cemented casing? 14 MR. PERFETTA: Yes, that is correct. 15 COMMISSIONER CHMIELOWSKI: Thank you. 16 MR. PERFETTA: Slide 18. I'll turn it over to 17 Nathan Sisemore again. 18 MR. SISEMORE: This is slide 19 on incremental 19 hydrocarbon recovery. To the upper left we have a 20 contour map of the net pay within the upper 200 feet of 21 the Coyote reservoir. The pattern of interest is 22 highlighted in green with a producer centered pattern 23 surrounded by two planned injectors. Reservoir 24 modeling estimates the stock tank oil in place for this 25 region to be between 30.7 and 32.2 million stock tank AOGCC 12/13/2022 ITMO: CONOCOPHILLIPS AK Docket No. ERIO-22-002 329 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 barrels. 2 The upper right-hand plat represents a 3 simulation based cumulative oil production with three 4 recovery types covered in this application. Simulation 5 estimates 5 to 10 percent potential recovery for 6 primary depletion or gas expansion drive, 20 to 30 7 percent potential recovery for waterflood and an 8 addition 1 to 5 percent for enriched gas injection 9 recovery. 10 COMMISSIONER CHMIELOWSKI: Do you plan to start 11 WAG injection at the beginning or are you going to do 12 some water injection for the well first? 13 MR. SISEMORE: We'll be doing water injection 14 for the well first. 15 COMMISSIONER CHMIELOWSKI: Okay. 16 MR. SISEMORE: Any other questions on this 17 slide? 18 COMMISSIONER WILSON: None. 19 MR. SISEMORE: I'll hand it over to Mike 20 Callahan to talk about the drilling. 21 MR. CALLAHAN: Good morning. I'm Mike 22 Callahan, I'm the drilling engineer for the Coyote 23 project with ConocoPhillips. I'd like to be recognized 24 by the Commission as an expert in drilling engineering. 25 COMMISSIONER CHMIELOWSKI: Okay. Please state AOGCC 12/13/2022 ITMO: CONOCOPHILLIPS AK Docket No. ERIO-22-002 329 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 your credentials. 2 MR. CALLAHAN: I have a bachelor of science 3 degree from the University of Texas in petroleum 4 engineering. I've been in the industry for 5 approximately 12 years all with ConocoPhillips, seven 6 of which have come in Alaska working projects all the 7 way from exploration through appraisal and development. 8 I also spent five years between the lower 48 working 9 primarily in the Permian and a year in Norway. 10 COMMISSIONER CHMIELOWSKI: I've no objections. 11 COMMISSIONER WILSON: No objections. 12 COMMISSIONER CHMIELOWSKI: Could you please 13 state your last name again? 14 MR. CALLAHAN: Callahan. 15 COMMISSIONER CHMIELOWSKI: Callahan. Great. 16 Thanks. 17 MIKE CALLAHAN 18 previously sworn under oath, called as a witness on 19 behalf of ConocoPhillips, stated as follows: 20 MR. CALLAHAN: All right. I'll be talking here 21 slide 21. This shows a schematic of our planned 22 injection well. Starting from the top we'll be 23 drilling a 13 and a half inch surface hole and running 24 10 and three-quarter inch surface casing that will be 25 set below the base of the West Sak formation. And that AOGCC 12/13/2022 ITMO: CONOCOPHILLIPS AK Docket No. ERIO-22-002 329 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 casing will be cemented to surface. We will then drill 2 out of that with a nine and seven-eights inch 3 intermediate hole and run seven and five-eights 4 intermediate casing. That casing will be set within 5 the Coyote reservoir and cemented to a minimum of 500 6 feet MD or 250 feet TVD above the top of that Coyote 7 interval, whichever is greater. We then plan to drill 8 a six and a half inch lateral for about 8,000 feet 9 within the Coyote reservoir and run a four and a half 10 inch liner completed with swell packers and frac 11 sleeves. That liner top will be set within 20 feet MD 12 of the intermediate casing shoe. 13 Are there any questions on our proposed well 14 design? 15 COMMISSIONER WILSON: I have a question. This 16 may be more for Pat though. Just could you comment on 17 the presence or absence of any Tuluvak sands and the 18 present -- the fluids associated with it? 19 MR. CALLAHAN: Within the Coyote overburden 20 between the surface casing set point and the top of the 21 Coyote there really are -- there's one thin Campanian 22 sand. Other than that it's predominantly a silty 23 section. And the Campanian sand that's present isn't 24 known to have hydrocarbons in this area. 25 COMMISSIONER WILSON: Okay. Thank you. AOGCC 12/13/2022 ITMO: CONOCOPHILLIPS AK Docket No. ERIO-22-002 329 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 MR. CALLAHAN: Uh-huh. Okay. If there's no 2 further questions we'll move on to the next slide, 3 slide 22. So this slide is just referencing the wells 4 that we have within one-quarter mile of the proposed 5 injection area. As you can see on the table on the 6 left we have three wells that fall within this area. 7 Shown on the map on the right there I'll start with the 8 3S03. So that is an active Kuparuk producer. You can 9 see there where the Coyote penetration marked with the 10 top and bottom by the red and blue stars there to the 11 northeast of our planned pattern. That well is 12 currently on active production with no known mechanical 13 issues. The Coyote interval is uncemented in that well 14 and our plan is to monitor that annulus during fracture 15 operations. 16 Moving on to the 3S21. That is a Kuparuk 17 injector. This slide is actually a couple weeks old. 18 The abandonment on that well was recently completed and 19 the Coyote interval was cemented as part of that 20 abandonment. 21 And then finally the 3S24B is the Coyote 22 producer that we have referenced previously in the 23 presentation. That's an active producer currently. As 24 part of that sidetrack we did cement across the Coyote 25 and within the intermediate casing so the Coyote is AOGCC 12/13/2022 ITMO: CONOCOPHILLIPS AK Docket No. ERIO-22-002 329 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 cemented there as well. The plan is to use that well 2 for monitoring for the near term and it will be P&A'd 3 shortly after beginning injection on the proposed well 4 pair. 5 COMMISSIONER CHMIELOWSKI: Which well are you 6 using for monitoring going forward after you plug and 7 abandon this one, are you drilling a new well for that 8 purpose? 9 MR. CALLAHAN: There will be no new well..... 10 COMMISSIONER CHMIELOWSKI: Okay. 11 MR. CALLAHAN: .....drilled for monitoring. We 12 do have ongoing annulus monitoring across the 3S pad. 13 COMMISSIONER CHMIELOWSKI: Okay. 14 MR. CALLAHAN: So we do have a way to monitor 15 pressures on any offset wells. 16 COMMISSIONER CHMIELOWSKI: Okay. 17 MR. CALLAHAN: And if there's no more questions 18 I think I'll hand off to my colleague, Dustin Morrow. 19 MR. MORROW: Good morning. My name is Dustin 20 Morrow, I'm the completion engineer for the Coyote 21 project. I'd like to be recognized as an expert 22 witness in completions. 23 COMMISSIONER CHMIELOWSKI: Okay. I think you 24 know the routine. 25 MR. MORROW: I'll try not to forget it. So I AOGCC 12/13/2022 ITMO: CONOCOPHILLIPS AK Docket No. ERIO-22-002 329 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 went to New Mexico State University, I received and 2 bachelor's and master's in mechanical engineering. 3 From there I went -- worked for El Paso Natural Gas for 4 three years as a pipeline engineer. I've been with 5 ConocoPhillips for 14 years, five as production 6 engineer and intervention engineer and then the 7 remaining nine in completions from unconventional to 8 conventional assets. I've been in Alaska working 9 projects for a total of three years. 10 COMMISSIONER CHMIELOWSKI: I've no objections. 11 COMMISSIONER WILSON: No objections. 12 DUSTIN MORROW 13 previously sworn under oath, called as a witness on 14 behalf of ConocoPhillips, stated as follows: 15 MR. MORROW: Thank you. So I'm going to talk a 16 little bit about our planned fracture stimulation work 17 for this injector. A lot of the data here is from the 18 3S24B. On the left is a model built from logging on 19 the 3S24B. From there -- from that we built a geo 20 model and modeled our frac job. So what I'm showing on 21 the left is our depths and those pink hash marks those 22 are some high Young's modulus layers that we found in 23 this log, but we do not expect them to be continuous 24 and so therefore they were left off the geo model. We 25 didn't want it to show up as a barrier which they -- we AOGCC 12/13/2022 ITMO: CONOCOPHILLIPS AK Docket No. ERIO-22-002 329 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 believe they are not. 2 So we fracture stimulated the 3S24B with 3 300,000 pounds of proppant. On the right is a geo 4 model and a history match with that job. And we found 5 a half link (ph) at about 270 feet, high pros (ph) of 6 160 feet. Based on these modeling and history matching 7 we've lowered our lateral placement as shown on the 8 left about 100 feet deeper and we placed the 9 perforation as 24B. And we're also -- I'm sorry, a 10 hundred feet below the top of Coyote. So our planned 11 job for this well is 300 pounds of 16/20 proppant in 12 place of the crosslink (ph) gel system. And our frac 13 sleeves will be at a spacing of 500 feet. 14 COMMISSIONER CHMIELOWSKI: And so you're 15 planning what, somewhere around 15 stage fracs, 16 something like that? 17 MR. MORROW: We're going to have 15 sleeves and 18 a tow stage so there'll be a total of 16 stages, total 19 proppant of 4.8 million pounds. 