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AIO 018 E
Area Injection Order AIO 18E Docket No. AIO-20-021 Colville River Field Colville River Unit Alpine Oil Pool 1. November 5, 2020 CPAI’s request to amend AIO 18 (confidential pages 37 – 43 held in secure storage) 2. November 20, 2020 Notice of public hearing, affidavit of publication, email distribution, mailings 3. February 22, 2021 CPAI Request for Reconsideration (Granted 3/3/21) 4. May 26, 2021 CPAI request to reinstate AIO 18A with modifications (AIO 18E.001) 5. March 24, 2022 CPAI request to allow CRU CD3-118 to continue WAG injection service (AIO 18E.002) 6. September 8, 2022 CPAI request to approve area injection order 18E; Water only injection Colville River unit (AIO 18E.003) 7. February 21, 2023 CPAI request to allow water only injection CRU CD5-23 (AIO 18E.004) 8. June 5, 2023 CPAI request to cancel AIO 18E.003 (AIO 18E.003 canceled) 9. February 23, 2024 CPAI request to amend admin approval for CRU CD3-118 (PTD 208-025) (AIO 18E.002 Amended) 10. August 30, 2024 CPAI request for well CD2-57 to remain in water only injection service (AIO 18E.005) 11. August 30, 2024 CPAI request for well CD4-213B to remain in water only injection service (AIO 18E.006) 12. January 15, 2025 AIO 7 Proposed language change (AIO 18E.008) 13. December 3, 2025 CPAI request to allow well CD2-30 (PTD# 203-135) to be online in water-only injection service (AIO 18E.009) ORDERS STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION 333 West Seventh Avenue Anchorage, Alaska 99501 Re: THE APPLICATION OF ConocoPhillips ) Area Injection Order No. 18E Amended Alaska, Inc. for amendments to Area Injection ) on Reconsideration Order No. 18D to expand the areal and vertical ) Docket Number: AIO-20-021 limits of the Colville River Unit, Alpine Oil ) Pool and to incorporate the existing Fiord Oil ) Colville River Field Pool into the Alpine Oil Pool. ) Colville River Unit ) Alpine Oil Pool ) Nunc pro tunc February 3, 2021 Dated March 4, 2021 IT APPEARING THAT: 1. By letter dated November 5, 2020, ConocoPhillips Alaska, Inc. (CPAI), in its capacity as unit operator, requested that the Alaska Oil and Gas Conservation Commission (AOGCC) amend Conservation Order (CO) No. 443C and Area Injection Order (AIO) No. 18D to expand the affected area of Alpine Oil Pool (AOP) to include additional acreage within the Colville River Unit (CRU) and to expand the vertical limits of the AOP to incorporate the Fiord Oil Pool (FOP), which is governed by CO No. 569 and AIO No. 30. 2. Pursuant to 20 AAC 25.540, the AOGCC scheduled a public hearing for December 15, 2020. On November 10, 2020, the AOGCC published notice of the opportunity for that hearing on the State of Alaska's Online Public Notice website, on the AOGCC's website, electronically transmitted the notice to all persons on the AOGCC's email distribution list, and mailed printed copies of the notice to all persons on the AOGCC's mailing distribution list. On November 10, 2020, the AOGCC also published the notice of the hearing in the ANCHORAGE DAILY NEWS. 3. No comments on the application or hearing requests were received. 4. The hearing was cancelled on December 2, 2020 because CPAI's application and supporting documents, along with public records, provide sufficient information for AOGCC to reach a decision.. FINDINGS: 1. CPAI is the 100% working interest owner of the producing intervals in the CRU. Subsurface owners of the AOP are currently the State of Alaska; the U.S. Government, Bureau of Land Management (BLM); and the Arctic Slope Regional Corporation. 2. Surface owners of the proposed AOP expansion area include Kuukpik Corporation, the State of Alaska, the BLM (U.S. Government), Lydia Sovalik, Joeb Woods, Jr., Marlene Michelle Woods, and Martha Lynn Neakok. 3. CPAI is the Operator of the CRU and all lands affected by this order. 4. The areal and vertical extents of the AOP in the CRU were initially defined in CO 443. The areal and vertical extents of the AOP were subsequently modified in CO 443B and CO 443C. 5. Participating Areas established by the State of Alaska's Department of Natural Resources will be unaffected by this pool expansion. AIO 18E Amended on Reconsideration March 4 2021 Page 2 of 6 6. Geology: a. Stratigraphy: The vertically expanded injection interval, which incorporates the former FOP, is defined as the stratigraphic interval between 6,920 and 7,559 feet measured depth in the Alpine No. 3 well (Figure 1, below). Three reservoirs are included in this revised pool: the Jurassic -aged Alpine and Nechelik sandstones within the Kingak formation and the Lower Cretaceous -aged "C sandstones" of the Kuparuk River formation (Kuparuk C) that are currently informally known as the Nanuq-Kuparuk, Fiord-Kuparuk, and Fiord West Kuparuk reservoirs. The Alpine and Nechelik reservoir sandstones (Alpine and Nechelik) are locally overlain by relatively thin Kuparuk C sandstone deposits that lie atop the Lower Cretaceous Unconformity (LCU). They are aerially more extensive than the Kuparuk C within AOP, and all three sandstones are in pressure communication through non -sealing sand -on -sand contacts across