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Home My WebLink AboutAIO 035 AINDEX AREA INJECTION ORDER NO. 35A Colville River Field Colville River Unit Qannik Oil Pool 1. July 17, 2023 ConocoPhillips Alaska, Inc.’s (CPAI) Application for Expansion of Area Injection Order 2. August 1, 2023 Notice of Public Hearing 3. August 3, 2023 Affidavit of Publication 4. December 19, 2023 Administrative Approval 5. January 15, 2025 AIO 7 Proposed language change (AIO 35A.002) INDEX AREA INJECTION ORDER NO. 35A STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION 333 West 7th Avenue, Suite 100 Anchorage, Alaska 99501 Re: THE APPLICATION OF CONOCOPHILLIPS ALASKA, INC. to expand the authorized injection interval for underground injection of fluids for enhanced oil recovery in the Qannik Oil Pool and to terminate Enhanced Recovery Injection Order 6, Colville River Unit, Arctic Slope, Alaska ) ) ) ) ) ) ) ) ) Area Injection Order 35A Docket Number: AIO-23-019 Colville River Field Colville River Unit Qannik Oil Pool December 19, 2023 IT APPEARING THAT: 1. By letter and application dated July 17, 2023 (July 17 Application), ConocoPhillips Alaska, Inc. (CPAI) requested that the Alaska Oil and Gas Conservation Commission (AOGCC) approve a vertical expansion of the authorized injection strata in Area Injection Order 35 (AIO 35) to match the vertical extents of the Qannik Oil Pool. 2. Pursuant to 20 AAC 25.540, the AOGCC scheduled a tentative public hearing for September 5, 2023. On August 1, 2023, the AOGCC published notice of that hearing on the State of Alaska’s Online Public Notice website, the AOGCC’s website and electronically transmitted the notice to all persons on the AOGCC’s email distribution list. On August 3, 2023, the notice was published in the Anchorage Daily News. 3. The AOGCC received no comments or requests for a public hearing. 4. Because CPAI provided sufficient information upon which to make an informed decision, the request can be resolved without a hearing. 5. The tentatively scheduled hearing was vacated. FINDINGS: Operator: CPAI is the operator of the Colville River Unit (CRU). Owners and Landowners: CPAI owns over 99% of the CRU and Petro-Hunt LLC, XH LLC, Rosewood Resources Inc., and William Herbert Hunt Trust Estate own the remainder. The landowners are the State of Alaska, Department of Natural Resources and the Arctic Slope Regional Corporation. Qannik Oil Pool: Conservation Order 605A (CO 605) (as amended) defines the current affected area and vertical extents of the Qanik Oil Pool (QOP). Defined Injection Area: The affected area of AIO 35 (as amended) matches the affected DUHDof CO 605A (as amended) and would not be altered by this application. See Figure 1below. Area Injection Order 35A December 19, 2023 Page 2 of 7 Area Injection Order 35A December 19, 2023 Page 3 of 7 5. Proposed Injection Interval: The current vertical extents authorized for enhanced oil recovery (EOR) injection is less than the current vertical limits of the QOP. CPAI proposes to vertically expand the injection interval to match the vertical extents of the QOP. The proposed vertical extents of the AIO are 6,030 ft to 6,249 ft measured depth in the CRU CD2-11 well (API 50-103-20515-00-00). See Figure 2 below. Figure 2: CD2-11 Type Log. Note Narwhal is non-reservoir in this this type log. (Courtesy of CPAI) 6. Relationship to Enhanced Recovery Injection Order 6 (ERIO 6): ERIO 6 approved a pilot injection project in the southeast portion of the QOP in the area around what’s labeled as Narwhal PA in Figure 1. The affected area of ERIO 6 is contained within the affected area Area Injection Order 35A December 19, 2023 Page 4 of 7 of the QOP. As can be seen in Figure 2 the injection of ERIO 6 extends above the injection interval of AIO 35. Expanding the injection interval of AIO 35 to match the vertical limits of the QOP will make it so that ERIO 6 is fully encompassed by the revised AIO 35, and thus no longer necessary. 7. Operators/Surface Owners Notification: CPAI submitted an affidavit attesting to having provided copies of the July 17 Application to all offset operators and surface owners within a ¼-mile of the affected area of AIO 35 as required by 20 AAC 25.402(c)(3). 8. Description of Operations: Fluids (originally only seawater provided by the Kuparuk River Unit seawater treatment plant and produced water from the Colville River Field, but additional fluids have been approved since AIO 35 came into effect) have been injected into the QOP since 2008 to enhance recovery from the pool. CPAI is drilling additional producers and injectors in what to date has been referred to as the Narwhal reservoir to expand development of the QOP. CPAI plans to continue water only injection in the portion of the QOP developed from CD2 but is requesting that enriched and non-enriched hydrocarbon gas be authorized for injection but only into the Narwhal reservoir. 9. Injection Fluids Compatibility: The authorized liquids have been demonstrated by over a decade’s worth of injection into the QOP to be compatible with the formation and reservoir fluids. Gas injection has been approved for development of the nearby Pikka-Nanushuk Oil Pool, which is an extension of the QOP/Narwhal development. This coupled with the fact that hydrocarbon gas injection has historically been shown to not have adverse reactions with the formation or reservoir fluids in oil pools across the North Slope indicate that hydrocarbon gases should not adversely impact the QOP. 10. Hydrocarbon Recovery: CPAI estimates that primary depletion in the QOP would only recover about 5% of the original oil in place and that water injection would increase this to about 30% while WAG injection would increase ultimate recovery by another 7%. 12. Injection Pressures: Injection pressure at the sandface will be limited to 0.8 psi/ft, which is above the QOP fracture gradient of 0.56 to 0.63 psi/ft but below the fracture gradient of the upper confining interval of 0.82 psi/ft. Water injection rates are expected to be between 500 and 8,000 bbls/day. CONCLUSIONS: 1. The requirements of 20 AAC 25.402 have been met. 2. The injection of water and gas will significantly improve oil recovery from the Qannik Oil Pool. 3. The proposed injection operations will be conducted in permeable strata, which can reasonably be expected to accept injected fluids at pressures less than the fracture pressure of the confining strata. 4. Injected fluids will be confined within the appropriate receiving intervals by impermeable lithology, cement isolation of the wellbores and appropriate operating conditions. 5. Sufficient information has been provided to authorize the injection of water and hydrocarbon gas into the QOP for the purposes of pressure maintenance and enhanced oil recovery. NOW, THEREFORE, IT IS ORDERED: This order supersedes AIO 35, the record of which is included by reference in this order. The Area Injection Order 35A December 19, 2023 Page 5 of 7 underground injection of fluids for pressure maintenance and enhanced oil recovery is authorized in the following area, subject to the following rules and, to the extent not superseded by these rules, the statewide requirements of 20 AAC 25: Affected Area: Umiat Meridian Township, Range Sections T10N, R04E 1 – 4 T10N, R05E 4 – 6 T11N, R04E 1 – 4; 9 – 16; 21 – 28; 33 – 36 T11N, R05E 4 – 9; 16 – 21; 28 – 33 T12N, R04E 1 – 4; 9 – 16; 21 – 28; 33 – 36 T12N, R05E 4 – 9; 16 – 21; 28 – 33 Rule 1. Authorized Injection Strata for Enhanced Recovery (Revised This Order) Authorized fluids (under Rule 3, below) may be injected for purposes of pressure maintenance and enhanced oil recovery within the Affected Area into strata that are common to, and correlate with, the interval between the measured depths of 6,030 and 6,249 feet on the EWR log recorded in well CRU CD2-11. Except that enriched and lean hydrocarbon gas may only be injected in the Narwhal reservoir (the strata that is common to and correlates with the interval between the measured depths of 6,030 and 6,086 feet on the EWR log recorded in well CD2-11). Rule 2. Well Construction (Source AIO 35) To facilitate wireline access, packers in injection wells may be located more than 200’ measured depth above the top of the Qannik Oil Pool; however, packers shall not be located above the confining zone. The production casing cement volume must be sufficient to place cement a minimum of 300’ measured depth above the planned packer depth. Rule 3. Authorized Fluids for Enhanced Recovery (Sources: AIO 35, AIO 35.003, AIO 35.004, and Revised This Order) Fluids authorized for injection include: Dsource water from the Kuparuk sea water treatment plant; Eproduced water from the Alpine Central Facility (ACF); FEnriched gas from ACF for injection only in the Narwhal reservoir portion of the QO3, asdescribe in Rule 1; GLean gas from ACF for injection only in the Narwhal reservoir portion of the QO3, asdescribe in Rule 1; HSump Fluid, hydrotest fluid (excluding fluids derived from tests of transportation pipelines), rinsate generated from washing mud hauling trucks, excess well work fluids, and treated camp effluent and mixtures involving such fluids; ITracer survey fluids to monitor reservoir performance; JFluids used to improve near wellbore injectivity (acid, solvents, surfactants, etc.); KFluids used to seal wellbore intervals which negatively impact recovery (cement, resin, etc.); Area Injection Order 35A December 19, 2023 Page 6 of 7 i. Fluids associated with freeze protection; and j. Standard oilfield chemicals (corrosion inhibitor, scale inhibitor, etc.) Any other fluids shall be approved by separate administrative action. Rule 4. Authorized Injection Pressure for Enhanced Oil Recovery (Revised This Order) For the injection interval specified in Rule 1 above, pressures will be managed not to exceed the maximum injection gradient of 0.80 psi/ft to ensure containment if injected fluids withing the injection interval. Rule 5. Monitoring Tubing-Casing Annulus Pressure (Source: AIO 35) The tubing and casing annuli pressures of each injection well and the OA pressures of all wells that are not cemented across the Qannik reservoir located within a ¼-mile radius of a Qannik injector must be monitored at least daily, except if prevented by extreme weather conditions, emergency situations, or similar unavoidable circumstances. Monitoring results shall be documented and made available for AOGCC inspection. Rule 6. Demonstration of Tubing/Casing Annulus Mechanical Integrity (Source: AIO 35) The mechanical integrity of an injection well must be demonstrated before injection begins, and before returning a well to service following a workover affecting mechanical integrity. A AOGCC-witnessed mechanical integrity test must be performed after injection is commenced for the first time in a well, to be scheduled when injection conditions (temperature, pressure, rate, etc.) have stabilized. Subsequent tests must be performed at least once every four years thereafter (except at least once every two years in the case of a slurry injection well). The AOGCC must be notified at least 24 hours in advance to enable a representative to witness mechanical integrity tests. Unless an alternate means is approved by the AOGCC, mechanical integrity must be demonstrated by a tubing/casing annulus pressure test using a surface pressure of 1500 psi or 0.25 psi/ft multiplied by the vertical depth of the packer, whichever is greater, that shows stabilizing pressure and does not change more than 10 percent during a 30-minute period. Results of mechanical integrity tests must be readily available for AOGCC inspection. Rule 7. Well Integrity and Confinement (Source: AIO 35) Whenever any pressure communication, leakage or lack of injection zone isolation is indicated by an injection rate, operating pressure observation, test, survey, log, or other evidence (including OA pressure monitoring of all wells within a ¼-mile radius of where the Qannik 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, or if so directed by the AOGCC. A monthly report of daily tubing and casing annuli pressures