20 COMMISSIONER CHMIELOWSKI: And how many stages 21 did you have in 24B, was it just a single? 22 MR. MORROW: A single vertical. 23 COMMISSIONER CHMIELOWSKI: Yeah. Okay. 24 MR. MORROW: Single vertical. 25 COMMISSIONER CHMIELOWSKI: Yeah. And you're AOGCC 12/13/2022 ITMO: CONOCOPHILLIPS AK Docket No. ERIO-22-002 329 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 going to frac the injector too? 2 MR. MORROW: Correct. 3 COMMISSIONER CHMIELOWSKI: Right. Okay. And 4 similar design for that one, frac design? 5 MR. MORROW: The producer and injector will be 6 the same design. 7 COMMISSIONER CHMIELOWSKI: Okay. 8 MR. MORROW: Correct. Yeah, so the 3S704 will 9 be cemented. The injector will have swell packer. Our 10 planned producer is -- will be cemented and that will 11 be a test to determine if that's needed due to 12 potential proppant flowback. So we'll be comparing the 13 two wells. 14 COMMISSIONER CHMIELOWSKI: All right. 15 MR. MORROW: Any questions? 16 COMMISSIONER WILSON: I'm good. 17 COMMISSIONER CHMIELOWSKI: You mentioned you'll 18 start drilling relatively soon and I realize this 19 hearing has been postponed several times. So do you 20 have like an update on when you're going to get the rig 21 out there? 22 MR. MORROW: Yeah, so the rig should be moving 23 onto the 3S701 this weekend..... 24 COMMISSIONER CHMIELOWSKI: This weekend. 25 MR. MORROW: .....or later in the week. Yeah. AOGCC 12/13/2022 ITMO: CONOCOPHILLIPS AK Docket No. ERIO-22-002 329 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: Great. So I see you 2 have one more slide. Is there a summary slide then. 3 Okay. Move on to that. 4 MR. MORROW: Yeah, that's correct. 5 COMMISSIONER CHMIELOWSKI: Okay. 6 MR. PERFETTA: Okay. Slide 24 we're 7 transitioning just to the final thoughts and summary 8 and then moving to slide 25. And this is Patrick 9 Perfetta again. 10 So in closing ConocoPhillips Alaska requests 11 approval for a pilot enhanced recovery injection order 12 for a period of three years for the Coyote interval. 13 The area is located at 3S pad in the western portion of 14 the Kuparuk River unit and the adjacent lease as 15 previously stated. The request covers fluids outlined 16 in this presentation and that are contained within the 17 application. This time period will give ample time to 18 understand injectivity into the Coyote, collect and 19 analyze additional data and potentially drill a follow- 20 up injector to complete the previously mentioned fully 21 supported producer centered pattern. 22 And we'd like to thank the Commissioners and 23 AOGCC Staff for their time and effort concerning this 24 matter and we're happy to take any additional questions 25 that you might have at this time. AOGCC 12/13/2022 ITMO: CONOCOPHILLIPS AK Docket No. ERIO-22-002 329 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 COMMISSIONER CHMIELOWSKI: Great. That was an 2 excellent presentation. Thank you very much. 3 MR. PERFETTA: Thank you. 4 COMMISSIONER CHMIELOWSKI: Do you have any 5 questions or should we take a brief recess? 6 COMMISSIONER WILSON: Let's take a brief 7 recess. Yeah, I'll second that that was an excellent 8 presentation. 9 COMMISSIONER CHMIELOWSKI: All right. Let's 10 see. The time is 11:11 so we will -- let's plan to 11 come back at 11:25 and we'll wrap it up. 12 MR. PERFETTA: Great. Thank you. 13 COMMISSIONER CHMIELOWSKI: All right. See you 14 at 11:25. 15 (Off record) 16 (On record) 17 COMMISSIONER CHMIELOWSKI: All right. Thanks 18 for bearing with us. We're back on the record, the 19 time is 11:29 a.m. 20 First of all could you talk a little bit about 21 what injection rates you plan, water and MI? And then 22 please restate your name as you talk. 23 Thank you. 24 MR. SISEMORE: Thank you. My name is Nathan 25 Sisemore. We're looking to inject up to 15,000 barrels AOGCC 12/13/2022 ITMO: CONOCOPHILLIPS AK Docket No. ERIO-22-002 329 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 a day. We left ourselves kind of a wide berth since we 2 don't have any horizontal penetrations in the ground we 3 are trying to keep a voidage (ph) replacement of one 4 and so we gave ourselves enough room to cover that 5 depending on what the producer comes on at. 6 COMMISSIONER CHMIELOWSKI: Okay. And you 7 talked about, you know, a pressure differential of 8 about 165 PSI between the injection pressure downhole 9 and the frac pressure for the overburden, right. So 10 how do you ensure that you stay in the -- you know, 11 within that range, what if you had a couple hundred 12 pound injection pressure swing, like what is your 13 system for keeping this in line, it's kind of a tight 14 margin? 15 MR. SISEMORE: Sure. Sure. So we have 16 instrumentation out in the field, automatic chokes that 17 are set to a do not exceed pressure and so they will 18 activate when we start getting close to that 0.61 PSI 19 per foot gradient as well as monitoring with our board 20 operators. And so if we are consistently saying that 21 we're hitting that amount and we're having to choke 22 back, they will see that on the board and if we have an 23 event that starts to go above that we've left ourselves 24 about 165 PSI difference to react and the board would 25 send an operator out to the field. AOGCC 12/13/2022 ITMO: CONOCOPHILLIPS AK Docket No. ERIO-22-002 329 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 COMMISSIONER CHMIELOWSKI: And so this 2 automatic choke is just on this one injector, right, or 3 do you have them across all injectors? 4 MR. SISEMORE: We have them across injectors 5 and we do -- this is -- we do have additional wells, 6 not in Coyote, but across the field that have these 7 DNE, do not exceed limitation. So this is somewhat of 8 a common practice for us. 9 COMMISSIONER CHMIELOWSKI: Okay. And you've 10 been able -- Conoco's been able to maintain those 11 pressure limits without going over to -- at all or..... 12 MR. SISEMORE: I don't have..... 13 COMMISSIONER CHMIELOWSKI: Okay. 14 MR. SISEMORE: .....that information. 15 COMMISSIONER CHMIELOWSKI: Right. 16 MS. ALSHIRE: This is Lynn Alshire. We'll have 17 a series of alarms set off for -- and set up depending 18 on the sand face pressures that we desire and at that 19 drop dead the surface safety valve will close and shut 20 off injection. 21 COMMISSIONER CHMIELOWSKI: Okay. And the drop 22 dead is what, the 165 difference? 23 MS. ALSHIRE: We'll probably set that a little 24 bit more than that to -- the hard part is we don't know 25 -- understand injectivity yet..... AOGCC 12/13/2022 ITMO: CONOCOPHILLIPS AK Docket No. ERIO-22-002 329 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: Uh-huh. 2 MS. ALSHIRE: .....so it won't -- we'll -- once 3 we understand injectivity we'll decide how close we 4 want to ride that 165 PSI. 5 COMMISSIONER CHMIELOWSKI: Okay. So the 6 surface safety will close and is that -- that will 7 happen automatically? 8 MS. ALSHIRE: Yes. 9 COMMISSIONER CHMIELOWSKI: Yeah. Okay. 10 MS. ALSHIRE: But we have two alarms ahead of 11 that that will..... 12 COMMISSIONER CHMIELOWSKI: Right. 13 MS. ALSHIRE:.....allow the operators and the 14 PEs to react. 15 COMMISSIONER CHMIELOWSKI: Great. Thank you. 16 MS. ALSHIRE: You're welcome. 17 COMMISSIONER CHMIELOWSKI: And I want to talk a 18 little bit about the offset well 3S03. So it has an 19 annulus that's not cemented across the Coyote and you 20 mentioned only monitoring that well during the frac. 21 Why is Conoco not cementing that well like other wells 22 on the pad, hasn't there been a campaign on 3S pad to 23 perf and wash and cement across the Coyote? 24 MS. ALSHIRE: This is Lynn Alshire again. The 25 perf washes have been a part of the P&A process..... AOGCC 12/13/2022 ITMO: CONOCOPHILLIPS AK Docket No. ERIO-22-002 329 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 COMMISSIONER CHMIELOWSKI: Uh-huh. 2 MS. ALSHIRE: .....so it requires tubing to 3 become pulled and..... 4 COMMISSIONER CHMIELOWSKI: Okay. 5 MS. ALSHIRE: .....laid down. So for 3S03 we 6 will be monitoring the OA, the OAs are always monitored 7 so it's not just during the frac. It'll be different 8 information we're looking for during the frac, but the 9 OAs are already monitored. And if -- eventually we 10 will P&A 303 and it will be perf washed and cemented to 11 surface. 12 COMMISSIONER CHMIELOWSKI: So cemented after 13 the pilot that you're talking about or you mean just 14 eventually at end of field life? 15 MS. ALSHIRE: End of well life actually. 16 COMMISSIONER CHMIELOWSKI: End of well life, 17 yeah. 18 MS. ALSHIRE: So we're recovering slots as the 19 development for Moraine and Coyote progress we will 20 recover slots from the Kuparuk wells. 