the LCU. Pressure communication between the Alpine and Nechelik and the overlying Kuparuk C has been interpreted as occurring along faults and naturally occurring fractures, as discussed below. This communication appears to only exist below the Kalubik/HRZ upper confining interval. b. Confinement: The three reservoirs in the expanded injection interval share the same confining intervals for injected fluids: Upper Confining Interval: The upper confining interval for the expanded AOP includes deep marine shales and silts of the HRZ and Kalubik formation varying from 100 to over 230 feet in existing wells. Lower Confining Interval: The Lower Kingak formation is 700 to 1,300 feet thick and defines the lower confining interval. It is made up of sealing shales and silts and is estimated from both well and seismic data. The Kingak lower confining zone is not penetrated in the Alpine No. 3 type log (Figure 1). 7. Evidence of communication between the Alpine, Nechelik, and Kuparuk reservoirs is provided by well, production, and pressure data. The most distal portion of the CRU CD2-02 injection well was drilled directionally upward from the Alpine reservoir into the overlying Kuparuk C, and it demonstrated sand -on -sand contact existed across the LCU at that location. Similarly, the Kuparuk C and the Nechelik reservoirs also exhibit sand -on -sand contact within the current FOP. In addition to direct sand -on -sand contacts between these reservoirs in other portions of the CRU, it has been demonstrated that the Kuparuk C and Alpine reservoirs are in hydraulic communication through natural fractures. On this basis, the former Nanuq-Kuparuk Oil Pool was incorporated into the AOP in CO 443B. (See Findings 7 through 12 and Conclusion 1 within CO 443B.) AIO 18E Amended on Reconsideration March 4 2021 Page 3 of 6 692D' MD 7559' MD Alpine 3 7150 7250 7300 7350 7400 1450 7500 Strut Tops. Formotbn Kalubik Fm. Top Kuparuk Kuparuk River Fm. Kuparuk C {.LU • - 1 • -,. Miluveach Fm. Top Alpine Top Nuigsut Top Nechelik Base Nechelik Figure 1 Alpine No. 3 Type Log Kingak Fm. CONCLUSIONS: 1. Amending AIO 18D to expand the affected area and vertically expand the injection interval is consistent with the provisions of AS 31.05. Accordingly, these expansions will not promote waste, jeopardize correlative rights, or compromise ultimate recovery and are based on sound engineering and geoscience principles. 2. The definition of the term "pool" in AS 31.05.190(12) requires complete separation from other zones to be considered a standalone pool. The direct sand -on -sand contact between the Alpine, Nechelik, and Kuparuk C reservoir sandstones and the established hydraulic connection AIO 18E Amended on Reconsideration March 4 2021 Page 4 of 6 between these reservoirs through faults and natural fractures demonstrate that these reservoirs are not completely separate and should be considered a single pool.. The proposed areal expansion area is reasonable based upon the geologic information contained in the operator's application, the exploratory wells drilled in the area, and the records of previous Conservations Orders governing oil pools within the CRU. NOW, THEREFORE, IT IS ORDERED: This Area Injection Order supersedes AIO 18D. The findings, conclusions, and administrative records for AIO 18D are adopted by reference and incorporated in this decision, except where inconsistent with this Order. AIO 1813.001, AIO 1813.006, AIO 1813.007, AIO 18C.002, AIO 18C.003, AIO l 8C.004, AIO 18C.005, AIO 18C.008, AIO 18C.009, AIO 18C.010, AIO 18C.012, AIO 1813.002, AIO 1813.003, AIO 1813.005, and AIO 18D.006 remain in effect, all other administrative approvals associate with AIOs 18, 18A, 1813, 18C, and 18D are hereby rescinded. Additionally, AIO 30 and its related administrative approvals (except AIO 30.008, which remains in effect) are rescinded. The administrative record of AIO 30 is incorporated by reference. The development and operation of the Alpine Oil Pool is subject to the following rules and the statewide requirements of 20 AAC 25, to the extent not superseded by the following rules. Affected Area: Umiat Meridian (Revised This Order) Township Range Sections T10N R3E 1-3: All T10N R4E 1-6: All 8-12: All T10N R5E 5: N1/2NW1/4, SW1/4NW1/4, & NW1/4SW1/4 6-7: All T11N R3E 1-3: All 10-14: All 22-27: All 34-36: All T11N R4E 1-36: All T11N R5E 1: W1/2W1/2 2-11: All 14: NW 1 /4N W 1 /4 15: Wl/2, NEIA, NI/2SEl/4, & SW1/4SE1/4 16-21: All 22: NW1/4 & NW1/4SW1/4 28-33: All T12N R3E 1: S1/2 2: S1/2 11-14: All 23-27: All 34-36: All T12N R4E 1-36: All T12N R5E 1-23: All 26: NW1/4NW1/4, S1/2NW1/4, SWIA, & W1/2SE1/4 27-35: All AIO 18E Amended on Reconsideration March 4 2021 Page 5 of 6 36: SW1/4SW1/4 T13N R4E 25: All 33-36: All T13N R5E 15-22: All 26-36: All Rule 1 Authorized Injection Strata for Enhanced Recovery (Revised this Order) Within the affected area, authorized fluids may be injected for purposes of pressure maintenance and enhanced recovery into strata that are common to and correlate with the interval between the measured depths of 6,920 and 7,559 feet in the Alpine No. 3 well. The fluids authorized for injection in the FOR