and injection rates must be provided to the AOGCC for all injection wells indicating well integrity failure or lack of injection zone isolation. Rule 8. Notification of Improper Class II Injection (Source: AIO 35) Injection of fluids other than those listed in Rule 4 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. Additionally, notification requirements of any other State or Federal agency remain the operator’s responsibility. Area Injection Order 35A December 19, 2023 Page 7 of 7 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. Injection may not be restarted unless approved by the AOGCC. Rule 9. Other Conditions (Source: AIO 35) The AOGCC may suspend, revoke or modify this authorization if injected fluids fail to be confined within the designated injection strata. Rule 10. Administrative Action (Rescinded, superseded by 20 AAC 25.556(d)) DONE at Anchorage, Alaska, and dated December 19, 2023. Brett W. Huber, Sr Jessie L. Chmielowski Gregory C. Wilson Chair, Commissioner Commissioner Commissioner RECONSIDERATION AND APPEAL NOTICE As provided in AS 31.05.080(a), within 20 days after written notice of the entry of this order or decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration of the matter determined by it. If the notice was mailed, then the period of time shall be 23 days. An application for reconsideration must set out the respect in which the order or decision is believed to be erroneous. The AOGCC shall grant or refuse the application for reconsideration in whole or in part within 10 days after it is filed. Failure to act on it within 10 days is a denial of reconsideration. If the AOGCC denies reconsideration, upon denial, this order or decision and the denial of reconsideration are FINAL and may be appealed to superior court. The appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision denying reconsideration, UNLESS the denial is by inaction, in which case the appeal MUST be filed within 40 days after the date on which the application for reconsideration was filed. If the AOGCC grants an application for reconsideration, this order or decision does not become final. Rather, the order or decision on reconsideration will be the FINAL order or decision of the AOGCC, and it may be appealed to superior court. That appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision on reconsideration. As provided in AS 31.05.080(b), “[t]he questions reviewed on appeal are limited to the questions presented to the AOGCC by the application for reconsideration.” In computing a period of time above, the date of the event or default after which the designated period begins to run is not included in the period; the last day of the period is included, unless it falls on a weekend or state holiday, in which event the period runs until 5:00 p.m. on the next day that does not fall on a weekend or state holiday. Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2023.12.19 09:09:38 -09'00' Gregory Wilson Digitally signed by Gregory Wilson Date: 2023.12.19 12:49:06 -09'00' Brett W. Huber, Sr. Digitally signed by Brett W. Huber, Sr. Date: 2023.12.19 13:03:28 -09'00' From:Christianson, Grace K (OGC) To:AOGCC_Public_Notices Subject:[AOGCC_Public_Notices] ERIO 6.002 and AIO 35A (CPAI) Date:Wednesday, December 20, 2023 2:52:34 PM Attachments:aio35A.pdf ERIO 6.002.pdf Request to terminate Enhanced Recovery Injection Order 6 Colville River Unit And THE APPLICATION OF CONOCOPHILLIPS ALASKA, INC. to expand the authorized injection interval for underground injection of fluids for enhanced oil recovery in the Qannik Oil Pool and to terminate Enhanced Recovery Injection Order 6, Colville River Unit, Arctic Slope, Alaska Best, Grace Christianson Executive Assistant Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage, AK 99501 907-793-1230 CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska, and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use, or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it without first saving or forwarding it, and so that the AOGCC is aware of the mistake in sending it to you, contact Grace Christianson at (907-793-1230 ) or (grace.christianson@alaska.gov). __________________________________ List Name: AOGCC_Public_Notices@list.state.ak.us You subscribed as: samantha.carlisle@alaska.gov Unsubscribe at: https://list.state.ak.us/mailman/options/aogcc_public_notices/samantha.carlisle%40alaska.gov Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.alaska.gov ADMINISTRATIVE APPROVALS AREA INJECTION ORDER 18E.007 AREA INJECTION ORDER 28.010 AREA INJECTION ORDER 35A.001 AREA INJECTION ORDER 40.004 AREA INJECTION ORDER 43.002 Mr. Michael Driscoll WNS Development Supervisor North Slope Development ConocoPhillips Alaska, Inc. P.O Box 100360 Anchorage, AK 99510-0360 Re: Docket Number: AIO-25-013 Making mechanical integrity testing notification requirements consistent across Colville River Unit and Greater Moose’s Tooth Unit pools Colville River Unit, Alpine Oil Pool, Qannik Oil Pool, and Nanuq Oil Pool Greater Moose’s Tooth Unit Lookout Oil Pool and Rendezvous Oil Pool Dear Mr. Driscoll: By letter dated March 17, 2025, ConocoPhillips Alaska, Inc. (CPAI) asked the Alaska Oil and Gas Conservation Commission (AOGCC) to reconsider a portion of Rule 5 of Enhanced Recovery Injection Order No. 9 (ERIO 9) which stated that CPAI was required to provide a minimum of 72- hour notice prior to conducting a required mechanical integrity test. CPAI pointed out that other pools the in Colville River Unit (CRU) and Greater Moose’s Tooth Unit (GMTU) have different minimum notification requirements and that the pools should be consistent and proposed changing the requirement in Rule 5 of ERIO 9 from 72 to 24 hours. The AOGCC agrees the notification requirement should be consistent across all pools in these two units. However, the CRU and GMTU are remote locations in the context of Industry Guidance Bulletins (IGB) 10-01A (Test Witness Notification) and IGB 10-02B (Mechanical Integrity Testing) because the fields do not have a permanent road connection to Alaska’s road system and therefore 48 hours’ notice is appropriate for these fields. On its own motion and in accordance with 20 AAC 25.556(d), the AOGCC hereby amends the Demonstration of Tubing/Casing Annulus Mechanical Integrity rules in the injection orders for the CRU and GMTU fields. AIO 18E.007, 28.010, 35A.001, 40.004, and 43.002 April 24, 2025 Page 2 of 4 Now Therefore it is Ordered: Rule 6 of AIO 18E is amended to read as follows: Rule 6 Demonstration of Tubing/Casing Annulus Mechanical Integrity (Source: Revised This Order for Clarification) The mechanical integrity of each injection well must be demonstrated before injection begins and before returning a well to service following any workover affecting mechanical integrity. An AOGCC-witnessed 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. Subsequent tests must be performed at least once every four years thereafter. For slurry injection wells, the tubing/casing annulus must be tested for mechanical integrity every two years. The AOGCC must be notified at least 48 hours in advance to enable a representative to witness an MIT. Unless an alternate means is approved by the AOGCC, mechanical integrity must be demonstrated by a tubing/casing annulus pressure test using a surface pressure of 1,500 psi or 0.25 psi/ft multiplied by the vertical depth of the packer, whichever is greater, that shows stabilizing pressure and does not change more than 10 percent during a 30-minute period. Results of MITs must be readily available for AOGCC inspection. Rule 6 of AIO 28 is amended to read as follows: Rule 6 Demonstration of Tubing/Casing Annulus Mechanical Integrity A Commission-witnessed mechanical integrity test must be performed after injection is commenced for the first time in a well, to be scheduled when injection conditions (temperature, pressure, rate, etc.) have stabilized. Subsequent tests must be performed at least once every four years thereafter, except at least once every two years in the case of a slurry injection well. The Commission must be notified at least 48 hours in advance to enable a representative to witness mechanical integrity tests. Unless an alternate means is approved by the Commission, mechanical integrity must be demonstrated by a tubing/casing annulus pressure test using a surface pressure of 1,500 psi or 0.25 psi/ft multiplied by the vertical depth of the packer, whichever is greater, that shows stabilizing pressure and does not change more than 10 percent during a 30-minute period. Results of mechanical integrity tests must be readily available for Commission inspection. Rule 6 of AIO 35A is amended to read as follows: Rule 6. Demonstration of Tubing/Casing Annulus Mechanical Integrity (Source: AIO 35) The mechanical integrity of an injection well must be demonstrated before injection begins, and before returning a well to service following a workover affecting mechanical integrity. An AOGCC-witnessed mechanical integrity test must be performed after injection is commenced for the first time in a well, to be scheduled when injection conditions (temperature, pressure, rate, etc.) have stabilized. Subsequent tests must be performed at least once every four years thereafter (except at least once every two years in the case of a slurry injection well). The AOGCC must be notified at least 48 hours in advance to enable a representative to witness mechanical integrity tests. Unless an alternate means is AIO 18E.007, 28.010, 35A.001, 40.004, and 43.002 April 24, 2025 Page 3 of 4 approved by the AOGCC, mechanical integrity must be demonstrated by a tubing/casing annulus pressure test using a surface pressure of 1500 psi or 0.25 psi/ft multiplied by the vertical depth of the packer, whichever is greater, that shows stabilizing pressure and does not change more than 10 percent during a 30-minute period. Results of mechanical integrity tests must be readily available for AOGCC inspection. Rule 6 of AIO 40 is amended to read as follows: Rule 6 Demonstration of Tubing/Casing Annulus Mechanical Integrity The mechanical integrity of each injection well must be demonstrated before injection begins and before returning a well to service following any workover affecting mechanical integrity. An AOGCC-witnessed MIT must be performed after injection is commenced for the first time in a well, to be scheduled when injection conditions (temperature, pressure, rate, etc.) have stabilized. Subsequent tests must be performed at least once every four years thereafter. The AOGCC must be notified at least 48 hours in advance to enable a representative to witness an MIT. Unless an alternate means is approved by the AOGCC, mechanical integrity must be demonstrated by a tubing/casing annulus pressure test using a surface pressure of 1,500 psi or 0.25 psi/ft multiplied by the vertical depth of the packer, whichever is greater, that shows stabilizing pressure and does not change more than 10 percent during a 30-minute period. Results of MITs must be readily available for AOGCC inspection. Rule 6 of AIO 43 is amended to read as follows: Rule 6 Demonstration of Tubing/Casing Annulus Mechanical Integrity The mechanical integrity of each injection well must be demonstrated before injection begins and before returning a well to service following any workover affecting mechanical integrity. 