21 COMMISSIONER CHMIELOWSKI: Okay. So you're 22 monitoring the annulus and can you talk a little bit 23 about the monitoring program that how often is the data 24 received and reviewed? 25 MS. ALSHIRE: Daily. Some -- actually I think AOGCC 12/13/2022 ITMO: CONOCOPHILLIPS AK Docket No. ERIO-22-002 329 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 every shift, they go out and they read the gauges and 2 then it's also in the scata screening, we can -- the 3 PEs can see it also. 4 COMMISSIONER CHMIELOWSKI: Okay. So how will 5 Conoco ensure that fluids are not escaping out of zone, 6 you know, going into this Coyote interval and 3S03? 7 MS. ALSHIRE: So for 3S03 as soon as we see any 8 abnormal injection or any abnormal pressure we will 9 shut the well in immediately. 10 COMMISSIONER CHMIELOWSKI: Okay. Any other 11 questions, Commissioner Wilson? 12 COMMISSIONER WILSON: No, none from me. 13 COMMISSIONER CHMIELOWSKI: Just checking with 14 Staff. Any reason to convene again? 15 (No comments) 16 COMMISSIONER CHMIELOWSKI: Seeing no. Okay. 17 Great. We did receive a question through Teams and we 18 decided it wasn't germane to the hearing so we're not 19 going to ask that. Let's see. I guess I will ask -- 20 offer to any member of the public the opportunity to 21 testify or provide comments. I'm going to give kind of 22 a lengthy pause here to give people a chance to comment 23 Samantha or speak up on the Teams or communicate via 24 chat and let us know if there's anyone who wishes to 25 testify. I'm going to wait a full minute on that. AOGCC 12/13/2022 ITMO: CONOCOPHILLIPS AK Docket No. ERIO-22-002 329 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 (No comments) 2 COMMISSIONER CHMIELOWSKI: Okay. We're at a 3 minute just because it does take folks a while to get 4 through with the new technology. 5 Samantha, have you heard from anyone who wishes 6 to testify? 7 MS. CARLISLE: I have not. 8 COMMISSIONER CHMIELOWSKI: Okay. Any other 9 comments, Commissioner Wilson? 10 COMMISSIONER WILSON: No, none from me. 11 COMMISSIONER CHMIELOWSKI: Okay. So hearing no 12 other business the time is 11:36 a.m. and this hearing 13 is now adjourned. 14 (Hearing adjourned - 11:36 a.m.) 15 (END OF PROCEEDINGS) 16 17 18 19 20 21 22 23 24 25 AOGCC 12/13/2022 ITMO: CONOCOPHILLIPS AK Docket No. ERIO-22-002 329 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 TRANSCRIBER'S CERTIFICATE 2 I, Salena A. Hile, hereby certify that the 3 foregoing pages numbered 02 through 42 are a true, 4 accurate, and complete transcript of proceedings in 5 Docket No.: ERIO-22-002, transcribed under my direction 6 from a copy of an electronic sound recording to the 7 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 Coyote Pilot enhanced oil recovery project AOGCC Hearing December 13, 2022 Acronyms 2 •AAC: Alaska Administrative Code •ADL: Alaska Division of Lands •AOGCC: Alaska Oil and Gas Conservation Commission •CPAI: ConocoPhillips Alaska, Inc. •CFR: Code of Federal Regulations •CPF: Central Processing Facility •DFIT: Diagnostic Fracture Injection Test •EPA: Environmental Protection Agency •EWAG: Enriched Water Alternating Gas •KRU: Kuparuk River Unit •md: Millidarcy •mg/l: Milligrams per Liter •MI: Miscible Injectant •MMSTB: Million Stock Tank Barrels •P&A: Plug and Abandon •PPG: Pounds Per Gallon •PSI: Pounds Per Square Inch •PW: Produced Water •STOOIP: Stock Tank Original Oil In Place •SW: Sea Water •TVD: True Vertical Depth •TVDSS/SSTVD: True Vertical Depth Subsea •YM: Young’s Modulus Agenda Objective: To supply the AOGCC with the information necessary to approve CPAI’s Coyote Enhanced Recovery Injection Order application. Presentation Outline: •Project Introduction (Patrick Perfetta) •Land Overview (Patrick Perfetta) •Geoscience Overview (Patrick Perfetta & Ethan Castongia) •Injection Analysis (Lynn Aleshire & Nathan Sisemore) •Formation Water Quality (Patrick Perfetta) •Reservoir Engineering (Nathan Sisemore) •Drilling & Wells Overview (Mike Callahan & Dustin Morrow) •Project Summary (Patrick Perfetta) 3 Project Introduction -Description of proposed operation 4 Project Location & Overview •History •3S-24B Coyote Interval exploration test (2021-2022) •P&A and side-track of 3S-24A Kuparuk producer •Fracture stimulated -> flow test -> long-term production •Proved productivity of interval on CPAI acreage •Request for approval for pilot injection •Location: Drillsite 3S, KRU & adjacent lease •Interval of interest: Coyote Reservoir •Duration: Three years •Request allows time for planned data collection program, observation of injection/withdrawal, and integration of results into Pool Rules & Area Injection Order proposal •Planned activities •Initial drilling: late Q4 2022 -> Q12023 •Horizontal multi-stage fracture stimulated producer/injector •Pilot-hole for dedicated data collection •Overburden data collection in existing 3S-24B prior to P&A •Studies 5 Planned horizontal injector Planned horizontal producer Possible future horizontal injector Kuparuk River Unit Location of Proposed Coyote Injection Pilot 1 Mile 3S Pad Area Map with Well Spider Land Overview -Plat of wells penetrating injection zone -Operators and surface owners within ¼ mile of injection operations 6 Land Plat with Planned Wells 7 Geoscience Overview -Description and depth interval -Description of the formation 8 Coyote Interval Geologic Overview •Stratigraphy •Nanushuk, west to east progradational topset reservoir •Elongate northeast to southwest depositional system, parallel to paleo-shelf margin •Average sand porosity: 23-24%, permeability: 10-20 md •Confining intervals •Upper: Distal toe of slope Seabee clay/siltstones, ~350’ thick •Lower: Distal toe of slope Torok mudstones, ~300’ thick •Structure/Trap •Predominantly stratigraphic trap with small low relief dip closures •Limited faulting -> Small northwest-southeast trending fault to northeast of planned horizontal producer 9 Top Coyote 4,270’ MD Base Coyote 5,115’ MD NanushukTorokSeabeeKuparuk River: Torok Oil Pool Lower Confining Zone Upper Confining Zone Coyote Gross Reservoir Interval Palm 1 Top Coyote Depth Structure Area of detail Contour interval 50’*Top Coyote penetration Formation Schematic Seismic Lines 10 Injection Analysis -Injection fluid analysis and injection rates -Estimated average and maximum injection pressures 11 Injection Fluid Analysis Primary Injection Fluids •Produced water and gas from all present and yet-to-be defined oil pools within the KRU •Beaufort seawater sourced from the Kuparuk seawater treatment plant •Enriched hydrocarbon gas (MI): Blend of KRU lean gas with indigenous and/or imported natural gas liquids Secondary Injection Fluids •Fluids used during hydraulic fracture stimulation •Tracer survey fluids to monitor reservoir performance •Fluids used to improve near wellbore injectivity (acids, solvents, etc.) •Fluids used to seal wellbore intervals which negatively impact recovery (cement, resin, etc.) •Fluids associated with freeze protection (diesel, crude, glycol, methanol, etc.) •Standard oilfield chemicals (corrosion inhibitor, scale inhibitor, etc.) 12 Water Compatibility •Modeling indicates potential for CaCO3 and BaSO4 formation in the wellbore •Coyote wells will be included in the GKA scale inhibition program which includes regular PW sampling and scheduled inhibition treatments •Compatibility testing is planned as part of core analysis program. Coyote Injection Pressure Rock Strength •3S-24B log display •Right-most track contains calibrated minimum horizontal stress (closure pressure) curves in mudweight (PPG), and gradient (psi/ft) •Coyote fracture gradient (0.62 psi/ft) based on 3S-24B fracture stimulation data •Overlying Seabee fracture gradient (0.65 psi/ft) based on rock strength curves calibrated to 3S-24B Coyote fracture stimulation data •Further planned data collection for continued rock strength calibration •Diagnostic fracture injection test (DFIT) in upper confining interval (Q2 2023) •Geomechanical testing of whole core (Q1 2023) Injection •Target injection pressure will be based on 0.61 psi/ft •Will not exceed fracture gradient of the Coyote Sands (0.62 psi/ft) and overlying confining shales (0.65 psi/ft) 13 3S-24B Closure pressure:0.62 psi/ft (2506 psi @ 4109 SSTVD) Depth:4,165 TVD (4,109 SSTVD) Formation Water Quality -Quality of formation water -Aquifer exemption reference -Potential for freshwater 14 Coyote Interval Produced Water •Sustained ~10-11% water cut produced from 3S-24B long-term production •Total dissolved solids of produced water are in excess of 21,000 mg/l •Exceeds 10,00 mg/l cut-off for freshwater 15 Analysis Name Value Unit Aluminum - mg/l Boron 26.2 mg/l Barium 1.3 mg/l Bicarbonate 2,409.8 mg/l Calcium 99.4 mg/l Carbonate 13.0 mg/l Chloride 10,081.1 mg/l Conductivity 17,850.0 uS/cm Iron 0.1 mg/l Potassium 48.2 mg/l Lithium 2.2 mg/l Magnesium 91.7 mg/l Manganese 0.2 mg/l Sodium 8,246.5 mg/l Phosphorus 0.3 mg/l PH 8.3 Silicon 6.1 mg/l Sulfate 151.5 mg/l Specific Gravity @ 60 degrees F 1.0 Strontium 7.5 mg/l Zinc - mg/l 3S-24B Produced Water Sample: Coyote Formation Sample