interval are: a. Source water from the Kuparuk seawater treatment plant, b. Produced water from the Alpine Central Facility, c. Enriched hydrocarbon gas (MI) from Alpine Central Facility, d. Lean gas, e. Tracer survey fluids to monitor reservoir performance (chemical, radioactive, etc.), f. Fluids used to improve near wellbore injectivity (via use of acid or similar treatment), g. Fluids used to seal wellbore intervals which negatively impact recovery efficiency (cement, resin, etc.), h. Fluids associated with freeze protection (diesel, dead crude, glycol methanol, etc.), and Standard oilfield chemicals (corrosion inhibitor, scale inhibitor, etc.) j. Small amounts of Class II fluids, which will be mixed with the source or produced water including: sump fluids, hydro -test fluids, rinsate from washing mud hauling trucks, excess well -work fluids, and meltwater collected from well cellars. Rule 2 Authorized Injection Strata for Disposal (Source: AIO 18A) Within the affected area, Class II fluids may be injected for purposes of disposal into strata that are common to and correlate with the interval between the measured depths of 8,432 and 9,540 feet in the Sohio Alaska Petroleum Company Nechelik No. 1 well. Rule 3 Fluid Injection Wells (Source: AIO 18) The underground injection of fluids must be through a well permitted for drilling as a service well for injection in conformance with 20 AAC 25.005 or through a well approved for conversion to a service well for injection in conformance with 20 AAC 25.280. Rule 4 Monitoring the Tubing -Casing Annulus Pressure Variations (Source: AIO 18) The tubing -casing annulus pressure and injection rate of each injection well must be checked at least weekly to ensure there is no leakage and that it does not exceed a pressure that will subject the casing to a hoop stress greater than 70% of the casing's minimum yield strength. Rule 5 Reporting the Tubing -Casing Annulus Pressure Variations (Source: AIO 18) Tubing -casing annulus pressure variations between consecutive observations need not be reported to the Commission unless well integrity failure is indicated as in Rule 7 below. AIO 18E Amended on Reconsideration March 4 2021 Page 6 of 6 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 24 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 7 Well Integrity Failure and Confinement (Source: AIO 18) Whenever any pressure communication, leakage or lack of injection zone isolation is indicated by injection rate, operating pressure observation, test, survey, log, or other evidence, the operator shall 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 Commission. A monthly report of daily tubing and casing annuli pressures and injection rates must be provided to the Commission for all injection wells indicating well integrity failure or lack of injection zone isolation. Rule 8 Plugging and Abandonment of Infection Wells (Rescinded AIO 18D) Rule 9 Surveillance (Source: AIO 18B.004 and AIO 18D) For grind -and -inject slurry injection wells, a baseline temperature survey from surface to total depth, initial step -rate test to pressure equal or exceeding maximum injection pressure and pressure falloff are required prior to sustained disposal injection. Regular fill depth tags are required at least once every two years or as warranted following consultation with the Commission. For slurry injection wells, an annual performance report will be required including rate and pressure performance, surveillance logging, fill depth, survey results, and volumetric analysis of the disposal storage volume, estimate of fracture growth, if any, and updates of operational plans. Report submission must be on or before April 1, in conjunction with the Alpine Pool Annual Reservoir Report. AIO 18E Amended on Reconsideration March 4 2021 Page 7 of 6 Rule 10 Notification (Source: AIO 18A) The operator must notify the Commission if it learns of any improper Class I1 injection. Additional notification requirements of any other State or Federal agency remain the operators' responsibility. Rule 11 Administrative Actions (Source: AIO 18B) Unless notice and public hearing are otherwise required, the Commission may administratively waive or amend any rule stated above as long as the change does not promote waste or jeopardize correlative rights, is based on sound engineering and geoscience principles, and will not result in fluid movement outside of the authorized injection zone. Rule 12 Authorized Iniection Pressure for Enhanced Recovery (Source: AIO 18D) For the injection interval specified in Rule 1 pressures will be managed not to exceed the maximum injection gradient of 0.81 psi/ft to ensure containment of injected fluids within the injectional interval. Done at Anchorage, Alaska and dated March 4, 2021. Jeremy D,mmyM P—b, Date', 203103 04 M. Price1633:16-0 0' Jeremy M. Price Chair, Commissioner Dig itallysigned by Daniel Daniel T. T. Seamount, Jr. Seamount, Jr. Date: 2021.03.0414:51:06 09,00, Daniel T. Seamount, Jr. Commissioner Digit allysigned byJessie Jessie I . L. Chmielowski Chmielowski Date: 2021.03.0414:56:17 -09,00, Jessie L. Chmielowski 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. `l'HE