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 (temperature, pressure, rate, etc.) have stabilized. Subsequent tests must be performed at least once every four years thereafter. The AOGCC must be notified at least 48 hours in advance to enable a representative to witness an MIT. Unless an alternate means is approved by the AOGCC, mechanical integrity must be demonstrated by a tubing/casing annulus pressure test using a surface pressure of 1,500 psi or 0.25 psi/ft multiplied by the vertical depth of the packer, whichever is greater, that shows stabilizing pressure and does not change more than 10 percent during a 30-minute period. Results of MITs must be readily available for AOGCC inspection. DONE at Anchorage, Alaska and dated April 24, 2025. Jessie L. Chmielowski Gregory C. Wilson Commissioner Commissioner Gregory C. Wilson Digitally signed by Gregory C. Wilson Date: 2025.04.23 15:47:29 -08'00' Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2025.04.23 16:29:43 -08'00' AIO 18E.007, 28.010, 35A.001, 40.004, and 43.002 April 24, 2025 Page 4 of 4 RECONSIDERATION AND APPEAL NOTICE As provided in AS 31.05.080(a), within 20 days after written notice of the entry of this order or decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration of the matter determined by it. If the notice was mailed, then the period of time shall be 23 days. An application for reconsideration must set out the respect in which the order or decision is believed to be erroneous. The AOGCC shall grant or refuse the application for reconsideration in whole or in part within 10 days after it is filed. Failure to act on it within 10 days is a denial of reconsideration. If the AOGCC denies reconsideration, upon denial, this order or decision and the denial of reconsideration are FINAL and may be appealed to superior court. The appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision denying reconsideration, UNLESS the denial is by inaction, in which case the appeal MUST be filed within 40 days after the date on which the application for reconsideration was filed. If the AOGCC grants an application for reconsideration, this order or decision does not become final. Rather, the order or decision on reconsideration will be the FINAL order or decision of the AOGCC, and it may be appealed to superior court. That appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision on reconsideration. In computing a period of time above, the date of the event or default after which the designated period begins to run is not included in the period; the last day of the period is included, unless it falls on a weekend or state holiday, in which event the period runs until 5:00 p.m. on the next day that does not fall on a weekend or state holiday. From:Coldiron, Samantha J (OGC) To:AOGCC_Public_Notices Subject:Area Injection Orders 18E.007, 28.010, 35A.001, 40.004, 43.002 (CPAI) Date:Thursday, April 24, 2025 9:25:00 AM Attachments:AIO18E.007_AIO28.010_AIO35A.001_AIO40.004_AIO43.002.pdf Docket Number: AIO-25-013 Making mechanical integrity testing notification requirements consistent across Colville River Unit and Greater Moose’s Tooth Unit pools Colville River Unit, Alpine Oil Pool, Qannik Oil Pool, and Nanuq Oil Pool Greater Moose’s Tooth Unit Lookout Oil Pool and Rendezvous Oil Pool Samantha Coldiron AOGCC Special Assistant Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage, AK 99501 (907) 793-1223 Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.alaska.gov ADMINISTRATIVE APPROVALS AREA INJECTION ORDER NO. 2C.096 AREA INJECTION ORDER NO. 16.009 AREA INJECTION ORDER NO. 18E.008 AREA INJECTION ORDER NO. 28.011 AREA INJECTION ORDER NO. 35A.002 AREA INJECTION ORDER NO. 39A.001 AREA INJECTION ORDER NO. 40.005 AREA INJECTION ORDER NO. 43.003 Greg Hobbs, Regulatory Engineer ConocoPhillips Alaska, Inc. P.O. Box 100360 Anchorage, AK 99510-0360 Re: Docket Number: AIO-25-001 Request to change language of Area Injection Order Rule 7 Well Integrity and Confinement Dear Mr. Hobbs: By letter dated January 15, 2025, ConocoPhillips Alaska, Inc. (CPAI) requested the amendment to Rule 7 of the Area Injection Orders listed below: •AIO 18E: Colville River Field, Colville River Unit, Alpine Oil Pool • AIO 28: Colville River Field, Colville River Unit, Nanuq Oil Pool • AIO 35A: Colville River Field, Colville River Unit, Qannik Oil Pool • AIO 39A: Kuparuk River Field, Kuparuk River Unit, Torok Oil Pool • AIO 40: Greater Moose's Tooth Field, Greater Moose's Tooth Unit, Lookout Oil Pool • AIO 43: Greater Moose's Tooth Field, Greater Moose's Tooth and Bear Tooth Units, Rendezvous Oil Pool The purpose of the amendment is to clarify the appropriate process and current practice when pressure communication, leakage or lack of injection zone isolation is indicated by certain data observed by the operator. CPAIproposed adopting the Rule 7 language from the recently approved AIO 45 Coyote Oil Pool. AIO 2C.096, AIO 16.009, AIO 18E.008, AIO 28.011, AIO 35A.002, AIO 39A.001, AIO 40.005, and AIO 43.003 May 12, 2025 Page 2 of 3 In accordance with 20 AAC 25.556(d), the Alaska Oil and Gas Conservation Commission (AOGCC) hereby GRANTS CPAI’s request to amend Rule 7 of the AIOs listed above. Additionally, on its own motion, and in accordance with 20 AAC 25.556(d), the AOGCC has determined that Rule 7 of the CPAI AIO’s listed below should also be amended for the same reasons. • AIO 2C: Kuparuk River Field, Kuparuk River Unit, Kuparuk River, West Sak, and Tabasco Oil Pools • AIO 16: Kuparuk River Field, Kuparuk River Unit, Tarn Oil Pool Now Therefore it is Ordered: Rule 7 of each of the AIO’s listed is amended to read as follows: Rule 7 Well Integrity and Confinement Whenever an indication of pressure communication, leakage, or lack of injection zone isolation occurs, the operator must notify the AOGCC by the next business day. Such indication may arise from information including but not limited to injection rate, operating pressure observation, test, survey, log, or outer anulus pressure monitoring in wells within one-quarter mile radius of where the applicable defined oil pool is not cemented. If the operator's investigation supports a conclusion of pressure communication, leaking, or lack of injection zone isolation, the operator must submit a corrective action plan to the AOGCC, following the applicable unit sundry matrix order. The operator must shut in any well for which: (a) continued operation would be unsafe, (b) continued operation would threaten contamination of freshwater; or (c) the AOGCC directs the operator to shut in the well. The operator must submit a monthly report of daily tubing and casing annuli pressures and injection rate for injection wells that (a) are subject to administrative approval (AA) to operate; or (b) lack injection zone isolation. DONE at Anchorage, Alaska and dated May 12, 2025. Jessie L. Chmielowski Gregory C. Wilson. Commissioner, Chair Commissioner Gregory C. Wilson Digitally signed by Gregory C. Wilson Date: 2025.05.12 12:12:38 -08'00' Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2025.05.12 13:42:57 -08'00' AIO 2C.096, AIO 16.009, AIO 18E.008, AIO 28.011, AIO 35A.002, AIO 39A.001, AIO 40.005, and AIO 43.003 May 12, 2025 Page 3 of 3 RECONSIDERATION AND APPEAL NOTICE As provided in AS 31.05.080(a), within 20 days after written notice of the entry of this order or decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration of the matter determined by it. If the notice was mailed, then the period of time shall be 23 days. An application for reconsideration must set out the respect in which the order or decision is believed to be erroneous. The AOGCC shall grant or refuse the application for reconsideration in whole or in part within 10 days after it is filed. Failure to act on it within 10 days is a denial of reconsideration. If the AOGCC denies reconsideration, upon denial, this order or decision and the denial of reconsideration are FINAL and may be appealed to superior court. The appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision denying reconsideration, UNLESS the denial is by inaction, in which case the appeal MUST be filed within 40 days after the date on which the application for reconsideration was filed. If the AOGCC grants an application for reconsideration, this order or decision does not become final. Rather, the order or decision on reconsideration will be the FINAL order or decision of the AOGCC, and it may be appealed to superior court. That appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision on reconsideration. In computing a period of time above, the date of the event or default after which the designated period begins to run is not included in the period; the last day of the period is included, unless it falls on a weekend or state holiday, in which event the period runs until 5:00 p.m. on the next day that does not fall on a weekend or state holiday. From:Coldiron, Samantha J (OGC) To:AOGCC_Public_Notices Subject:[AOGCC_Public_Notices] Area Injection Orders Admin Approvals (CPAI) Date:Monday, May 12, 2025 1:54:34 PM Attachments:AIO2C.096, AIO16.009, AIO18E.008, AIO28.011, AIO35A.002, AIO39A.001, AIO40.005, and AIO43.003.pdf Docket Number: AIO-25-001 Request to change language of Area Injection Order Rule 7 Well Integrity and Confinement Samantha Coldiron AOGCC Special Assistant Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage, AK 99501 (907) 793-1223 __________________________________ List Name: AOGCC_Public_Notices@list.state.ak.us You subscribed as: samantha.coldiron@alaska.gov Unsubscribe at: https://list.state.ak.us/mailman/options/aogcc_public_notices/samantha.coldiron%40alaska.go v 5 January 15, 2025 VIA E-MAIL DELIVERY Victoria Loepp Senior Petroleum Engineer Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue, Suite 100 Anchorage, Alaska 99501-3572 Subject: Area Injection Order Rule 7 Proposed Language Change Dear Ms. Loepp, ConocoPhillips Alaska Inc. (CPAI) makes this application to amend the Area Injection Orders listed below to clarify the appropriate process and current practice when pressure communication, leakage or lack of injection zone isolation is indicated by certain data observed by the operator. An example of the current area injection order language from the Alpine Area Injection Order (AIO 18E) is as follows: Whenever any pressure communication, leakage or lack of injection zone isolation is indicated by an injection rate, operating pressure observation, test, survey, log, or other evidence, the operator shall, by the next business day, notify the Commission and submit a plan of corrective action on a Form 10-403 for Commission approval. The Operator shall immediately shut in the well if continued operation would be unsafe or would threaten contamination of freshwater, or if so directed by the AOGCC. A monthly report of daily tubing and casing annuli pressures and injection rates must be provided to the AOGCC for all injection wells indicating well integrity failure or lack of injection zone isolation. There are two concerns with the current language. First, the rule requires the filing of a form 10-403 report with the AOGCC on the next business day. This does not represent current practice. Instead, the rule should require the Operator to notify the AOGCC by the next business day and file a report following the applicable AOGCC Sundry matrix only if the Operator’s investigation supports a conclusion of pressure communication, leaking, or lack of injection zone isolation. Second, the current rule requires the submission of daily tubing and casing annuli pressure for all injection wells indicating well integrity failure or lack of injection zone isolation. The current practice is not to submit this information for wells that are shut in. The shut in wells are separately tracked in the annual long-term shut-in wells report to the AOGCC. Greg Hobbs Principal Regulatory Engineer 700 G Street, ATO 1562 Anchorage, AK 99510 (907) 263-4749 (office) Greg.S.Hobbs@conocophillips.com By Samantha Coldiron at 12:09 pm, Jan 15, 2025 2 CPAI proposes the following language from the recent Coyote Oil Pool area injection order to resolve both issues: Whenever an indication of pressure communication, leakage, or lack of injection zone isolation occurs, the operator must notify the AOGCC by the next business day. Such indication may arise from information including but not limited to injection rate, operating pressure observation, test, survey, log, or outer anulus pressure monitoring in wells within one-quarter mile radius of where the COP is not cemented. If the operator’s investigation supports a conclusion of pressure communication, leaking, or lack of injection zone isolation, the operator must submit a corrective action plan to the AOGCC, following the [KRU, CRU or GMTU sundry matrix order as applicable]. The operator must shut in any well