date: 1/28/22, analyses performed at Kupaurk Lab Aquifer Exemption Reference •EPA aquifer exemption •Area directly beneath, and within ¼ mile of the Kuparuk River Unit as per 40 C.F.R. 147.102(b)(3) •Enacted in 1984 •AOGCC adopted the above exemption in 1986 by reference 20 AAC 25.440(c) 16 Planned horizontal injector Planned horizontal producer Possible future horizontal injector Kuparuk River Unit Location of Proposed Coyote Injection Pilot 1 Mile 3S Pad Area Map with Well Spider Current KRU Boundary KRU Boundary 1984 Current KRU Boundary KRU Boundary 1984 Potential Freshwater Interval •Resistivity in clean sands of >= 100 ohmm is a good approximation of permafrost •Ugnu sand interval in area occurs near base of permafrost section •Zone from 1,610 –1,905’ MD in Lower Ugnu has resistivities approaching 100 ohmm •Two options for this zone •Likely transitional package with mix of ice and water •If zone is not ice bearing, it would have a calculated salinity of ~2,000 ppm •Zone is cemented behind surface casing on all wells in the area •In excess of 2,000’ TVD above interval 17 Palm 1 Log Display >= 100 ohmm Reservoir Engineering -In-place -Incremental hydrocarbon recovery 18 Incremental Hydrocarbon Recovery •STOOIP for injection area (upper 200’) –30.7-32.2 MMSTB •Recovery factors (simulation-based estimates) •Primary depletion: 5-10% •Waterflood recovery: 20-30% •Enriched gas (EWAG) recovery: 1-5% incremental 19 0 1,000,000 2,000,000 3,000,000 4,000,000 5,000,000 6,000,000 7,000,000 8,000,000 9,000,000 Primary Depletion Waterflood Enriched Gas Oil Production (BO)Time Coyote Net Pay 1 Mile Volumetric calculation area Cumulative Oil Production (by recovery type) Drilling & Completions -Mechanical integrity of injection wells -Logs of the injection wells -Mechanical condition of wells within ¼ mile of proposed area -Fracture modeling 20 Injection Well Schematic 21 Mechanical condition of wells within ¼ mile of proposed area 22 Well Well Type Status Mech Integrity Notes 3S-03 Kuparuk Producer Active No issues -Coyote currently uncemented -Well to be pressure monitored during Coyote fracture stimulation. 3S-21 Kuparuk Injector To be Abandoned No issues -Coyote currently uncemented -Coyote will be isolated with cement prior to fracture stimulation. 3S-24B Coyote Producer Active No Issues -Estimated top of cement >250 ft TVD above top Coyote -3S-24B Sidetrack drilled 2021 as Coyote exploration well. -Well to be P&A’d shortly after beginning injection in offset Coyote wells. *Top Coyote penetration point *Base Coyote penetrations point Well Location Map P&A’d well Fracture Stimulation Modeling 23 160 ft 270 ft Prop Con 0 –5 lb/ft2 0 1 2 3 4 5 300k lbm 16/20 ceramic Top Coyote 4093 ft TVD •High density / YM layers manually removed (as shown to the left ) •Planning lateral placement 100 ft below the top of Coyote, landing depth based on the 3S-24B post job stimulation modeling, and history matching ̶Moved lateral deeper than originally planned after post job analysis on 3S-24B •300k lbm of proppant planned with crosslinked gel to provide high fracture conductivity over the 500’ sleeve spacing Gas Cap Geo-model based on 3S-24B Lateral Placement Summary -General project summary, and final thoughts 24 Summary •Request for approval for a pilot enhanced recovery injection order •Duration: Three years •Interval of interest: Coyote •Location: Western KRU & adjacent lease •Fluids: As noted in application and this presentation 25 Planned horizontal injector Planned horizontal producer Possible future horizontal injector Kuparuk River Unit Location of Proposed Coyote Injection Pilot 1 Mile 3S Pad Area Map with Well Spider 4 Revised Notice Rescheduling Public Hearing STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION RE: Docket Number: ERIO-22-002 By application received August 11, 2022, ConocoPhillips Alaska, Inc. (CPAI) requested the Alaska Oil and Gas Conservation Commission (AOGCC) issue an order approving a pilot enhanced oil recovery (EOR) project for the Coyote Interval in the Kuparuk River Unit (KRU). Enhanced recovery regulations (20 AAC 25.402) are in place to ensure that EOR injection projects are conducted in a manner that will lead to increased ultimate recovery, prevent the injected fluids from escaping the injection interval, and protect sources of freshwater. Operators must apply for, and be granted, an order that authorizes EOR injection before they can commence injection operations. Part of the application process requires the operator to notify, and provide a copy of the application to, all operators and surface owners within a ¼-mile radius of the proposed injection well(s). For situations where the viability of a specific EOR process has not been demonstrated as being effective in a certain application, such as this proposal to conduct water injection for EOR purposes in the Coyote Interval, 20 AAC 25.450(b) allows the AOGCC to issue an injection order approving a pilot EOR injection project to allow for the gathering of information necessary to show whether or not it is viable before a full field project is pursued. Pilot project EOR orders are usually time limited and often require different data collection and reporting requirements than a conventional EOR injection order since the purpose of a pilot EOR injection project is to demonstrate feasibility of a process before pursuing it on a fieldwide basis. This notice does not contain all the information filed by CPAI.You may obtain more information about this filing by contacting the AOGCC’s Special Assistant, Samantha Carlisle, at (907) 793- 1223 or Samantha.Carlisle@alaska.gov. The AOGCC is rescheduling the public hearing on this matter from November 8, 2022 to November 29, 2022 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 no. 592 156 542#. Anyone who wishes to participate remotely using MS Teams video conference should contact Samantha Carlisle 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.carlisle@alaska.gov. Comments must be received no later than the conclusion of the November 29, 2022 hearing. Individuals or groups of people with disabilities who require special accommodations to comment or attend the hearing should contact Samantha Carlisle at (907) 793-1223, no later than November 21, 2022. Jessie L. Chmielowski Commissioner Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2022.10.26 16:23:37 -08'00' From:Carlisle, Samantha J (OGC) To:AOGCC_Public_Notices Subject:[AOGCC_Public_Notices] Rescheduled ERIO-22-002 Public Hearing Notice (CPAI) Date:Thursday, October 27, 2022 8:07:58 AM Attachments:Revised ERIO-22-002 Public Hearing Notice.pdf By application received August 11, 2022, ConocoPhillips Alaska, Inc. (CPAI) requested the Alaska Oil and Gas Conservation Commission (AOGCC) issue an order approving a pilot enhanced oil recovery (EOR) project for the Coyote Interval in the Kuparuk River Unit (KRU). Samantha Carlisle AOGCC Special Assistant Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage, AK 99501 (907) 793-1223 __________________________________ List Name: AOGCC_Public_Notices@list.state.ak.us You subscribed as: samantha.carlisle@alaska.gov Unsubscribe at: https://list.state.ak.us/mailman/options/aogcc_public_notices/samantha.carlisle%40alaska.gov Bernie Karl K&K Recycling Inc. P.O. Box 58055 Fairbanks, AK 99711 mailed 10/27/22 Adam Garrigus being first duly sworn on oath deposes and says that she is a representative of the Anchorage Daily News, a daily newspaper. That said newspaper has been approved by the Third Judicial Court, Anchorage, Alaska, and it now and has been published in the English language continually as a daily newspaper in Anchorage, Alaska, and it is now and during all said time was printed in an office maintained at the aforesaid place of publication of said news- paper. That the annexed is a copy of an adver- tisement as it was published in regular issues (and not in supplemental form) of said news- paper on AFFIDAVIT OF PUBLICATION ______________________________________ Notary Public in and for The State of Alaska. Third Division Anchorage, Alaska MY COMMISSION EXPIRES ______________________________________ 10/30/2022 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 this 31st day of October 2022. Account #: 100869 ST OF AK/AK OIL AND GAS CONSERVATION COMMISSION 333 W. 7TH AVE STE 100, ANCHORAGE, AK 99501 Order #: W0033890 Cost: $346.6 Revised Notice Rescheduling Public HearingSTATE OF ALASKAALASKA OIL AND GAS CONSERVATION COMMISSION RE: Docket Number: ERIO‑22‑002 By application received August 11, 2022, ConocoPhillips Alaska, Inc. (CPAI) requested the Alaska Oil and Gas Conservation Commission (AOGCC) issue an order approving a pilot enhanced oil recovery (EOR) project for the Coyote Interval in the Kuparuk River Unit (KRU). Enhanced recovery regulations (20 AAC 25.402) are in place to ensure that EOR injection projects are conducted in a manner that will lead to increased ultimate recovery, prevent the injected fluids from escaping the injection interval, and protect sources of