S'1XFE 'ALASKA GOVERNOR MIKE DUNLEAVY Mr. Stephen Thatcher Manager, WNS Development ConocoPhillips Alaska, Inc. P.O. Box 100360 Anchorage, AK 99510-0360 Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.00gcc.alaska.gov Re: Reconsideration Request for Area Injection Order No. 18E — Docket No. AIO 20-21 Collville River Field Alpine Oil Pool Dear Mr. Thatcher: By letter dated February 22, 2021, ConocoPhillips Alaska, Inc. (CPAI) requested reconsideration of two rules in the recently issued Area Injection Order No. (AIO) 18E. First, CPAI requests that the Alaska Oil and Gas Conservation Commission (AOGCC) add the following to the list of approved enhanced oil recovery (EOR) fluids in Rule 1 of AIO 18E: Small amounts of Class II fluids, which will be mixed with the source or produced water including: sump fluids, hydro -test fluids, rinsate from washing mud hauling trucks, excess well -work fluids, and meltwater collected from well cellars. As pointed out in your reconsideration letter these fluids were initially approved as acceptable FOR injection fluids for the Alpine Oil Pool in AIO 18B.002 which was issued on June 1, 2005. The AOGCC did not modify Rule 1 of the Alpine Oil Pool AIO to include a specific list of approved FOR fluids until AIO 18D was issued on June 20, 2017, but the fluids that were authorized by AIO 18B.002 were inadvertently left out of Rule 1 of AIO 18D even though AIO 18B.002 was still valid. When AIO 18E was issued the AOGCC carried over this inadvertent omission of authorized fluids in Rule 1 of AIO 18E. The second point that CPAI seeks reconsideration on is the notification requirement in Rule 7 of AIO 18E, which states :...the operator shall immediately notify the Commission..." if a leak is suspected. CPAI proposes changing this to read "...the operator shall by the next business day notify the Commission..." The proposed language is consistent with the language that the AOGCC has been using in recent AIOs. AIO 18E Reconsideration March 4, 2021 Page 2 of 2 Therefore, the AOGCC agrees with CPAIs proposed revisions and will release a corrected AIO 18E to reflect these changes. Sincerely, Jeremy Digitally signed by ice Date: 2021.03.09 M. Price 163639-09'W Jeremy M. Price Chair, Commissioner RECONSIDERATION AND APPEAL NOTICE As provided in AS 31.05.080(a), within 20 days after written notice of the entry of this order or decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration of the matter determined by it. If the notice was mailed, then the period of time shall be 23 days. An application for reconsideration must set out the respect in which the order or decision is believed to be erroneous. The AOGCC shall grant or refuse the application for reconsideration in whole or in part within 10 days after it is filed. Failure to act on it within 10-days is a denial of reconsideration. If the AOGCC denies reconsideration, upon denial, this order or decision and the denial of reconsideration are FINAL and may be appealed to superior court. The appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision denying reconsideration, UNLESS the denial is by inaction, in which case the appeal MUST be filed within 40 days after the date on which the application for reconsideration was filed. If the AOGCC grants an application for reconsideration, this order or decision does not become final. Rather, the order or decision on reconsideration will be the FINAL order or decision of the AOGCC, and it may be appealed to superior court. That appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision on reconsideration. In computing a period oftime above, the date ofthe event or default after which the designated period begins to run is not included in the period; the last day of the period is included, unless it falls on a weekend or state holiday, in which event the period runs until 5:00 p.m. on the next day that does not fall on a weekend or state holiday. Colombie, Jody J (CED) From: Colombie, Jody J (CED) <jody.colombie@alaska.gov> Sent: Thursday, March 4, 2021 4:49 PM To: AOGCC Public Notices Subject: [AOGCC_Public_Notices] A1018E Amended Attachments: aio18E Amended.pdf Categories: Yellow Category Re: THE APPLICATION OF ConocoPhillips ) Area Injection Order No. 18E Amended Alaska, Inc. for amendments to Area Injection ) on Reconsideration Order No. 18D to expand the areal and vertical ) Docket Number: AIO-20- limits of the Colville River Unit, Alpine Oil ) 021 Pool and to incorporate the existing Fiord Oil ) Colville River Field Pool into the Alpine Oil Pool. ) Colville River Unit Alpine Oil Pool )) Nunc pro tunc February 3, 2021 Dated March 4, 2021 Jody J. Colombie AOGCC Special Assistant Alaska Oil and Gas Conservation Commission State of Alaska 333 West 2 h Avenue Anchorage, AK 99501 Phone Number: 907-793-1221 Email: jody.colombie@alaska.gov List Name: AOGCC_Public_Notices@list.state.ak.us You subscribed as: jody.colombie@alaska.gov Unsubscribe at: http://list.state.ak.us/mailman/options/aogcc_public_notices/jody.colombie%40alaska.gov Bernie Karl Recycling Inc. Gordon Severson Richard Wagner K&K P.O. Box 5 3201 Westmar Cir. P.O. Box 60868 