for which: (a) continued operation would be unsafe, (b) continued operation would threaten contamination of freshwater; or (c) the AOGCC directs the operator to shut in the well. The operator must submit a monthly report of daily tubing and casing annuli pressures and injection rate for injection wells that (a) are subject to administrative approval (AA) to operate; or (b) lack injection zone isolation. If acceptable, CPAI requests that the rule be modified in the following orders with appropriate reference to the applicable sundry matrix order: x AIO 18E: Colville River Field, Colville River Unit, Alpine Oil Pool x AIO 28: Colville River Field, Colville River Unit, Nanuq Oil Pool x AIO 35A: Colville River Field, Colville River Unit, Qannik Oil Pool x AIO 39A: Kuparuk River Field, Kuparuk River Unit, Torok Oil Pool x AIO 40: Greater Moose’s Tooth Field, Greater Moose’s Tooth Unit, Lookout Oil Pool x AIO 43: Greater Moose’s Tooth Field, Greater Moose’s Tooth and Bear Tooth Units, Rendezvous Oil Pool CPAI appreciates your consideration of this request. Feel free to contact me at 907-263-4749 or greg.s.hobbs@conocophillips.com with any questions. Sincerely, Greg Hobbs Regulatory Engineer ConocoPhillips Alaska, Inc. Digitally signed by Greg Hobbs DN: OU=Regulatory Engineer, O= ConocoPhillips Alaska Wells, CN=Greg Hobbs, E=greg.s.hobbs@ conocophillips.com Reason: I am the author of this document Location: Date: 2025.01.15 10:49:29-09'00' Foxit PDF Editor Version: 13.0.0 Greg Hobbs 4 Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.alaska.gov ADMINISTRATIVE APPROVAL ENHANCED RECOVERY INJECTION ORDER 6.002 Mr. Ian Ramshaw Manager, WNS Development ConocoPhillips Alaska, Inc. P.O. Box 100360 Anchorage, AK 99510-0360 Re: Docket Number: AIO-23-019 Request to terminate Enhanced Recovery Injection Order 6 Colville River Unit Dear Mr. Ramshaw: By letter dated July 17, 2023, ConocoPhillips Alaska, Inc. (CPAI) requested that the vertical limits of Area Injection Order 35 (AIO 35) be expanded and that additional enhanced oil recovery (EOR) injection fluids be authorized. CPAI also requested that Enhanced Recovery Injection Order No. 6 (ERIO 6) be terminated. In accordance with 20 AAC 25.556(d), the Alaska Oil and Gas Conservation Commission (AOGCC) hereby GRANTS CPAI’s request to terminate ERIO 6. ERIO 6 authorized a pilot EOR project in the Narwhal reservoir in the Colville River Unit (CRU). CPAI requested that the vertical limits of the injection interval of AIO 35 be expanded. The proposed expansion would bring the Narwhal reservoir into the area and vertical limits of the expanded AIO 35. The AOGCC approved CPAI’s request to expand the vertical limits of the injection interval specified in AIO 35 on December 19, 2023, and as such ERIO 6 is no longer needed to allow CPAI to continue injection into the Narwhal reservoir so ERIO 6 and its administrative approvals can be terminated. NOW THERFORE IT IS ORDERED Enhanced Recovery Injection Order No. 6 is terminated. ERIO 6.002 December 19, 2023 Page 2 of 2 DONE at Anchorage, Alaska and dated December 19, 2023. Brett W. Huber, Sr Jessie L. Chmielowski Gregory C. Wilson Chair, Commissioner Commissioner Commissioner RECONSIDERATION AND APPEAL NOTICE As provided in AS 31.05.080(a), within 20 days after written notice of the entry of this order or decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration of the matter determined by it. If the notice was mailed, then the period of time shall be 23 days. An application for reconsideration must set out the respect in which the order or decision is believed to be erroneous. The AOGCC shall grant or refuse the application for reconsideration in whole or in part within 10 days after it is filed. Failure to act on it within 10 days is a denial of reconsideration. If the AOGCC denies reconsideration, upon denial, this order or decision and the denial of reconsideration are FINAL and may be appealed to superior court. The appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision denying reconsideration, UNLESS the denial is by inaction, in which case the appeal MUST be filed within 40 days after the date on which the application for reconsideration was filed. If the AOGCC grants an application for reconsideration, this order or decision does not become final. Rather, the order or decision on reconsideration will be the FINAL order or decision of the AOGCC, and it may be appealed to superior court. That appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision on reconsideration. In computing a period of time above, the date of the event or default after which the designated period begins to run is not included in the period; the last day of the period is included, unless it falls on a weekend or state holiday, in which event the period runs until 5:00 p.m. on the next day that does not fall on a weekend or state holiday. Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2023.12.19 09:05:01 -09'00' Brett W. Huber, Sr. Digitally signed by Brett W. Huber, Sr. Date: 2023.12.19 10:32:32 -09'00' Gregory Wilson Digitally signed by Gregory Wilson Date: 2023.12.19 12:50:03 -09'00' From:Christianson, Grace K (OGC) To:AOGCC_Public_Notices Subject:[AOGCC_Public_Notices] ERIO 6.002 and AIO 35A (CPAI) Date:Wednesday, December 20, 2023 2:52:34 PM Attachments:aio35A.pdf ERIO 6.002.pdf Request to terminate Enhanced Recovery Injection Order 6 Colville River Unit And THE APPLICATION OF CONOCOPHILLIPS ALASKA, INC. to expand the authorized injection interval for underground injection of fluids for enhanced oil recovery in the Qannik Oil Pool and to terminate Enhanced Recovery Injection Order 6, Colville River Unit, Arctic Slope, Alaska Best, Grace Christianson Executive Assistant Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage, AK 99501 907-793-1230 CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska, and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use, or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it without first saving or forwarding it, and so that the AOGCC is aware of the mistake in sending it to you, contact Grace Christianson at (907-793-1230 ) or (grace.christianson@alaska.gov). __________________________________ 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 3 Lisi Misa being first duly sworn on oath deposes and says that she is a representative of the An- chorage Daily News, a daily newspaper. That said newspaper has been approved by the Third Judicial Court, Anchorage, Alaska, and it now and has been published in the English language continually as a daily newspaper in Anchorage, Alaska, and it is now and during all said time was printed in an office maintained at the afore- said place of publication of said newspaper. That the annexed is a copy of an advertisement as it was published in regular issues (and not in supplemental form) of said newspaper on AFFIDAVIT OF PUBLICATION ______________________________________ Notary Public in and for The State of Alaska. Third Division Anchorage, Alaska MY COMMISSION EXPIRES ______________________________________ 08/03/2023 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 4th day of August 2023. Account #: 100869 ST OF AK/AK OIL AND GAS CONSERVATION COMMISSION333 W. 7TH AVE STE 100, ANCHORAGE, AK 99501 Order #: W0039764 Cost: $321.1 Notice of Public HearingSTATE OF ALASKAALASKA OIL AND GAS CONSERVATION COMMISSION RE: Docket Number: AIO-23-019By application dated July 17, 2023, ConocoPhillips Alaska, Inc. (CPAI) requests that the Alaska Oil and Gas Conservation Commission (AOGCC) expand the vertical limits of the authorized injection interval associated with the Qannik Oil Pool (QOP) in the Colville River Unit. Area Injection Order (AIO) 35 prescribes rules for the injection of fluids into the QOP for the purpose of enhanced oil recovery (EOR). CPAI proposes to amend this order to expand the vertical limits of the interval authorized for enhanced oil recovery to match the limits of the QOP as defined in Conservation Order 605A, which was issued on March 17, 2020. The application also seeks to add enriched gas to the list of fluids approved for EOR injection under the AIO. If adopted the proposed amendments would have the affect of superseding Enhanced Recovery Injection Order 6, which authorized a pilot EOR project on a portion of the QOP. This notice does not contain all the information filed by CPAI. To obtain more information, contact the AOGCC’s Special Assistant, Samantha Carlisle, at (907) 793-1223 or samantha.carlisle@alaska.gov. A public hearing on the matter has been tentatively scheduled for September 5, 2023, 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: 136 199 493#. Anyone who wishes to participate remotely using MS Teams video conference should contact Ms. Carlisle at least two business days before the scheduled public hearing to request an invitation for the MS Teams. To request that the tentatively scheduled hearing be held, a written request must be filed with the AOGCC no later than 4:30 p.m. on August 18, 2023. If a request for a hearing is not timely filed, the AOGCC may issue an order without a hearing. To learn if the AOGCC will hold the hearing, call (907) 793-1223 after August 21, 2023. 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 4:30 p.m. on September 1, 2023, except that, if a hearing is held, comments must be received no later than the conclusion of the September 5, 2023, hearing. If, because of a disability, special accommodations may be needed to comment or attend the hearing, contact Samantha Carlisle, at (907) 793-1223, no later than August 29, 2023. Brett W. Huber, Sr. Chair, Commissioner Pub: Aug. 3, 2023 STATE OF ALASKA THIRD JUDICIAL DISTRICT 2024-07-14 Document Ref: ZXKMZ-VCU8J-FKVZD-W8ESE Page 23 of 26 2 Notice of Public Hearing STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION RE: Docket Number: AIO23-019 By application dated July 17, 2023, ConocoPhillips Alaska, Inc. (CPAI) requests that the Alaska Oil and Gas Conservation Commission (AOGCC) expand the vertical limits of the authorized injection interval associated with the Qannik Oil Pool (QOP) in the Colville River Unit. Area Injection Order (AIO) 35 prescribes rules for the injection of fluids into the QOP for the purpose of enhanced oil recovery (EOR). CPAI proposes to amend this order to expand the vertical limits of the interval authorized for enhanced oil recovery to match the limits of the QOP as defined in Conservation Order 605A, which was issued on March 17, 2020. The application also seeks to add enriched gas to the list of fluids approved for EOR injection under the AIO. If adopted the proposed amendments would have the affect of superseding Enhanced Recovery Injection Order 6, which authorized a pilot EOR project on a portion of the QOP. This notice does not contain all the information filed by CPAI. To obtain more information, contact the AOGCC’s Special Assistant, Samantha Carlisle, at (907) 793-1223 or samantha.carlisle@alaska.gov. A public hearing on the matter has been tentatively scheduled for September 5, 2023, 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: 136 199 493#. Anyone who wishes to participate remotely using MS Teams video conference should contact Ms. Carlisle at least two business days before the scheduled public hearing to request an invitation for the MS Teams. To request that the tentatively scheduled hearing be held, a written request must be filed with the AOGCC no later than 4:30 p.m. on August 18, 2023. If a request for a hearing is not timely filed, the AOGCC may issue an order without a hearing. To learn if the AOGCC will hold the hearing, call (907) 793-1223 after August 21, 2023. 