freshwater. Operators must apply for, and be granted, an order that authorizes EOR injection before they can commence injection operations. Part of the application process requires the operator to notify, and provide a copy of the application to, all operators and surface owners within a ¼‑mile radius of the proposed injection well(s). For situations where the viability of a specific EOR process has not been demonstrated as being effective in a certain application, such as this proposal to conduct water injection for EOR purposes in the Coyote Interval, 20 AAC 25.450(b) allows the AOGCC to issue an injection order approving a pilot EOR injection project to allow for the gathering of information necessary to show whether or not it is viable before a full field project is pursued. Pilot project EOR orders are usually time limited and often require different data collection and reporting requirements than a conventional EOR injection order since the purpose of a pilot EOR injection project is to demonstrate feasibility of a process before pursuing it on a fieldwide basis. This notice does not contain all the information filed by CPAI. You may obtain more information about this filing by contacting the AOGCC’s Special Assistant, Samantha Carlisle, at (907) 793‑1223 or Samantha.Carlisle@alaska.gov. The AOGCC is rescheduling the public hearing on this matter from November 8, 2022 to November 29, 2022 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 no. 592 156 542#. Anyone who wishes to participate remotely using MS Teams video conference should contact Samantha Carlisle 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.carlisle@alaska.gov. Comments must be received no later than the conclusion of the November 29, 2022 hearing. Individuals or groups of people with disabilities who require special accommodations to comment or attend the hearing should contact Samantha Carlisle at (907) 793‑1223, no later than November 21, 2022. Jessie L. ChmielowskiCommissioner Pub: Oct. 30, 2022 STATE OF ALASKA THIRD JUDICIAL DISTRICT 2024-07-14 Document Ref: JOJBV-C6ZHM-RYLPK-S2QOW Page 4 of 50 3 From:Perfetta, Patrick J To:Carlisle, Samantha J (OGC); Roby, David S (OGC) Subject:RE: [EXTERNAL]RE: Conflict with October 6th Coyote pilot enhanced oil recovery project Date:Thursday, September 8, 2022 10:58:59 AM Samantha, Yes, the October 20th date will work for CPAI. Also, thanks for confirming that a representative need not be present for the October 6th date. Thank you for accommodating us. Best Regards, Pat Perfetta Principal Geologist | ConocoPhillips Alaska | O: 907-263-4531 | C: 713-446-5359 From: Carlisle, Samantha J (OGC) <samantha.carlisle@alaska.gov> Sent: Thursday, September 8, 2022 10:23 AM To: Perfetta, Patrick J <Patrick.J.Perfetta@conocophillips.com>; Roby, David S (OGC) <dave.roby@alaska.gov> Subject: [EXTERNAL]RE: Conflict with October 6th Coyote pilot enhanced oil recovery project CAUTION:This email originated from outside of the organization. Do not click links or open attachments unless you recognize the sender and know the content is safe. Patrick, Looking at our calendar, we can do October 20th at 10am. Please let me know if this works for CPAI. We will open the record on October 6th and just reschedule to October 20th, if that date works for CPAI. No one from CPAI needs to be in person for the October 6th hearing, unless someone wants to be. Thank you, Samantha Carlisle AOGCC Special Assistant Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage, AK 99501 (907) 793-1223 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: Perfetta, Patrick J <Patrick.J.Perfetta@conocophillips.com> Sent: Wednesday, September 7, 2022 1:33 PM To: Roby, David S (OGC) <dave.roby@alaska.gov>; Carlisle, Samantha J (OGC) <samantha.carlisle@alaska.gov> Cc: Perfetta, Patrick J <Patrick.J.Perfetta@conocophillips.com> Subject: Conflict with October 6th Coyote pilot enhanced oil recovery project Samantha/Dave, Following up with respect to the recently scheduled public hearing for the subject pilot injection project, for the Coyote interval, within the KRU. Unfortunately, two key members of the ConocoPhillips team responsible for this project are out of state during the time of the scheduled hearing. Would it be possible to accommodate an alternative date for this hearing? Our team is available anytime after the first week of October, with the exception of October 27th. Please let me know if you are able to help with this request. Best Regards, Patrick Perfetta Principal Geologist | ConocoPhillips Alaska | O: 907-263-4531 | C: 713-446-5359 2 Notice of Public Hearing STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION RE: Docket NXPEHUERIO-22-002 By application received August 11, 2022, ConocoPhillips Alaska, Inc.(CPAI) requested the Alaska Oil and Gas Conservation Commission (AOGCC) issue an order approving a pilot enhanced oil recovery (EOR) project for the Coyote Interval in the Kuparuk River Unit (KRU). Enhanced recovery regulations (20 AAC 25.402) are in place to ensure that EOR injection projects are conducted in a manner that will lead to increased ultimate recovery, prevent the injected fluids from escaping the injection interval, and protect sources of freshwater. Operators must apply for, and be granted, an order that authorizes EOR injection before they can commence injection operations. Part of the application process requires the operator to notify, and provide a copy of the application to, all operators and surface owners within a ¼-mile radius of the proposed injection well(s). For situations where the viability of a specific EOR process has not been demonstrated as being effective in a certain application, such as this proposal to conduct water injection for EOR purposes in the Coyote Interval, 20 AAC 25.450(b) allows the AOGCC to issue an injection order approving a pilot EOR injection project to allow for the gathering the information necessary to show whether or not it is viable before a full field project is pursued. Pilot project EOR orders are usually time limited and often require different data collection and reporting requirements than a conventional EOR injection order since the purpose of a pilot EOR injection project is to demonstrate feasibility of a process before pursuing it on a fieldwide basis. This notice does not contain all the information filed by CPAI.You may obtain more information about this filing by contacting the AOGCC’s Special Assistant, Samantha Carlisle, at (907) 793- 1223 or Samantha.Carlisle@alaska.gov. The AOGCC has scheduled a public hearing on this matter for October 6, 2022 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 no. 592 156 542#. Anyone who wishes to participate remotely using MS Teams video conference should contact Samantha Carlisle 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.carlisle@alaska.gov. Comments must be received no later than the conclusion of the October 6, 2022 hearing. Individuals or groups of people with disabilities who require special accommodations to comment or attend the hearing should contact Samantha Carlisle at (907) 793-1223, no later than September 29, 2022. Jeremy M. Price Chair, Commissioner Jeremy Price Digitally signed by Jeremy Price Date: 2022.09.02 09:00:12 -08'00' From:Carlisle, Samantha J (OGC) To:AOGCC_Public_Notices Subject:Public Hearing Notice ERIO-22-002 (CPAI) Date:Friday, September 2, 2022 10:22:00 AM Attachments:ERIO-22-002 Public Hearing Notice.pdf RE: Docket Number: ERIO-22-002 Samantha Carlisle AOGCC Special Assistant Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage, AK 99501 (907) 793-1223 Bernie Karl K&K Recycling Inc. P.O. Box 58055 Fairbanks, AK 99711 Mailed 9/2/22 Adam Garrigus being first duly sworn on oath deposes and says that she is a representative of the Anchorage Daily News, a daily newspaper. That said newspaper has been approved by the Third Judicial Court, Anchorage, Alaska, and it now and has been published in the English language continually as a daily newspaper in Anchorage, Alaska, and it is now and during all said time was printed in an office maintained at the aforesaid place of publication of said news- paper. That the annexed is a copy of an adver- tisement as it was published in regular issues (and not in supplemental form) of said news- paper on AFFIDAVIT OF PUBLICATION ______________________________________ Notary Public in and for The State of Alaska. Third Division Anchorage, Alaska MY COMMISSION EXPIRES ______________________________________ 09/04/2022 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 this 6th day of September 2022. Account #: 100869 ST OF AK/AK OIL AND GAS CONSERVATION COMMISSION 333 W. 7TH AVE STE 100, ANCHORAGE, AK 99501 Order #: W0032601 Cost: $341.6 Notice of Public HearingSTATE OF ALASKAALASKA OIL AND GAS CONSERVATION COMMISSION RE: Docket Number: ERIO‑22‑002 By application received August 11, 2022, ConocoPhillips Alaska, Inc. (CPAI) requested the Alaska Oil and Gas Conservation Commission (AOGCC) issue an order approving a pilot enhanced oil