Anchorage, AK 99508-4336 Fairbanks, AK 99706 Fairbanks, AK 99711 George Vaught, Jr. Darwin Waldsmith P.O. Box 13557 P.O. Box 39309 Denver, CO 80201-3557 Ninilchik, AK 99639 1 U� 3 � S STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION 333 West Seventh Avenue Anchorage, Alaska 99501 Re: THE APPLICATION OF ConocoPhillips ) Area Injection Order No. 18E Alaska, Inc. for amendments to Area Injection ) Docket Number: AIO-20-021 Order No. 18D to expand the areal and vertical ) limits of the Colville River Unit, Alpine Oil ) Pool and to incorporate the existing Fiord Oil ) Colville River Field Pool into the Alpine Oil Pool. ) Colville River Unit ) Alpine Oil Pool ) February 3, 2021 IT APPEARING THAT: By letter dated November 5, 2020, ConocoPhillips Alaska, Inc. (CPAI), in its capacity as unit operator, requested that the Alaska Oil and Gas Conservation Commission (AOGCC) amend Conservation Order (CO) No. 443C and Area Injection Order (AIO) No. 18D to expand the affected area of Alpine Oil Pool (AOP) to include additional acreage within the Colville River Unit (CRU) and to expand the vertical limits of the AOP to incorporate the Fiord Oil Pool (FOP), which is governed by CO No. 569 and AIO No. 30. 2. Pursuant to 20 AAC 25.540, the AOGCC scheduled a public hearing for December 15, 2020. On November 10, 2020, the AOGCC published notice of the opportunity for that hearing on the State of Alaska's Online Public Notice website, on the AOGCC's website, electronically transmitted the notice to all persons on the AOGCC's email distribution list, and mailed printed copies of the notice to all persons on the AOGCC's mailing distribution list. On November 10, 2020, the AOGCC also published the notice of the hearing in the ANCHORAGE DAILY NEWS. 3. No comments on the application or hearing requests were received. 4. The hearing was cancelled on December 2, 2020 because CPAI's application and supporting documents, along with public records, provide sufficient information for AOGCC to reach a decision.. FINDINGS: 1. CPAI is the 100% working interest owner of the producing intervals in the CRU. Subsurface owners of the AOP are currently the State of Alaska; the U.S. Government, Bureau of Land Management (BLM); and the Arctic Slope Regional Corporation. 2. Surface owners of the proposed AOP expansion area include Kuukpik Corporation, the State of Alaska, the BLM (U.S. Government), Lydia Sovalik, Joeb Woods, Jr., Marlene Michelle Woods, and Martha Lynn Neakok. 3. CPAI is the Operator of the CRU and all lands affected by this order. 4. The areal and vertical extents of the AOP in the CRU were initially defined in CO 443. The areal and vertical extents of the AOP were subsequently modified in CO 443B and CO 443C. 5. Participating Areas established by the State of Alaska's Department of Natural Resources will be unaffected by this pool expansion. AIO 18E February 3, 2021 Page 2 of 6 6. Geology: a. Stratigraphy: The vertically expanded injection interval, which incorporates the former FOP, is defined as the stratigraphic interval between 6,920 and 7,559 feet measured depth in the Alpine No. 3 well (Figure 1, below). Three reservoirs are included in this revised pool: the Jurassic -aged Alpine and Nechelik sandstones within the Kingak formation and the Lower Cretaceous -aged "C sandstones" of the Kuparuk River formation (Kuparuk C) that are currently informally known as the Nanuq-Kuparuk, Fiord-Kuparuk, and Fiord West Kuparuk reservoirs. The Alpine and Nechelik reservoir sandstones (Alpine and Nechelik) are locally overlain by relatively thin Kuparuk C sandstone deposits that lie atop the Lower Cretaceous Unconformity (LCU). They are aerially more extensive than the Kuparuk C within AOP, and all three sandstones are in pressure communication through non -sealing sand -on -sand contacts across the LCU. Pressure communication between the Alpine and Nechelik and the overlying Kuparuk C has been interpreted as occurring along faults and naturally occurring fractures, as discussed below. This communication appears to only exist below the Kalubik/HRZ upper confining interval. b. Confinement: The three reservoirs in the expanded injection interval share the same confining intervals for injected fluids: Upper Confining Interval: The upper confining interval for the expanded AOP includes deep marine shales and silts of the HRZ and Kalubik formation varying from 100 to over 230 feet in existing wells. Lower Confining_ Interval: The Lower Kingak formation is 700 to 1,300 feet thick and defines the lower confining interval. It is made up of sealing shales and silts and is estimated from both well and seismic data. The Kingak lower confining zone is not penetrated in the Alpine No. 3 type log (Figure 1). Evidence of communication between the Alpine, Nechelik, and Kuparuk reservoirs is provided by well, production, and pressure data. The most distal portion of the CRU CD2-02 injection well was drilled directionally upward from the Alpine reservoir into the overlying Kuparuk C, and it demonstrated sand -on -sand contact existed across the LCU at that location. Similarly, the Kuparuk C and the Nechelik reservoirs also exhibit sand -on -sand contact within the current FOP. In addition to direct sand -on -sand contacts between these reservoirs in other portions of the CRU, it has been demonstrated that the Kuparuk C and Alpine reservoirs are in hydraulic communication through natural fractures. On this basis, the former Nanuq-Kuparuk Oil Pool was incorporated into the AOP in CO 443B. (See Findings 7 through 12 and Conclusion 1 within CO 443B.) AIO 18E February 3, 2021 Page 3 of 6 6920' MD 7559` MD Alpine 3 Strut Taos. FormoGlon I,f REt• �,�C ago*r I Katubik Fm. Top Kuparuk I 6950 Kuparuk River Fm. Kuparuk C . LCU . 