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 4:30 p.m. on September 1, 2023, except that, if a hearing is held, comments must be received no later than the conclusion of the September 5, 2023, hearing. If, because of a disability, special accommodations may be needed to comment or attend the hearing, contact Samantha Carlisle, at (907) 793-1223, no later than August 29, 2023. Brett W. Huber, Sr. Chair, Commissioner Brett W. Huber, Sr. Digitally signed by Brett W. Huber, Sr. Date: 2023.08.01 15:31:44 -08'00' From:Carlisle, Samantha J (OGC) To:AOGCC_Public_Notices Subject:[AOGCC_Public_Notices] Public Hearing Notice, Docket Number: AIO-23-019 (CPAI) Date:Tuesday, August 1, 2023 3:54:30 PM Attachments:AIO-23-019 Public Hearing Notice CPAI QOP.pdf Docket Number: AIO-23-019 By application dated July 17, 2023, ConocoPhillips Alaska, Inc. (CPAI) requests that the Alaska Oil and Gas Conservation Commission (AOGCC) expand the vertical limits of the authorized injection interval associated with the Qannik Oil Pool (QOP) in the Colville River Unit. Samantha Carlisle Special Assistant Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage, AK 99501 (907) 793-1223 __________________________________ List Name: AOGCC_Public_Notices@list.state.ak.us You subscribed as: samantha.carlisle@alaska.gov Unsubscribe at: https://list.state.ak.us/mailman/options/aogcc_public_notices/samantha.carlisle%40alaska.gov 1 July 17, 2023 Jessie Chmielowski, Chair Alaska Oil and Gas Conservation Commission 333 W. 7th Ave #100 Anchorage, Alaska, 99501-3539 RE: Application for Expansion of the Area Injection Order, Qannik Oil Pool, North Slope, AK Dear Commissioner Chmielowski: In accordance with 20 ACC 25.402 (Enhanced Recovery Operations) and 20 AAC 25.460 (Area Injection Orders), ConocoPhillips Alaska, Inc. (“CPAI”) as operator of the Colville River Unit (“CRU”) requests that the Alaska Oil and Gas Conservation Commission ("AOGCC") approve CPAI’s application for an expansion to Area Injection Order (“AIO”) 35. This amendment seeks a vertical expansion of the injection interval approved within the Qannik Oil Pool (“QOP”). This would allow enhanced recovery to be performed within the Narwhal reservoir, maximizing recovery from existing and future development wells. This amendment also includes the addition of enriched gas injectant to further enhance recovery via water-alternating-gas (“WAG”) flood in the Narwhal reservoir wells only. CPAI requests that the hearing date for this application be scheduled as soon as possible after the 30-day public notice period has concluded. Enclosed are two printed originals of the application. Please contact Jennifer Crews (907-265-6820, jennifer.r.crews@conocophillips.com) if you have questions or require additional information. Regards, Ian Ramshaw Manager, WNS Development CC: Derek Nottingham, Alaska Department of Natural Resources, Division of Oil and Gas Erik Kenning, Arctic Slope Regional Corporation Ian Ramshaw Manager, WNS Development North Slope Development ConocoPhillips Alaska, Inc. P.O. Box 100360 Anchorage, AK 99510-0360 Phone 907.263.4464 Signed on Behalf of By Samantha Carlisle at 2:48 pm, Jul 17, 2023 Application to the AOGCC for Approval of Expansion of Qannik Area Injection Order Colville River Unit Page 2 ConocoPhillips Alaska, Inc. Application to the Alaska Oil and Gas Conservation Commission for Approval of Expansion of the Qannik Area Injection Order to Include Narwhal Reservoir Colville River Unit ConocoPhillips Alaska, Inc. July 14, 2023 Application to the AOGCC for Approval of Expansion of Qannik Area Injection Order Colville River Unit Page 3 ConocoPhillips Alaska, Inc. Table of Contents Introduction ............................................................................................................................................................................................ 4 20 AAC 25.402 (c)(1) Plat of Wells Penetrating Injection Zone .......................................................................................... 6 20 AAC 25.402 (c)(2) Operators and Surface Owners within One Quarter Mile of Injection Operations ......... 9 20 AAC 25.402 (c)(3) Affidavit of Dennise Arzola Regarding Notice to Surface Owners ...................................... 10 20 AAC 25.402 (c)(4) Description of the Proposed Operation ........................................................................................ 11 20 AAC 25.402 (c)(5) Description and Depth of Pool to be Affected ........................................................................... 12 20 AAC 25.402 (c)(6) Description of the Formation ............................................................................................................. 14 20 AAC 25.402 (c)(7) Logs of the Injection Wells .................................................................................................................. 19 20 AAC 25.402 (c)(8) Casing Description and Proposed Method for Testing ........................................................... 20 20 AAC 25.402 (c)(9) Injection Fluid Analysis and Injection Rates ................................................................................. 23 20 AAC 25.402 (c)(10) Injection Pressures ............................................................................................................................... 25 20 AAC 25.402 (c)(11) Fracture Information ........................................................................................................................... 26 20 AAC 25.402 (c)(12) Quality of Formation Water ............................................................................................................. 29 20 AAC 25.402 (c)(13) Aquifer Exemption Reference .......................................................................................................... 30 20 AAC 25.402 (c)(14) Incremental Hydrocarbon Recovery ............................................................................................. 31 20 AAC 25.402 (c)(15) Mechanical Condition of Wells Within ¼ Mile of Proposed Area .................................... 32 Proposed Area Injection Order Rules ........................................................................................................................................ 33 List of Figures Figure 1: Proposed Qannik/Narwhal AIO 35 Expansion Area (same as QOP area).................................................... 7 Figure 2: Map with Narwhal and Qannik Well Penetrations and Proposed and Existing Narwhal and Qannik Horizontal Wells with ¼ Mile Circle/Tangent radii in the CD4 Narwhal injection area. ................................. 8 Figure 3: CD2-11 Type Log. Notetab Narwhal is non-reservoir in this type log. ..................................................... 13 Figure 4: CD2-11 Qannik type log and Qugruk 3 supplemental representative well log showing Narwhal reservoir. ...................................................................................................................................................................................... 15 Figure 5: Top Narwhal depth structure map. ......................................................................................................................... 17 Figure 6: CD4-597 Injector Wellbore Schematic ................................................................................................................... 22 Figure 7: Fracture Gradient plot for upper confining interval and reservoir.............................................................. 27 Figure 8: Narwhal Injection Model Results. ............................................................................................................................. 28 List of Tables Table 1: Affected Land (Umiat Meridian, Alaska) .................................................................................................................. 12 Table 2: CD4-595 PVT Summary ................................................................................................................................................. 18 Table 3: Reservoir DFIT data showing fracture initiation and fracture closure pressure for the Putu 2A well (vertical well) and CD4-595 well (horizontal well) and associated fracture gradients. ................................. 18 Table 4: Nanuk #2 produced water sample analysis. .......................................................................................................... 29 Table 5: Qannik wells within 1/4 mile of proposed injection. .......................................................................................... 32 Attachments CD4-597 Log CD4-597 Well Completion Report (AOGCC Form 10-407) Application to the AOGCC for Approval of Expansion of Qannik Area Injection Order Colville River Unit Page 4 ConocoPhillips Alaska, Inc. Introduction This application is submitted for approval by the AOGCC to establish area injection Rules pursuant to 20 ACC 25.402 (Enhanced Recovery Operations) and 20 AAC 25.460 (Area Injection Orders) for the expanded Qannik Oil Pool (“QOP”) described in Conservation Order 605A. CPAI submits this application to the AOGCC in its capacity as Operator and 100% working interest owner of the producing intervals in the CRU. The purpose of this application is to seek endorsement and authorization from the AOGCC for area injection rules for the expanded QOP that includes: 1) Vertical expansion of AIO 35 to allow injection operations into the Narwhal Reservoir within the QOP 2) Addition of enriched gas injection as an approved injection fluid, enabling water- alternating-gas (”WAG”) flood to maximize hydrocarbon recovery from the Narwhal Reservoir The original QOP was established through CO 605 effective June 2008. When originally established, the QOP included the accumulation of hydrocarbons common to, and correlating with, the interval between the measured depths of 6,086’ and 6,249’ on the Electromagnetic Wave Resistivity (“EWR”) log recorded in well CRU CD2-11. The existing AIO to inject fluids for enhanced oil recovery from the QOP was granted July 2008 as AIO 35. The expansion of AIO 35 is necessary to provide for injecting produced water, seawater and gas into the Narwhal reservoir (defined below in the section titled “20 AAC 25.402 (c)(5) Description and Depth of Pool to be Affected” on p. 12). A “pilot” water injection project for up to 2 injectors in the Narwhal reservoir, authorized by ERIO-06, is presently in place in the proposed amended AIO area as depicted in Figure 1. The production associated with ERIO-06 is now within the QOP, and the pilot period is nearing conclusion. CPAI would like to vertically expand AIO 35 governing injection within the Qannik Oil Pool so that it matches the QOP expansion approved in CO 605A. Once AIO 35 is expanded, CPAI proposes that ERIO-06 be terminated. The Narwhal reservoir is presently being developed from the CD4 drill pad. In June 2019, the CD4-595 exploration well (within the CRU) was drilled to gather information on the drilling, completion, and production of the Narwhal interval. In December 2019, the CD4- 594 complementary injector was drilled to further evaluate reservoir connectivity, and a Application to the AOGCC for Approval of Expansion of Qannik Area Injection Order Colville River Unit Page 5 ConocoPhillips Alaska, Inc. pilot enhanced recovery injection order was approved by the AOGCC (ERIO-06) in December 2019. Injection from CD4-594 commenced in February 2020. In March 2020, the QOP was vertically expanded to include the hydrocarbons common to and correlating with the interval between the measured depths of 6,030’ and 6,249’ on the EWR log recorded in well CD2-11, effectively the updip non-reservoir Narwhal interval, which thickens and develops hydrocarbon-bearing, reservoir-quality, sandstone beds of the Narwhal reservoir to the southeast from CD4 drill pad within the vertical expansion area. Planned development of the Narwhal reservoir from the CD4 drill pad includes four wells to be drilled in 2023/2024, two producers and two injectors, with future additional wells dependent upon drilling and production results. The development design for the Narwhal reservoir is planned to be a line-drive water alternating gas (“WAG”) flood with horizontal producers and injectors drilled along the maximum principal stress. The boundaries of the current QOP are shown on Figure 1 along with the present CRU Boundary. CPAI requests that AIO 35 be amended to match the vertically expanded QOP area, and AIO 35 be modified to allow for water