recovery (EOR) project for the Coyote Interval in the Kuparuk River Unit (KRU). Enhanced recovery regulations (20 AAC 25.402) are in place to ensure that EOR injection projects are conducted in a manner that will lead to increased ultimate recovery, prevent the injected fluids from escaping the injection interval, and protect sources of freshwater. Operators must apply for, and be granted, an order that authorizes EOR injection before they can commence injection operations. Part of the application process requires the operator to notify, and provide a copy of the application to, all operators and surface owners within a ¼‑mile radius of the proposed injection well(s). For situations where the viability of a specific EOR process has not been demonstrated as being effective in a certain application, such as this proposal to conduct water injection for EOR purposes in the Coyote Interval, 20 AAC 25.450(b) allows the AOGCC to issue an injection order approving a pilot EOR injection project to allow for the gathering the information necessary to show whether or not it is viable before a full field project is pursued. Pilot project EOR orders are usually time limited and often require different data collection and reporting requirements than a conventional EOR injection order since the purpose of a pilot EOR injection project is to demonstrate feasibility of a process before pursuing it on a fieldwide basis. This notice does not contain all the information filed by CPAI. You may obtain more information about this filing by contacting the AOGCC’s Special Assistant, Samantha Carlisle, at (907) 793‑1223 or Samantha.Carlisle@alaska.gov. The AOGCC has scheduled a public hearing on this matter for October 6, 2022 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 no. 592 156 542#. Anyone who wishes to participate remotely using MS Teams video conference should contact Samantha Carlisle 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.carlisle@alaska.gov. Comments must be received no later than the conclusion of the October 6, 2022 hearing. Individuals or groups of people with disabilities who require special accommodations to comment or attend the hearing should contact Samantha Carlisle at (907) 793‑1223, no later than September 29, 2022. Jeremy M. PriceChair, Commissioner Pub: Sept. 4, 2022 STATE OF ALASKA THIRD JUDICIAL DISTRICT 2024-07-14 Document Ref: 66NFL-SCS5A-S649Z-CHTLN Page 64 of 83 1 By Samantha Carlisle at 9:59 am, Aug 12, 2022 Application to the Alaska Oil and Gas Conservation Commission for Approval of Pilot Injection into the Coyote Reservoir Kuparuk River Unit August 11, 2022 Application to the AOGCC for Approval of Pilot Injection into the Coyote Reservoir, Kuparuk River Unit 2 Table of Contents 20 AAC 25.402(c)(1) Plat of Wells Penetrating Injection Zone………………………………………………………………….5 20 AAC 25.402(c)(2) Operators and Surface Owners within ¼ Mile of Injection Operations……………….......6 20 AAC 25.402 (c)(3) Affidavit 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 Affected…………………………………………………………………..9 20 AAC 25.402(c)(6) Description of the Formation…………………………………………………………………………………10 20 AAC 25.402(c)(7) Logs of the Injection Wells…………………………………………………………………………………….13 20 AAC 25.402 (c)(8) Mechanical Integrity of Injection Wells…………………………………………………………………14 20 AAC 25.402(c)(9) Injection Fluid Analysis and Injection Rates……………………………………………………………16 20 AAC 25.402(c)(10) Estimated Average and Maximum Injection Pressures…………………………………………17 20 AAC 25.402(c)(11) Fracture Information……………………………………………………………………………………………18 20 AAC 25.402(c)(12) Quality of Formation Water…………………………………………………………………………………20 20 AAC 25.402 (c)(13) Aquifer Exemption Reference……………………………………………………………………………..21 20 AAC 25.402(c)(14) Incremental Hydrocarbon Recovery…………………………………………………………………….23 20 AAC 25.402(c)(15) Mechanical Condition of Wells Within ¼ Mile of Proposed Area………………………….24 List of Figures Figure 1: Proposed Coyote Pilot Injection Project Well Locations……………………………………………………………4 Figure 2: One-Quarter Mile Circle/Tangent with Proposed Injectors and Formation Penetrations………….5 Figure 3: Palm 1 Type Log……………………………………………………………………………………………………………………….9 Figure 4: Coyote Top Structure………………………………………………………………………………………………………..11/12 Figure 5: Schematic of Proposed Injection Well…………………………………………………………………………………….15 Figure 6: Fracture Gradient of Coyote Upper Confining Layer……………………………………………………………….19 Figure 7: Composition of produced water from 3S-24B Coyote test well………………………………………………20 Figure 8: Palm 1 well Ugnu display………………………………………………………………………………………………………..22 Figure 9: List of wells within ¼ mile radius of proposed area…………………………………………………………………24 Figure 10: Estimated Top of Cement in wells within ¼ mile radius of proposed area…………………………….24 Application to the AOGCC for Approval of Pilot Injection into the Coyote Reservoir, Kuparuk River Unit 3 Introduction ConocoPhillips Alaska, Inc. (CPAI), as operator of the Kuparuk River Unit (KRU) and non-unitized lease ADL 392374, submits this application to the Alaska Oil and Gas Conservation Commission (AOGCC) for authorization for water injection into the Coyote reservoir through a proposed waterflood pattern pilot. This project involves injecting water, and potentially gas into the Coyote reservoir (the Coyote reservoir is defined in the section 20 AAC 25.402(c)(5) Description and Depth of Pool Affected) to test the injectivity of water (and potentially gas) and subsequent production response. The feasibility of injection into the Coyote reservoir has not been established and is therefore considered a “pilot” project. This pilot project will aid in determining the commercial viability of developing Coyote as an enhanced oil recovery project. The impacted area of the pilot project (adjacent to drill site 3S in the Kuparuk River Unit) is depicted below in Figure 1. The requested duration of the order is 3 years. This will allow time to drill the first injector, test injection performance, and analyze results. This will also allow for ample time to potentially drill and complete a second injection well to fully complete a producer centered pattern for additional data collection if warranted. Application to the AOGCC for Approval of Pilot Injection into the Coyote Reservoir, Kuparuk River Unit 4 Figure 1: Proposed Coyote pilot injection project showing approximate well locations southwest of the Kuparuk 3S drill site. Blue dashed line is the first proposed injector, Green dashed line is proposed producer, and gray dashed line is future potential injector to complete a fully supported producer centered pattern. In Q4 2021, the 3S-24B exploration well was drilled to understand the ability to produce from the Coyote interval. The well was drilled as an exploration well within the KRU. No pool rules are established for this reservoir. Drilling of a horizontal producer-injector well pair is planned for Q4 2022, with injection operations commencing in ~Q1 2023. The final development design for the Coyote reservoir is expected to be a line-drive water alternating gas (WAG) flood with horizontal producers and horizontal injectors drilled approximately parallel to the maximum principal stress direction. These pilot results will inform whether this development concept is optimal. If a commercially viable discovery is established and the development is sanctioned, then CPAI would apply at that time to the AOGCC to establish pool rules and an area injection order. Application to the AOGCC for Approval of Pilot Injection into the Coyote Reservoir, Kuparuk River Unit 5 20 AAC 25.402(c)(1) Plat of Wells Penetrating Injection Zone Figure 2 shows the proposed Coyote injection wells within the injection zone. A ¼ mile radius around the injection laterals is displayed. It should be noted that the 3S-21 well will be P&A’d prior to commencement of injection operations. Figure 2: ¼ Mile Circle/Tangent with Proposed Injectors within the injection formation. Application to the AOGCC for Approval of Pilot Injection into the Coyote Reservoir, Kuparuk River Unit 6 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: Alaska Department of Natural Resources Division of Oil and Gas Attn: Ken Diemer, Unit Manager 550 West 7th Ave., Suite 1100 Anchorage, AK 99501 Application to the AOGCC for Approval of Pilot Injection into the Coyote Reservoir, Kuparuk River Unit 7 20 AAC 25.402 (c)(3) Affidavit Regarding Notice to Surface Owners Application to the AOGCC for Approval of Pilot Injection into the Coyote Reservoir, Kuparuk River Unit 8 20 AAC 25.402(c)(4) Description of the Proposed Operation This application to the AOGCC seeks endorsement and authorization for a pilot injection project in the Coyote Reservoir within the KRU, and an adjacent non-unitized lease (ADL 392374) owned by KRU working interest owners. The Coyote pilot injection project involves drilling a horizontal producer-injector well pair. The first injector to be drilled will be named 3S-701 and will be located 1,000’ to 3,000’ southwest of the 3S-704 planned production well. The optimum pattern spacing for development in this reservoir is still under analysis. Completion of the 3S-701 injection well will allow interference and injection testing of the Coyote reservoir to help establish the optimal pattern spacing and potentially support commerciality of the reservoir. Depending on the outcome of this first injection well and its testing, a second injection well may be drilled to continue this long-term injection and production test with a fully supported producer centered pattern centered around the 3S-704. 