7000 Miluveach Fm. Top Alpine 7850 i144 I 7150 Top Nuiqsut 7250 Kingak Fm. 73M j 7350 . Top Nechellk -- 7400 7450 7500 jBase r Nechellk Figure 1 Alpine No. 3 Type Log CONCLUSIONS: 1. Amending AIO 18D to expand the affected area and vertically expand the injection interval is consistent with the provisions of AS 31.05. Accordingly, these expansions will not promote waste, jeopardize correlative rights, or compromise ultimate recovery and are based on sound engineering and geoscience principles. 2. The definition of the term "pool" in AS 31.05.190(12) requires complete separation from other zones to be considered a standalone pool. The direct sand -on -sand contact between the Alpine, Nechelik, and Kuparuk C reservoir sandstones and the established hydraulic connection AIO 18E February 3, 2021 Page 4 of 6 between these reservoirs through faults and natural fractures demonstrate that these reservoirs are not completely separate and should be considered a single pool.. The proposed areal expansion area is reasonable based upon the geologic information contained in the operator's application, the exploratory wells drilled in the area, and the records of previous Conservations Orders governing oil pools within the CRU. NOW, THEREFORE, IT IS ORDERED: This Area Injection Order supersedes AIO 18D. The findings, conclusions, and administrative records for AIO 18D are adopted by reference and incorporated in this decision, except where inconsistent with this Order. AIO 1813.001, AIO 1813.006, AIO 1813.007, AIO 18C.002, AIO 18C.003, AIO 18C.004, AIO 18C.005, AIO 18C.008, AIO 18C.009, AIO 18C.010, AIO 18C.012, AIO 1813.002, AIO 18D.003, AIO 18D.005, and AIO 18D.006 remain in effect, all other administrative approvals associate with AIOs 18, 18A, 1813, 18C, and 18D are hereby rescinded. Additionally, AIO 30 and its related administrative approvals (except AIO 30.008, which remains in effect) are rescinded. The administrative record of AIO 30 is incorporated by reference. The development and operation of the Alpine Oil Pool is subject to the following rules and the statewide requirements of 20 AAC 25, to the extent not superseded by the following rules. Affected Area: Umiat Meridian (Revised This Order) Township Range Sections T10N ME 1-3: All T10N ME 1-6: All 8-12: All TION R5E 5: NI/2NW1/4, SWI/4NW1/4, & NW1/4SW1/4 6-7: All T11N R3E 1-3: All 10-14: All 22-27: All 34-36: All TI 1N ME 1-36: All Tl1N ME 1: W1/2W1/2 2-11: All 14: NW1/4NW1/4 15: W1/2, NE1/4, N1/2SE1/4, & SWI/4SE1/4 16-21: All 22: NW1/4 & NWI/4SW1/4 28-33: All T12N ME 1: S1/2 2: S1/2 11-14: All 23-27: All 34-36: All T12N ME 1-36: All T12N R5E 1-23: All 26: NWI/4NW1/4, S1/2NW1/4, SW1/4, & W1/2SE1/4 27-35: All AIO 18E February 3, 2021 Page 5 of 6 36: SW1/4SW1/4 T13N R4E 25: All 33-36: All T13N R5E 15-22: All 26-36: All Rule 1 Authorized Infection Strata for Enhanced Recovery (Revised this Order) Within the affected area, authorized fluids may be injected for purposes of pressure maintenance and enhanced recovery into strata that are common to and correlate with the interval between the measured depths of 6,920 and 7,559 feet in the Alpine No. 3 well. The fluids authorized for injection in the FOR interval are: a. Source water from the Kuparuk seawater treatment plant, b. Produced water from the Alpine Central Facility, c. Enriched hydrocarbon gas (MI) from Alpine Central Facility, d. Lean gas, e. Tracer survey fluids to monitor reservoir performance (chemical, radioactive, etc.), f. Fluids used to improve near wellbore injectivity (via use of acid or similar treatment), g. Fluids used to seal wellbore intervals which negatively impact recovery efficiency (cement, resin, etc.), h. Fluids associated with freeze protection (diesel, dead crude, glycol methanol, etc.), and i. Standard oilfield chemicals (corrosion inhibitor, scale inhibitor, etc.) Rule 2 Authorized Infection Strata for Disposal (Source: AIO 18A) Within the affected area, Class II fluids may be injected for purposes of disposal into strata that are common to and correlate with the interval between the measured depths of 8,432 and 9,540 feet in the Sohio Alaska Petroleum Company Nechelik No. 1 well. Rule 3 Fluid Infection Wells (Source: AIO 18) The underground injection of fluids must be through a well permitted for drilling as a service well for injection in conformance with 20 AAC 25.005 or through a well approved for conversion to a service well for injection in conformance with 20 AAC 25.280. Rule 4 Monitoring the Tubing -Casing Annulus Pressure Variations (Source: AIO 18 The tubing -casing