alternating gas injection in the Narwhal reservoir. Development of the Qannik reservoir will continue to be by waterflood only. Application to the AOGCC for Approval of Expansion of Qannik Area Injection Order Colville River Unit Page 6 ConocoPhillips Alaska, Inc. 20 AAC 25.402 (c)(1) Plat of Wells Penetrating Injection Zone The map shown in Figure 1 depicts the existing CD4-594 and CD4-597 injection wells penetrating the injection zone in the proposed Narwhal reservoir injection area. The map also shows the areal extent of the Qannik Oil Pool (“QOP”), including all Qannik injectors and producers relative to the Narwhal reservoir development area. Figure 2 depicts the existing Narwhal injection wells (covered by ERIO-06) as well as the proposed Narwhal injection wells that are planned to penetrate the injection zone. A ¼ mile radius around each injection lateral is displayed. Application to the AOGCC for Approval of Expansion of Qannik Area Injection Order Colville River Unit Page 7 ConocoPhillips Alaska, Inc. Figure 1: Proposed Qannik/Narwhal AIO 35 Expansion Area (same as QOP area). Application to the AOGCC for Approval of Expansion of Qannik Area Injection Order Colville River Unit Page 8 ConocoPhillips Alaska, Inc. Figure 2: Map with Narwhal and Qannik Well Penetrations and Proposed and Existing Narwhal and Qannik Horizontal Wells with ¼ Mile Circle/Tangent radii in the CD4 Narwhal injection area. Application to the AOGCC for Approval of Expansion of Qannik Area Injection Order Colville River Unit Page 9 ConocoPhillips Alaska, Inc. 20 AAC 25.402 (c)(2) Operators and Surface Owners within One Quarter Mile of Injection Operations Operator: ConocoPhillips Alaska, Inc. Attn: Ryan J. Sustakoski PO Box 100360 Anchorage, AK 99510-0360 Offset Operator: Oil Search (Alaska), LLC Attn: Tim Jones PO Box 240927 Anchorage, AK 99524-0927 Surface Owners: Kuukpik Corporation Attn: Joseph Nukapigak, Sr. PO Box 89187 Nuiqsut, AK 99789-0187 Alaska Department of Natural Resources Division of Oil and Gas Attn: Derek Nottingham, Director 550 West 7th Ave., Suite 1100 Anchorage, AK 99501-3563 Application to the AOGCC for Approval of Expansion of Qannik Area Injection Order Colville River Unit Page 11 ConocoPhillips Alaska, Inc. 20 AAC 25.402 (c)(4) Description of the Proposed Operation This application to the Alaska Oil and Gas Conservation Commission (“AOGCC”) seeks to vertically expand Area Injection Order 35 to include the Narwhal horizon and seeks approval for water alternating gas injection in the Narwhal reservoir. Development of the Qannik reservoir from the CD2 drill pad will continue to be waterflood only. The QOP is currently developed from two drill sites in the CRU, CD2 and CD4. Development of the Narwhal reservoir within the QOP is planned at CD4. All wells will be produced to the Alpine Central Facility (“ACF”). The current and planned development at CD4 is within the expanded QOP vertical pool boundary. Secondary and tertiary recovery will be important to maximize recovery from this expanded portion of the pool. Current plans for the Narwhal reservoir development from CD4 are for drilling four wells, two producers and two injectors, in addition to the existing CD4-594 and CD4-597 injectors supporting the CD4-595 producer. Based on current information, the optimum spacing for WAG for the Narwhal reservoir is 1,800'. CPAI’s analysis is ongoing and may change with additional development data. Unitized substances produced from the QOP will be commingled on the surface with substances from the existing Alpine Oil Pool (“AOP”). The same process that is used to allocate unitized substances for the AOP will be used to allocate production for the QOP. Allocation will be based on periodic well tests and producing conditions such as up time. Injection allocation for all pools are based on meters on each injection well. Application to the AOGCC for Approval of Expansion of Qannik Area Injection Order Colville River Unit Page 12 ConocoPhillips Alaska, Inc. 20 AAC 25.402 (c)(5) Description and Depth of Pool to be Affected The vertical limits of the proposed AIO 35 expansion are to be consistent with the Qannik Oil Pool (“QOP”) that was expanded to include the Narwhal interval above the Qannik reservoir in 2020, defined as the strata common to, and correlating with, the interval between True Vertical Depth Sub Sea limits of -3,896 – -4,099 feet with a corresponding Measured Depth of 6,030 – 6,249 feet on the EWR recorded in well CRU CD2-11 (Figure 3). As shown on Figure 1, the injection area proposed for the QOP AIO expansion is the entire expanded QOP, which is within the following land: Table 1: Affected Land (Umiat Meridian, Alaska) Township, Range Sections (All) T10N, R04E 1 – 4 T10N, R05E 4 – 6 T11N, R04E 1 – 4, 9 – 16, 21 – 28, 33 – 36 T11N, R05E 4 – 9, 16 – 21, 28 – 33 T12N, R04E 1 – 4, 9 – 16, 21 – 28, 33 – 36 T12N, R05E 4 – 9, 16 – 21, 28 – 33 Application to the AOGCC for Approval of Expansion of Qannik Area Injection Order Colville River Unit Page 13 ConocoPhillips Alaska, Inc. Figure 3: CD2-11 Type Log. Note Narwhal is non-reservoir in this type log. Application to the AOGCC for Approval of Expansion of Qannik Area Injection Order Colville River Unit Page 14 ConocoPhillips Alaska, Inc. 20 AAC 25.402 (c)(6) Description of the Formation Stratigraphy and Sedimentology The Narwhal interval directly overlies the Qannik interval, but is not reservoir quality in the existing Qannik development area. The Narwhal interval is poorly developed in the CD2-11 QOP type log in the primary Qannik development area (CD2 pad), which, for Qannik reservoir, is a shelfal stratigraphic position. A representative stratigraphic section for the Narwhal reservoir, including the CD4 pad area, is the Qugruk 3 supplemental reservoir log with True Vertical Depth Sub Sea limits of -4,068 – -4,971 feet and corresponding measured depths of 4,192 – 5,152 feet. Figure 4 highlights the change from poorly developed Narwhal within the Qannik development area (CD2-11 type log) compared with the well-developed Narwhal reservoir at the Qugruk 3 location. The Late Cretaceous Narwhal sandstone represents a north-south elongate, eastward prograding deltaic marine sand that are age-equivalent to the Nanushuk Group. The Narwhal sands in the CRU represent a Brookian topset play in which thick deltaic marine sands (up to 800 ft gross sand) are trapped structurally-stratigraphically within at least three clinothems. The Qannik reservoir is confined to the shelf and is contained within its own separate clinothem (K-2). Over the length of the field, the Narwhal extends for approximately 35 miles parallel to depositional strike (north-south) and five miles in a depositional dip direction. Up-dip, to the west, these sands pinch-out due to either onlap or truncation beneath a ravinement surface. Narwhal reservoir development is at or near the shelf edge. In contrast, the Qannik reservoir is deposited as top-set beds in a shallow, north-trending, eastward-migrating marine shelf environment (up to 35’ gross sand). Qannik reservoir extent is approximately 12 miles along depositional strike (north-south) and 6 miles shelf along depositional dip with degrading reservoir quality from west to the east toward the shelf edge. One Qannik well has been drilled from CD4 pad, the CD4-499 horizontal producer. As the Qannik reservoir shaled out, the well toed up into the Narwhal, confirming the expansion of Narwhal reservoir at the shelf edge. The Narwhal reservoir has been penetrated by approximately 5 wells in the CRU and over 10 wells in the vicinity of the CRU and Pikka Units. There is no Narwhal core data within the QOP. The Putu 2A well, to the East of the QOP, is a good representation of the reservoir properties of the Narwhal reservoir at CD4. The range of core properties from the Putu 2A well in the net sand are 21-22% average porosity, 10-123 millidarcies air permeability, and 23-42% water saturation. The sands are lower very fine to lower fine- grained lithic arenites with average compositions of 53% quartz, 16% feldspar, and 31% lithics. Sands with porosities of less than 15% are generally non-pay. Application to the AOGCC for Approval of Expansion of Qannik Area Injection Order Colville River Unit Page 15 ConocoPhillips Alaska, Inc. Figure 4: CD2-11 Qannik type log and Qugruk 3 supplemental representative well log showing Narwhal reservoir. Structure and Trap Configuration Well log and seismic information indicate that both the Qannik and Narwhal reservoirs are stratigraphic traps, with Qannik truncating to the west and shaling out to the east. In the primary Qannik development area, no seismically mappable faults are present. The Qannik (K-2) structure is very low relief and sits approximately 50’ TVD deeper than the top Narwhal on the shelf. To the east, in the Narwhal development area, the Narwhal reservoir expands and the non-reservoir, shaly K-2 is approximately 200’ TVD structurally deeper than the top Narwhal. The top composite Narwhal structure elevation ranges from -3,950 SSTVD to -5,500 SSTVD as depicted below in Figure 5. Structural dips between wells generally range from 1-5 degrees. The Narwhal accumulation is a structural-stratigraphic trap. Well data suggests a hydrocarbon column greater than 600 feet. Application to the AOGCC for Approval of Expansion of Qannik Area Injection Order Colville River Unit Page 16 ConocoPhillips Alaska, Inc. Analysis of 3D seismic identified one NNE oriented normal fault that intersects the deeper Qannik and shallower Narwhal reservoirs at CD4 (Figure 5). This fault is present within the Qannik reservoir in the CD4-499 producer. This fault is approximately 0.81 miles to the west of the CD4 planned development area and thus injection pressure is not expected to affect the fault with ongoing production offtake. The fault is currently sealing as evidenced by the presence of the adjacent Narwhal and Qannik hydrocarbon columns, and the high clay content in the overburden provides high seal capacity. The fault stability was investigated using a coupled geomechanical model to test injection pressures in line with the premised maximum injection pressures for CD4 Narwhal and the fault shows no indication of failure in the top seal. It is possible that smaller, sub- seismic faults may exist in the reservoir, but these are not expected to impact planned injection operations in the area. Confining Zones Upper and lower confining zones for both the Qannik and Narwhal reservoirs are the same and are shown on the logs in Figure 4. Upper Confining Interval The upper confining interval consists of the Seabee Formation (Fm) from C-30 marker to the K-3 marker and the Cretaceous Nanushuk Group from the K-3 marker to the top of the Narwhal reservoir. The Seabee Fm consists of primarily claystone with occasional siltstone and the base is a shale-dominated marine flooding surface comprised of condensed mudstone facies. Intermittent volcanic tuffaceous bentonite interbeds are also found within the Seabee. The Nanushuk Group consists of claystone with thin siltstone beds. Total thickness of the upper confining interval varies from 1,580-1,700 ft TVD. Lower Confining Interval The lower confining interval is the Torok Fm and consists of marine mudstones and shales deposited in a slope setting. Thickness varies from 20-100 ft TVD. Application to the AOGCC for Approval of Expansion of Qannik Area Injection Order Colville River Unit Page 17 ConocoPhillips Alaska, Inc. Figure 5: Top Narwhal depth structure map. The oil accumulation of the Narwhal reservoir is clipped to the west-northwest by the gas- oil contact (GOC), and by a stratigraphic pinchout with degradation in quality of the sands to the northwest. Narwhal oil bearing sands continue south and east of CD4 pad. Narwhal Reservoir Fluids The Narwhal reservoir fluids are similar to that of the Qannik reservoir fluids. API gravity is 27-31 degrees. Geochemical analyses from CD4-595 wellhead samples indicate that the black oil is interpreted to be sourced from the calcareous facies of the Shublik and the light hydrocarbon components from