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, and, potentially, drill the second injector, test injection performance, and observe & analyze results. Application to the AOGCC for Approval of Pilot Injection into the Coyote Reservoir, Kuparuk River Unit 9 20 AAC 25.402(c)(5) Description and Depth of Pool Affected The 3S-701 injection well is a pilot appraisal well within the KRU and an adjacent non-unitized lease (ADL 392374). A Coyote pool has not been established. If it is determined that commercially exploitable hydrocarbons exist within the Coyote interval, and a development project is sanctioned, then a pool will be established. The gross Coyote reservoir interval is defined by logs from the Palm 1 well over the measured depth range of 4,270 – 5,115 feet (Figure 3). Location of the Palm 1 is shown on the map in Figure 4, with bottom hole location immediately west of drillsite 3S. Figure 3: Palm 1 (UWI: 501032036100) type log showing the Coyote reservoir interval, upper confining zone, and lower confining zone. Application to the AOGCC for Approval of Pilot Injection into the Coyote Reservoir, Kuparuk River Unit 10 20 AAC 25.402(c)(6) Description of the Formation Stratigraphy and Sedimentology The Late Cretaceous Coyote reservoir is a thinly bedded, shallow marine, west to east progradational system within the Nanushuk formation. The interval likely consists of delta front, distal delta front to prodelta silts and sands deposited in an elongate NE-SW trend paralleling depositional strike. Gross thickness of the Coyote interval is approximately 650’ in the 3S area. Average porosity of the Coyote interval sands is in the range of 23-24%, and average permeability of the reservoir sands is on the order of 10-20 millidarcies. Net to gross of the interval is approximately 45%. The interval has been penetrated by numerous wells targeting deeper stratigraphic intervals, both from drill site 3S, and vertical off-ice exploration wells in and surrounding the Kuparuk River Unit. Structure and Trap Configuration The predominant trapping mechanism of the Coyote hydrocarbon accumulation is stratigraphic, with some structural components. The stratigraphic components include a pinch-out to the west, and shale- out to the northeast, southeast and southwest. Small 4-way dip closures, and stratigraphic compartments are believed to be present within the Coyote and are known to contain small gas caps. The top Coyote depth structure has limited structural relief on the paleo-shelf (on the order of 100’). The Coyote has more significant relief to the northeast, and southeast as it plunges off the paleo-shelf (Figure 4A). Limited faulting is present in the area, at the Coyote level. In the proposed injection pilot area, a single small displacement fault is present near the heel of the proposed producer (Figure 4B). The fault trend is oriented northwest to southeast, with dip to the northeast. It has a maximum displacement of 30’, and a length from tip to tip of approximately 2000’. It cuts the Top Coyote, and extends 300’ into the overburden where it loses throw, and extends into the coyote reservoir by 200’ where it also loses throw. The fault is interpreted to be sealing where it displaces reservoir against overlying Seabee shale. It is uncertain whether the fault is sealing or not where it juxtaposes reservoir against reservoir. Seals Confining intervals shown in Figure 3, are as follows: Upper Confining Interval Distal toe of slope Claystone with thin siltstone beds of the Cretaceous Seabee formation are present in thicknesses greater than 350’ TVD across the area. There are no known hydrocarbon bearing zones, between the base of the permafrost to the top of the Coyote reservoir interval. Lower Confining Interval Slope mudstones associated with the Torok formation, are present in thicknesses greater than 300’ TVD across the area. This same interval forms the upper confining layer of the Kuparuk River Unit, Torok Oil Pool. Application to the AOGCC for Approval of Pilot Injection into the Coyote Reservoir, Kuparuk River Unit 11 4A Application to the AOGCC for Approval of Pilot Injection into the Coyote Reservoir, Kuparuk River Unit 12 Figure 4A & 4B: Small- and large-scale top Coyote depth structure maps. Top Coyote penetrations marked by red x’s. Large scale map includes proposed injection pilot wells, with the aforementioned fault near the heel of the producer. 4B Application to the AOGCC for Approval of Pilot Injection into the Coyote Reservoir, Kuparuk River Unit 13 20 AAC 25.402(c)(7) Logs of the Injection Wells Upon drilling of the injection well(s), logs will be sent to the Commission in accordance with applicable AOGCC regulations. Application to the AOGCC for Approval of Pilot Injection into the Coyote Reservoir, Kuparuk River Unit 14 20 AAC 25.402(c)(8) Mechanical Integrity of Injection Wells See Figure 5 below for a proposed injection schematic. The injection well design is like other injection wells in the KRU. A three-string design will be used as shown in the schematic below. Surface casing set below the base of the West Sak in the Colville Group will be cemented back to surface. Within the pilot area, the base of permafrost is interpreted to be at ~1,650 ft. SSTVD. The intermediate hole will be drilled to a casing point within the upper Coyote interval at approximately 85 degrees inclination. The Coyote interval will be drilled horizontally and completed open hole with solid liner containing ball drop fracture sleeves and liner top hanger and packer. External swell packers will be added to provide zonal isolation between fracture stages and as needed to isolate any out of zone intervals or fault crossings along the lateral. The packer will be set within 200’ MD of the intended injection interval in accordance with 20 AAC 25.412(b). The tubing/casing annulus pressure of each injection well will be tested in accordance with 20 AAC 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 Injection into the Coyote Reservoir, Kuparuk River Unit 15 Figure 5: Schematic of Proposed Injection Well Application to the AOGCC for Approval of Pilot Injection into the Coyote Reservoir, Kuparuk River Unit 16 20 AAC 25.402(c)(9) Injection Fluid Analysis and Injection Rates The Coyote Pilot Injection Project will occur at 3S pad, a satellite drillsite that is connected to the KRU pipeline network. KRU and its network of drillsites were built to allow only one type of water, either produced or sea, on a drill site at a time. Water service for each drillsite is selected to optimize the production potential of the entire asset. 3S is currently on produced water service, but this could change in the future. Part of the purpose for this pilot is to confirm compatibility. Injection rates may exceed 15,000 bbl/d for each injection well drilled for the pilot project, depending on reservoir quality. A gas injection rate schedule will be dependent on post-drill analysis of pore volume and voidage replacement. Water and gas injection rates will ultimately be constrained by bottom hole pressure and overburden strength. Primary injection fluids include: • Produced water and gas from all present and yet-to-be defined oil pools within the KRU • Beaufort seawater sourced from the Kuparuk seawater treatment plant • Enriched hydrocarbon gas (MI): Blend of KRU lean gas with indigenous and/or imported natural gas liquids 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 Coyote injection well(s). 