annulus pressure and injection rate of each injection well must be checked at least weekly to ensure there is no leakage and that it does not exceed a pressure that will subject the casing to a hoop stress greater than 70% of the casing's minimum yield strength. Rule 5 Reporting the Tubing -Casing Annulus Pressure Variations (Source: AIO 18) Tubing -casing annulus pressure variations between consecutive observations need not be reported to the Commission unless well integrity failure is indicated as in Rule 7 below. AIO 18E February 3, 2021 Page 6 of 6 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 24 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 7 Well Integrity Failure and Confinement (Source: AIO 18) Whenever any pressure communication, leakage or lack of injection zone isolation is indicated by injection rate, operating pressure observation, test, survey, log, or other evidence, the operator shall immediately notify the Commission and submit a plan of corrective action on a Form 10-403 for Commission approval. The operator shall immediately shut in the well if continued operation would be unsafe or would threaten contamination of freshwater, or if so directed by the Commission. A monthly report of daily tubing and casing annuli pressures and injection rates must be provided to the Commission for all injection wells indicating well integrity failure or lack of injection zone isolation. Rule 8 Plugging and Abandonment of Infection Wells (Rescinded AIO 18D) Rule 9 Surveillance (Source: AIO 18B.004 and AIO 18D) For grind -and -inject slurry injection wells, a baseline temperature survey from surface to total depth, initial step -rate test to pressure equal or exceeding maximum injection pressure and pressure falloff are required prior to sustained disposal injection. Regular fill depth tags are required at least once every two years or as warranted following consultation with the Commission. For slurry injection wells, an annual performance report will be required including rate and pressure performance, surveillance logging, fill depth, survey results, and volumetric analysis of the disposal storage volume, estimate of fracture growth, if any, and updates of operational plans. Report submission must be on or before April 1, in conjunction with the Alpine Pool Annual Reservoir Report. Rule 10 Notification (Source: AIO 18A) The operator must notify the Commission if it learns of any improper Class II injection. Additional notification requirements of any other State or Federal agency remain the operators' responsibility. Rule 11 Administrative Actions (Source: AIO 18B) Unless notice and public hearing are otherwise required, the Commission may administratively waive or amend any rule stated above as long as the change does not promote waste or jeopardize AIO 18E February 3, 2021 Page 7 of 6 correlative rights, is based on sound engineering and geoscience principles, and will not result in fluid movement outside of the authorized injection zone. Rule 12 Authorized Iniection Pressure for Enhanced Recovery (Source: AIO 18D) For the injection interval specified in Rule 1 pressures will be managed not to exceed the maximum injection gradient of 0.81 psi/ft to ensure containment of injected fluids within the injectional interval. Done at Anchorage, Alaska and dated February 3, 2021. Jeremy Digit ally signed by Jeremy M. Price Date: 021.02.03 M. Price 1548:128-0900' Jeremy M. Price Chair, Commissioner Digitally signed by Daniel T. Daniel T. Seamount, Jr. Seamount, Jr, Date:2021.02.03 14:41:58-09'00' Daniel T. Seamount, Jr. Commissioner Digitally signed by Jessie L. Jessie L. Chmielowski Chmielowski Date:2021.02.03 15:04:45-09100' Jessie L. Chmielowski Commissioner RECONSIDERATION AND APPEAL NOTICE As provided in AS 31.05.080(a), within 20 days after written notice of the entry of this order or decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration of the matter determined by it. If the notice was mailed, then the period of time shall be 23 days. An application for reconsideration must set out the respect in which the order or decision is believed to be erroneous. The AOGCC shall grant or refuse the application for reconsideration in whole or in part within 10 days after it is filed. Failure to act on it within 10-days is a denial of reconsideration. If the AOGCC denies reconsideration, upon denial, this order or decision and the denial of reconsideration are FINAL and may be appealed to superior court. The appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision denying reconsideration, UNLESS the denial is by inaction, in which case the appeal MUST be filed within 40 days after the date on which the application for reconsideration was filed. If the AOGCC grants an application for reconsideration, this order or decision does not become final. Rather, the order or decision on reconsideration will be the FINAL order or decision of the AOGCC, and it may be appealed to superior court. That appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision on reconsideration. In computing a period of time above, the date of the event or default after which the designated