Jurassic shales. Pressure-Volume-Temperature (“PVT”) test results for the CD4-595 downhole samples are summarized in Table 2. Gas-oil ratio, relative oil volume, and API gravity data are reported for differential liberation tests at reservoir conditions. Application to the AOGCC for Approval of Expansion of Qannik Area Injection Order Colville River Unit Page 18 ConocoPhillips Alaska, Inc. Table 2: CD4-595 PVT Summary Well CD4-595 Zone(s) Narwhal Viscosity (cp) @ Reservoir Temp & Press 3.486 Solution GOR (SCF/STB) 376 Relative Oil Volume (RB/STB) 1.173 Oil Gravity (degrees API at 60 °F) 26.8 Additional geological and geophysical work and studies are planned to be conducted. From the geophysical perspective, both fluid and rock property effects on the Narwhal seismic response will be examined. A static geological model is presently being constructed incorporating updated structural mapping, additional log data, and the drilling and test results from existing Narwhal wells. This geocellular model will provide the framework and property distributions for a new simulation model that will be used in updating and refining volumetrics and reserves distribution. Rock Mechanics The mechanical properties of the reservoir were collected using diagnostic fracture injection tests (DFITs) collected prior to hydraulic stimulation for the production tests on Putu 2A and CD4-595 (Table 3). These DFITs were used to measure the fracture initiation pressure of the reservoir rock (represented by instantaneous shut in pressure (“ISIP”)), and the fracture closure pressure (Pc, shmin). The former is important for determining the pressure required for injection in a non-stimulated well, while the latter is used to constrain the injection in a propped fracture so the proppant pack remains intact. A fracture gradient (“FG”) for the Narwhal reservoir is determined to be between 0.56- 0.63psi/ft. Table 3: Reservoir DFIT data showing fracture initiation and fracture closure pressure for the Putu 2A well (vertical well) and CD4-595 well (horizontal well) and associated fracture gradients. Well Depth (ft TVD, mid perf) Depth (ft MD) Sand ISIP (psi) Pc (psi) FG (psi/ft) Putu 2A 4,364 4,364 Central, Eastern 2,710 2,410 – 2,473 0.56 CD4-595 4,432 18,997 Lefty – First Stage 2,848 2,786 – 2,806 0.63 Application to the AOGCC for Approval of Expansion of Qannik Area Injection Order Colville River Unit Page 19 ConocoPhillips Alaska, Inc. 20 AAC 25.402 (c)(7) Logs of the Injection Wells CD4-594 and CD4-597 well logs have been sent to the Commission in accordance with applicable AOGCC regulations. CD4-588 is currently in progress and well logs and data will be submitted to the Commission upon completion of the well in accordance with applicable AOGCC regulations. Application to the AOGCC for Approval of Expansion of Qannik Area Injection Order Colville River Unit Page 20 ConocoPhillips Alaska, Inc. 20 AAC 25.402 (c)(8) Casing Description and Proposed Method for Testing All injection into the Narwhal wells within the expanded area of the QOP will be through wells permitted as injection wells in conformance with 20 AAC 25.005, or approved conversion to service wells in conformance with 20 AAC 25.280. A general Narwhal injector wellbore schematic is included as Figure 6. The QOP will be accessed from wells directionally drilled from gravel pads utilizing drilling procedures, well designs, casing and cementing programs consistent with current drilling practices. Primary, secondary, and general well control for drilling and completion operations will be performed in accordance with 20 AAC 25 Articles 01 and 06. Casing and cementing will be performed in accordance with 20 AAC 25.030. Existing injection wells into the QOP and their construction design are on file with the Commission. Existing wells are the same design as described below except they may have been cemented to the depths in accordance with AOGCC regulations at the time of construction. For proper anchorage and to divert an uncontrolled flow, 16 or 20-inch conductor casing will be drilled and cemented at least 75 feet below pad. Cement returns to surface will be verified by visual inspection. A diverter system compliant with the Commission requirements may be installed on the conductor. Surface casing will be set approximately 20 feet TVD above the C30 marker in the Colville Group and cemented back to surface. The intermediate hole section/s will be drilled with one or two intervals. The intermediate 1 section, in a one intermediate well design, will run from the surface casing shoe to either just above the top of the target reservoir sand or within the target reservoir sand. Casing will be run from surface and cemented. Top of cement will extend a minimum of 500 feet measured depth or 250 feet true vertical depth, whichever is greater, or the permitted length approved in the Permit to Drill, above the shoe or highest hydrocarbon bearing zone, in accordance with 20 AAC 25.030(d)(5). The intermediate 1 section, in a two intermediate well design, will run from the surface casing shoe to approximately 450 feet TVD below the top C10 marker. Casing will be run from surface and cemented. Top of cement will extend a minimum of 500 feet measured depth or 250 feet true vertical depth, whichever is greater, above the shoe or highest hydrocarbon bearing zone, whichever is higher, in accordance with 20 AAC 25.030(d)(5). Log analysis of the C10 at CD4 does not indicate any net pay in this interval. Each new Application to the AOGCC for Approval of Expansion of Qannik Area Injection Order Colville River Unit Page 21 ConocoPhillips Alaska, Inc. well will be evaluated as drilled and a stage cement job will be performed within the C10 if net pay is encountered. The intermediate 2 section, in a two intermediate well design, will run from the intermediate 1 shoe to either near the top of the target reservoir sand, but not within it, or within the target reservoir sand. Liner will be run and cemented. Top of cement will extend a minimum of 500 feet measured depth or 250 feet true vertical depth, whichever is greater, or the permitted length approved in the Permit to Drill, above the shoe or highest hydrocarbon bearing zone, in accordance with 20 AAC 25.030(d)(5). The target reservoir sand will be drilled horizontally and completed with uncemented liners with frac sleeves and swell packers with liner top hanger and packer or uncemented pre-perforated liners with liner top hanger and packer. External Swell packers will be added to provide zonal control of injection fluids or to isolate pay excursions and/or fault crossings. The well will be completed with 4-1/2 inch or 3-1/2 inch tubing based on expected flow rates. In lieu of the packer depth requirement under 20 AAC 25.412(b), CPAI requests that the packer/isolation equipment depth for injection wells may be located greater than 200 feet measured depth above the top of the perforations/open interval but shall not be located above the confining zone and shall be located where the casing section has competent cement behind it. The tubing/casing annulus pressure of each injection well will be tested in accordance with 20 ACC 25.412(c). Drilling and completion operations will be performed in accordance with 20 AAC 25. 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 into the approved interval. Application to the AOGCC for Approval of Expansion of Qannik Area Injection Order Colville River Unit Page 22 ConocoPhillips Alaska, Inc. Figure 6: CD4-597 Injector Wellbore Schematic Application to the AOGCC for Approval of Expansion of Qannik Area Injection Order Colville River Unit Page 23 ConocoPhillips Alaska, Inc. 20 AAC 25.402 (c)(9) Injection Fluid Analysis and Injection Rates The Qannik reservoir portion of the QOP (CD2 pad primary Qannik development area) will continue to be developed with water injection only. Average well spacing of the current Qannik development from the CD2 pad is ~3,000’, and at this spacing, there is limited benefit from gas injection. At this time, there is no planned additional development for the Qannik reservoir at the CD2 pad. For the expanded area, the addition of enriched gas injection is proposed in the Narwhal reservoir to increase ultimate recovery. Typical injected fluids are treated produced water, treated seawater, and enriched produced gas. Rates of 500 – 8,000 barrels of water per day (“BWPD”) are expected, although during well startup or other transitory period wells may exceed this range. Narwhal reservoir development is from the CD4 drill pad, a satellite drill site that is connected to the Alpine Central Processing Facility (“ACF”). ACF has demonstrated the compatibility of both produced water and seawater in Brookian age reservoirs over the past 14 years. No issues are expected with the injection of either fluid into the existing interval or the proposed interval. This WAG Enhanced Oil Recovery (“EOR”) method has been used since Alpine field startup and the compatibility of the injection fluids has been historically demonstrated. Types and sources of fluids requested for injection include: • Beaufort seawater sourced from the Kuparuk seawater treatment plant. • Produced water from all present and yet-to-be defined oil pools within the CRU and GMTU • Enriched hydrocarbon gas from the ACF for injection into the Narwhal reservoir wells (addition to AIO 35 injection fluids) 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 Narwhal injection wells. These fluids are not planned for continuous injection, or as a means for enhanced recovery. The volumes of these other fluids are not expected to hinder the recovery efficiency of performance. These other fluids include: a. Fluids used during hydraulic stimulation b. Tracer survey fluids to monitor reservoir performance c. Fluids used to improve near wellbore injectivity (acid, solvents, surfactants, etc.) d. Fluids used to seal wellbore intervals which negatively impact recovery (cement, resin, etc.) e. Fluids associated with freeze protection (diesel, crude, glycol, methanol, etc.) f. Standard oilfield chemicals (corrosion inhibitor, scale inhibitor, etc.) Application to the AOGCC for Approval of Expansion of Qannik Area Injection Order Colville River Unit Page 24 ConocoPhillips Alaska, Inc. g. Sump fluid, hydrotest fluid (excluding fluids derived from tests of transportation pipelines), rinsate generated from washing mud hauling trucks, excess well work fluids, and treated camp effluent and mixtures involving such fluids h. Non-enriched hydrocarbon gas from the ACF for injection into the Narwhal reservoir wells (Addition from AIO 35) Barium sulfate scale formation in production wells, as has been experienced to various degrees in CRU pools, is possible due to the mixing of seawater (containing sulfate) and formation water (containing barium). A scale inhibition treatment program, like that performed in CRU pools, will be performed at Narwhal as required. Application to the AOGCC for Approval of Expansion of Qannik Area Injection Order Colville River Unit Page 25 ConocoPhillips Alaska, Inc. 20 AAC 25.402 (c)(10) Injection Pressures CPAI proposes a maximum sandface injection gradient of 0.8 psi/ft for the QOP. Injection into the QOP will occur above the fracture gradient (0.56-0.63 psi/ft) of the reservoir, but below the fracture gradient of the upper confining interval of 0.82 psi/ft. The operating pressure of each injector will be set based on the realized depth of the reservoir. The data supporting the proposed maximum injection pressure is provided in the following section. Application to the AOGCC for Approval of Expansion of Qannik Area Injection Order Colville River Unit Page 26 ConocoPhillips Alaska, Inc. 20 AAC 25.402 (c)(11) Fracture Information In the CD4 area, the Narwhal reservoir is overlain by the Seabee Fm and Nanushuk Group below the K-3 Marker. The Seabee Formation consists of primarily claystone with occasional siltstone and the base is a shale-dominated marine flooding surface comprised of condensed mudstone facies. The Nanushuk Group consists of claystone with thin siltstone beds that