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 or performance. These other fluids include: • Fluids used during hydraulic stimulation • Tracer survey fluids to monitor reservoir performance • Fluids used to improve near wellbore injectivity (acids, solvents, etc.) • Fluids used to seal wellbore intervals which negatively impact recovery (cement, resin, etc.) • Fluids associated with freeze protection (diesel, crude, glycol, methanol, etc.) • Standard oilfield chemicals (corrosion inhibitor, scale inhibitor, etc.) Water compatibility modelling indicates barium sulfate and calcium carbonate scale formation in production wells, as has been experienced to various degrees in KRU pools, is likely due to the mixing of formation water with seawater or KRU produced water. A scale inhibition treatment program, like that employed elsewhere in KRU, will be performed at Coyote as required. As a part of the upcoming drilling campaign, a whole core will be collected. At that time additional water compatibility testing will be performed. Application to the AOGCC for Approval of Pilot Injection into the Coyote Reservoir, Kuparuk River Unit 17 20AAC 25.402(c)(10) Estimated Average and Maximum Injection Pressures The sand-face injection pressure of the pilot injection well(s) will be maintained below the estimated strength of the upper confining zone. Analysis of available data in the confining zone yielded a fracture gradient of ~0.65 psi/ft. The pilot project will target an injection gradient of 0.61 psi/ft, with an operating maximum of 0.62 psi/ft, but this is subject to change as more information is gathered. The pilot project will operate at or below the interpreted fracture gradient of the Coyote reservoir interval. The reservoir has demonstrated a fracture gradient of 0.62 psi/ft in the 3S-24B well test. At 4,112’ TVDSS the maximum injection pressure will be 2,549 psi (0.62 psi/ft). The sand-face injection pressure of each injector will be set based on the realized depth of the reservoir. Application to the AOGCC for Approval of Pilot Injection into the Coyote Reservoir, Kuparuk River Unit 18 20AAC 25.402(c)(11) Fracture Information In the area of the proposed Coyote injection pilot, the Coyote reservoir is overlain by distal toe of slope claystone with thin siltstone beds of the Cretaceous Seabee formation in thicknesses greater than 350’ TVD. The underlying confining zone beneath the Coyote reservoir consists of slope mudstones associated with the Torok formation in thicknesses greater than 300’ TVD. The lower confining zone forms the upper confining zone of the KRU, Torok Oil Pool (Figure 3). Leak-off test (LOT) data was collected in the 3S-611, and 3S-612 Torok horizontal wells within the overburden immediately above the Torok reservoir, for calibration of its strength. These LOT’s returned an ~16 pound per gallon (ppg) mud- weight equivalent strength for the Torok reservoir overburden. The calculated hydraulic fracture gradient for the overlying Seabee Formation is based on rock strength curves calibrated to fracture stimulation data collected during the stimulation of the Coyote reservoir in the 3S-24B well. At the present time there is no leak off, or formation integrity test data for the overlying confining zone. CPAI has plans to perform a diagnostic fracture injection test (DFIT) within the upper confining zone within the 3S-24B well to further calibrate the overburden rock strength. This test is planned to occur during the first half of 2023, prior to P&A of this well. The cross-plot in Figure 6 shows the resulting estimate for the initiation pressure for hydraulic fracturing of the Seabee confining zone in true vertical depth subsea and pore pressure (black line). Also shown is the pore pressure of the Coyote reservoir sandstone and the planned range of injection pressures for the Coyote injection pilot project. Example gradients are shown at 0.61 psi/ft (gray line), 0.62 psi/ft (orange line), and the Coyote pore pressure of 0.44 psi/ft (brown line). Fractures will not propagate within the Coyote Reservoir with injection pressures at or below 0.62 psi/ft (fracture gradient of the reservoir) and will not propagate into the confining interval if injection pressures are below 0. 65psi/ft (fracture gradient of the overlying seal). The anticipated water injection rate for this pilot project may exceed 15,000 BWPD per injection well. Injection into the Coyote Reservoir will occur at or below the fracture gradient of the Coyote Sands and below the fracture gradient of the overlying confining shales (0.62 psi/ft and 0.65 psi/ft respectively). At 4,150ft TVDSS the targeted sand-face injection pressure will be 2,531 psi (0.61 psi/ft), and the maximum injection pressure will be 2,573 psi (0.62 psi/ft gradient). Application to the AOGCC for Approval of Pilot Injection into the Coyote Reservoir, Kuparuk River Unit 19 Figure 6: Pressure gradients associated with Coyote pore pressure, targeted injection pressure, max injection pressure and upper confining zone pressure. Application to the AOGCC for Approval of Pilot Injection into the Coyote Reservoir, Kuparuk River Unit 20 20AAC 25.402(c)(12) Quality of Formation Water A small amount of sustained formation water (~11% sustained water cut) was produced from the 3S-24B production test from the Coyote reservoir interval. Composition of this water, from laboratory analysis of a sample taken on January 28, 2022, is included in figure 7. The TDS of this sample was 21,185 mg/l, which is above the 10,000 mg/l cut-off for freshwater. Figure 7: Composition of produced water from 3S-24B Coyote test well Analysis Name Value Unit Aluminum - mg/l Boron 26.2 mg/l Barium 1.3 mg/l Bicarbonate 2,409.8 mg/l Calcium 99.4 mg/l Carbonate 13.0 mg/l Chloride 10,081.1 mg/l Conductivity 17,850.0 uS/cm Iron 0.1 mg/l Potassium 48.2 mg/l Lithium 2.2 mg/l Magnesium 91.7 mg/l Manganese 0.2 mg/l Sodium 8,246.5 mg/l Phosphorus 0.3 mg/l PH 8.3 Silicon 6.1 mg/l Sulfate 151.5 mg/l Specific Gravity @ 60 degrees F 1.0 Strontium 7.5 mg/l Zinc - mg/l Application to the AOGCC for Approval of Pilot Injection into the Coyote Reservoir, Kuparuk River Unit 21 20AAC 25.402(c)(13) Aquifer Exemption Reference The EPA has adopted an aquifer exemption for the “portions of aquifers on the North Slope described by a ¼ mile area beyond and lying directly below the Kuparuk River Unit oil and gas producing field” 40 C.F.R. 147.102(b)(3). The commission has adopted that exemption by reference 20 AAC 25.44(c). The proposed Coyote ERIO area is within the KRU and within the scope of the aquifer exemption. One lease proposed for inclusion in this ERIO application is ADL 392374, depicted in Figure 1. This lease is not presently within and part of the KRU. Historically, the lands were within the KRU in 1984, when the EPA adopted the aquifer exemption, and in 1986, when the Commission incorporated the KRU aquifer exemption. Accordingly, ADL 392374 is within the aquifer exception as originally approved by EPA and AOGCC. The Ugnu interval in the 3S area is interpreted as being a transitional zone at the base of the permafrost. However, there is uncertainty in this interpretation. As background, resistivities in clean sands greater than 100 Ohmm have a good correspondence to the presence of permafrost in the Kuparuk area. In the absence of temperature data, this resistivity cutoff is utilized for picking the approximate base of permafrost. For reference, in the Palm 1 well (Figure 8.) the base of continuous 100 ohmm resistivity in clean sands is present down to a depth of ~1,570’ MD. Below this depth, in the interval from 1,610 - 1,905’ MD, there is a transitional zone where resistivities approach 100 ohmm in clean sands. There are two possible interpretations for this interval 1) it is a transitional zone of discontinuous permafrost, or 2) it is a zone of low salinity water. No test data, or samples are available for this interval to confirm which is the case. If the zone is not permafrost, the calculated salinity of this interval would be ~2,000 ppm. Application to the AOGCC for Approval of Pilot Injection into the Coyote Reservoir, Kuparuk River Unit 22 Figure 8. Ugnu interval in the Palm 1 well. Application to the AOGCC for Approval of Pilot Injection into the Coyote Reservoir, Kuparuk River Unit 23 20AAC 25.402(c)(14) Incremental Hydrocarbon Recovery Initial reservoir modeling and simulation estimate a primary depletion recovery factor of 5-10%, a cumulative recovery factor from waterflood operations between 20-30% and an incremental 1-5% recovery for enriched gas injection (EWAG). Application to the AOGCC for Approval of Pilot Injection into the Coyote Reservoir, Kuparuk River Unit 24 20AAC 25.402(c)(15) Mechanical Condition of Wells Within ¼ Mile of Proposed Area Wells located within ¼ mile radius of the proposed Coyote horizontal injection wells are included in Figure 9. Of these three wells, the 3S-24B is the only well that currently has cement across the Coyote interval (Figure 10.). It should be noted that the 3S-21 will be plugged & abandoned prior to fracture stimulation operations of the proposed Coyote horizontal wells. During fracture stimulation operations, the OA (annulus between the 7” and 9-5/8” casing) of the of the 3S-03 will be monitored. Well Well Type Status Mech Integrity Notes 3S-03 Kuparuk Producer Active No issues Well to be pressure monitored during Coyote fracture stimulation. 3S-21 Kuparuk Injector To be Abandoned No issues P&A will take place prior to drilling Coyote injectors within ¼ mile 3S-24B Coyote Producer Active No Issues 3S-24B Sidetrack drilled 2021 as Coyote exploration well. Well to be P&A’d shortly after beginning injection in offset Coyote wells. Figure 9: Wells within ¼ mile radius of proposed area. See figure 2 for referenced well locations. Well Estimated TOC (MD) Estimated TOC (TVD) 3S-03 6,850’ 5,229’ 3S-21 8,598’ 5,260’ 3S-24B 7,550’ 3,758’ Figure 10: Estimated top of cement in wells from Figure 8. For reference, the top of the Coyote interval is located at approximately 4,100’ TVD.