range from 240-310 TVD foot thick from the K-3 marker to the top Narwhal reservoir sandstone. These make up the upper confining interval. Total thickness of the upper confining interval varies from 1,580-1,700 ft TVD in the CD4 area. The underlying confining zone beneath the Narwhal reservoir consists of 20-100 feet TVD of shaly slope mudstones and shales that thicken to the east/southeast. The calculated hydraulic fracture gradient for the upper confining interval is based on available leak off tests (LOTs) and formation integrity tests (FITs) in the immediate area. Figure 7 shows the LOT and FIT data (red points) in True Vertical Depth (y axis) and the associated pore pressure in PSI (x axis) that represent the fracture gradient(s) for the overburden. Also shown is the fracture gradient of the Narwhal reservoir sandstone (gold dashed line) and the planned maximum injection pressure for the CD4 area (blue dashed line). Application to the AOGCC for Approval of Expansion of Qannik Area Injection Order Colville River Unit Page 27 ConocoPhillips Alaska, Inc. Figure 7: Fracture Gradient plot for upper confining interval and reservoir. Fracture gradient analysis has been calibrated with rock mechanical properties from drilling LOTs and FITs in the overlying shales. Data indicates overlying intervals have fracture gradients up to 0.82 psi/ft. By analog, rock properties of the underlying Torok shales are expected to have a similar fracture gradient. Based on DFITs, the fracture gradient in the Narwhal reservoir is between 0.56 and 0.63 psi/ft. The fracture gradient of the expanded QOP is expected to be the same. To ensure containment of fluids within the QOP, CPAI proposes a rule limiting injection pressure to a maximum injection gradient of 0.8 psi/ft. This is a modification of the existing QOP rules which currently does not have a maximum injection pressure. CPAI has verified that the 0.8 psi/ft injection gradient will not initiate or propagate fractures through the upper or lower confining strata by conducting containment analysis through the use of frac modeling software with inputs based on the CD4-595PH well log calibrated with data from geo-mechanical tests and Narwhal depth grids. Figure 8 shows results of the Application to the AOGCC for Approval of Expansion of Qannik Area Injection Order Colville River Unit Page 28 ConocoPhillips Alaska, Inc. simulated continuous injection for 9 days at a rate of 8,000 BWPD into a horizontal well within the Narwhal reservoir where fracture pressures stabilize at ~0.68 psi/ft. Figure 8 shows that all injected fluids remain confined within the expanded Narwhal interval (QOP). The frac modeling software used was Grid Oriented Hydraulic Fracture Extension Replicator (“GOHFER”), due to its reliability and common use within ConocoPhillips as well as in the fracturing industry. GOHFER is a planar 3-D geometry fracture simulator developed by Barree & Associates in association with Stim-lab and is commercially available throughout the industry for performing hydraulic fracture simulation work. In addition, a finite element based, coupled simulation geomechanical modelling approach to investigate top seal integrity and fault stability was conducted to evaluate the dynamic response of injection on top seal integrity and fault stability. During all injection cases, up to a maximum operating limit of 0.8 psi/ft or 3300 psi BHP, the stability of the top seal and faults were maintained with no failure of individual finite elements observed. Figure 8: Narwhal Injection Model Results. Application to the AOGCC for Approval of Expansion of Qannik Area Injection Order Colville River Unit Page 29 ConocoPhillips Alaska, Inc. 20 AAC 25.402 (c)(12) Quality of Formation Water No formation water samples are available from the Narwhal reservoir affected area. The closest analog formation water sample was produced from the Stony Hill 1 well on the southern end of the Narwhal trend. Consistent with the CRU area, the salinity of this water was found to be about 16,000 ppm. In the Narwhal reservoir near CD4 no water-oil contacts have been observed. The Nanuk #2 well produced water from a downdip, deep water equivalent Torok Formation sand. The water composition from that well is shown in Table 4 below. Table 4: Nanuk #2 produced water sample analysis. Sodium 7,000 ppm Potassium 150 ppm Calcium 200 ppm Magnesium 0 ppm Bicarbonate 800 ppm Sulfate 0 ppm Chloride 10,600ppm Please see the following section for CPAI’s explanation that there are no underground sources of drinking water in the QOP Area. Application to the AOGCC for Approval of Expansion of Qannik Area Injection Order Colville River Unit Page 30 ConocoPhillips Alaska, Inc. 20 AAC 25.402 (c)(13) Aquifer Exemption Reference In the original Alpine Pool application, CPAI demonstrated there are no freshwater aquifers in the Colville River Unit. In finding number 18 of CO 443, the Commission stated: “Calculated water salinity ranges from 15,000-18,000 milligrams per liter (mg/l) total dissolved solids (“TDS”) throughout the Cretaceous and older stratigraphic section in the Colville Delta area. Water samples collected from drill stem and production testing of several wells in the Colville Delta area yielded 18,500- 24,000 mg/l TDS.” In conclusion number 5 of CO 443, the Commission stated: “There are no freshwater aquifers in the Colville River Unit”. This prior finding and conclusion remains valid. None of the subsequent oil pools and area injection orders in the Colville River Unit have found any freshwater aquifers to exist within the Colville River Unit area. Significantly, the Qannik Area Injection Order covers the area of the proposed expansion to include Narwhal, and in that area injection order there was a finding of no freshwater aquifers. The Qannik Area Injection Order has an affected area entirely within the CRU area. See Area Injection Order 35, Finding 14 which provides: According to the findings and conclusions of Area Injection Orders 18, 18A, and 18B, there are no underground sources of drinking water beneath the permafrost in the Colville River Unit area. Examination of well log data from exploratory wells in and near the proposed Qannik development confirms that there are no aquifers within the affected area that could serve as underground sources of drinking water. For these reasons, CPAI requests the Commission find that there are no freshwater aquifers within the QOP area. Application to the AOGCC for Approval of Expansion of Qannik Area Injection Order Colville River Unit Page 31 ConocoPhillips Alaska, Inc. 20 AAC 25.402 (c)(14) Incremental Hydrocarbon Recovery Pressure support in the reservoir with water injection is necessary due to the expected voidage rates and relatively low recovery without voidage replacement. Although a full characterization of the in-place fluids across the Narwhal trend is not currently available, data gathered from exploration wells shows a reservoir which is slightly undersaturated, by as little as 200-300 psi, and an initial pressure of ~1,920 psi. This does not leave much driving force for primary depletion. The expected recovery without injection support is <5%. Reservoir modeling and analog data predict a recovery factor upwards of ~30% under waterflood. With water-alternating- gas (“WAG”) injection, up to 7% (of OOIP) additional recovery over waterflood is expected. The Narwhal pilot injection project ERIO-06 allowed CPAI to test communication across a production pattern and helped to confirm that the expected recovery benefit of injection is feasible. Application to the AOGCC for Approval of Expansion of Qannik Area Injection Order Colville River Unit Page 32 ConocoPhillips Alaska, Inc. 20 AAC 25.402 (c)(15) Mechanical Condition of Wells Within ¼ Mile of Proposed Area All existing perforations within a ¼ mile of proposed injection operations are within the existing QOP. There is one well, CD4-499 producer, which penetrates both the Qannik and Narwhal intervals within ¼ mile of proposed injection operations and is entirely within the QOP (Figure 2, Table 5). Currently there are three Narwhal wells drilled from CD4, Narwhal producer CD4-595 the intended recipient of pressure support from proposed injection operations, and CD4-594 and CD4-597 injectors. One well, CD4-588, a planned injector, is currently being drilled. The tubing/casing annulus pressure of each injection well will be tested in accordance with 20 ACC 25.402(c). Figure 2 shows the additional proposed injection wells with a ¼ mile radius plotted around the injection wellbore. Future proposed wells will be drilled and completed in accordance with applicable AOGCC drilling regulations in 20 AAC 25. In accordance with 20 AAC 25.402(d), cement quality logs, or other data approved by the AOGCC, will be provided for all injection wells to demonstrate isolation of the injected fluids to the approved interval. Table 5: Qannik wells within 1/4 mile of proposed injection. Well Name Status Top of Qannik Pool (MD/TVD) TOC (MD/TVD) TOC – Determined By Reservoir Completion Status Zonal Isolation Cement Operations Summary CD4- 499 Producing 4,967’ / 4,023’ 3,451’ / 3,266’ Sonic Log Liner TOC and Packer 55 bbls of 15.8 ppg Class G Application to the AOGCC for Approval of Expansion of Qannik Area Injection Order Colville River Unit Page 33 ConocoPhillips Alaska, Inc. Proposed Area Injection Order Rules The proposed rules set forth to update AIO 35 to vertically expand the authorized injection area to include the Narwhal reservoir, and allow gas injection within it. The affected area is unchanged from AIO 35, and consistent with CO 605A. Rule 1 Authorized Injection Strata for Enhanced Recovery (Updated from AIO 35) Authorized fluids (under Rule 3, below) may be injected for purposes of pressure maintenance and enhanced oil recovery within the Affected Area into strata that are common to, and correlate with, the interval between the measured depths of 6,030 – 6,249 feet on the EWR log recorded in well CRU CD2-11. Except that enriched and lean gas may only be injected in the Narwhal reservoir (the strata that is common to and correlates with the interval between the measured depths of 6,030 – 6,086 feet on the EWR log recorded in well CD2-11). Rule 2 Well Construction (Unchanged from AIO 35) Rule 3 Authorized Fluids for Enhanced Recovery (Updated from AIO 35) Injection fluids include: a. Source water from the Kuparuk seawater treatment plant; b. Produced water from the Alpine Central Facility; c. Enriched gas from the Alpine Central Facility for injection into the Narwhal reservoir wells only; d. Lean gas from the Alpine Central Facility into the Narwhal reservoir wells only; e. Sump fluid, hydrotest fluid (excluding fluids derived from tests of transportation pipelines), rinsate generated from washing mud hauling trucks, excess well work fluids, and treated camp effluent and mixtures involving such fluids; f. Tracer survey fluids to monitor reservoir performance; g. Fluids used to improve near wellbore injectivity (acid, solvents, surfactants, etc.); h. Fluids used to seal wellbore intervals which negatively impact recovery (cement, resin, etc.); i. Fluids associated with freeze protection; j. Standard oilfield chemicals (corrosion inhibitor, scale inhibitor, etc.). Rule 4 Authorized Injection Pressure for Enhanced Oil Recovery (Updated from AIO 35) For the injection interval specified in Rule 1 above, pressures will be managed not to exceed the maximum injection gradient of 0.80 psi/ft to ensure containment of injected fluids within the injection interval. Application to the AOGCC for Approval of Expansion of Qannik Area Injection Order Colville River Unit Page 34 ConocoPhillips Alaska, Inc. Rule 5 Monitoring Tubing-Casing Annulus Pressure (Unchanged from AIO 35) Rule 6 Demonstration of Tubing/Casing Annulus Mechanical Integrity (Unchanged from AIO 35) Rule 7 Well Integrity and Confinement (Unchanged from AIO 35) Rule 8 Notification of Improper Class II Injection (Unchanged from AIO 35) Rule 9 Other Conditions (Unchanged from AIO 35) Rule 10 Administrative Action (Unchanged from AIO 35)