period begins to run is not included in the period; the last day of the period is included, unless it falls on a weekend or state holiday, in which event the period runs until 5:00 p.m. on the next day that does not fall on a weekend or state holiday. Colombie, Jody J (CED) From: Colombie, Jody J (CED) <jody.colombie@alaska.gov> Sent: Wednesday, February 3, 2021 5:01 PM To: AOGCC Public Notices Subject: [AOGCC_Public_Notices] aiol8E Attachments: aio 18E.pdf Categories: Yellow Category Please see attached. Jody J. Colombie AOGCC Special Assistant Alaska Oil and Gas Conservation Commission State of Alaska 333 West 7`h Avenue Anchorage, AK 99501 Phone Number: 907-793-1221 Email: jody.colombie@alaska.gov List Name: AOGCC_Public_Notices@list.state.ak.us You subscribed as: jody.colombie@alaska.gov Unsubscribe at: http://list.state.ak.us/mailman/options/aogcc_public_notices/jody.colombie%40alaska.gov Bernie Karl K&K Recycling Inc. Gordon Severson Richard Wagner P.O. Box 58055 3201 Westmar Cir. P.O. Box 60868 Fairbanks, AK 99711 Anchorage, AK 99508-4336 Fairbanks, AK 99706 George Vaught, Jr. Darwin Waldsmith P.O. Box 13557 P.O. Box 39309 Denver, CO 80201-3557 Ninilchik, AK 99639 N Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.alaska.gov ADMINISTRATIVE APPROVAL AREA INJECTION ORDER NO. 18E.001 AREA INJECTION ORDER NO. 28.009 AREA INJECTION ORDER NO. 35.004 AREA INJECTION ORDER NO. 40.003 AREA INJECTION ORDER NO. 43.001 January 27, 2022 Mr. Stephen Thatcher, Manager North Slope Development ConocoPhillips Alaska, Inc. P.O. Box 100360 Anchorage, AK 99510-0360 Re: Docket Number: AIO-21-010 Request to Reinstate Area Injection Order No. 18.001with Modifications Colville River Unit, Alpine Oil Pool Dear Mr. Thatcher: By letter dated May 26, 2021, ConocoPhillips Alaska, Inc. (CPAI) requested reinstatement of Area Injection Order (AIO) No. 18A.001, which allowed for the mixing of treated effluent with Class II enhanced oil recovery (EOR) fluids for injection into the Alpine Oil Pool (AOP) when the Class I disposal well was unavailable. AIO 18A.001 was rescinded when AIO 18E was issued on March 4, 2021. The Alaska Oil and Gas Conservation Commission (AOGCC) does not reinstate rescinded orders. However, the substance of CPAI’s request is for administrative approval to authorize an additional fluid to be for injection, and AOGCC will treat it as such. Since AIO 18A.001 was issued, four additional pools have been tied into the EOR injection system that serves the AOP. These pools and the AIOs that govern their injection operations are: Pool Governing AIO Nanuq Oil Pool (NOP) AIO 28 Qannik Oil Pool (QOP) AIO 35 Lookout Oil Pool (LOP) AIO 40 Rendezvous Oil Pool (ROP) AIO 43 The NOP and QOP are in the Colville River Unit (CRU), and the LOP and ROP are in the Greater Moose’s Tooth Unit (GMTU). AIO 18E.001, AIO 28.009, AIO 35.004, AIO 40.003, & AIO 43.001 January 27, 2022 Page 2 of 2 There are currently two usable Class I disposal wells (a third Class I well was suspended in 2013) in the CRU, and there are none in the GMTU. Well CRU WD-02 (PTD 198-258) is used for disposal of treated effluent, and CRU CD1-01A (PTD 212-099) is the primary drilling waste disposal well. Having the ability to mix small amounts of treated effluent into the EOR injection stream when using a Class I well is not possible due to required mechanical integrity testing, well damage, well workover operations, or any other incident that may make a well temporarily unusable provides operational flexibility for the remote CRU and GMTU developments. Under the authorization of AIO 18A.001, CPAI has periodically mixed treated effluent with the EOR injection water with no indication of fluid incompatibilities or formation damage that reduces injectivity. In accordance with 20 AAC 25.556(d), the AOGCC hereby amends AIO numbers 18E, 28, 35, 40, and 43 to include the following in the list of authorized fluids in Rule 1 of AIO 18E, Rule 4 of AIO 28, and Rule 3 of AIO 35, 40, and 43: - Treated effluent, subject to the following conditions: o Treated effluent injection may occur when the Class I disposal well for effluent disposal is unavailable; o Treated effluent will be mixed with other EOR injection fluids (seawater or produced water); and o Injection of treated effluent may not exceed 1% by volume of the total annualized average water injection at the Colville River Unit and Greater Moose’s Tooth Unit. DONE at Anchorage, Alaska and dated January 27, 2022. Jeremy M. Price Daniel T. Seamount, Jr. Jessie L. Chmielowski Commissioner, Chair Commissioner Commissioner RECONSIDERATION AND APPEAL NOTICE As provided in AS 31.05.080(a), within 20 days after written notice of the entry of this order or decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration of the matter determined by it. If the notice was mailed, then the period of time shall be 23 days. An application for reconsideration must set out the respect in which the order or decision is believed to be erroneous. The AOGCC shall grant or refuse the application for reconsideration in whole or in part within 10 days after it is filed. Failure to act on it within 10 days is a denial of reconsideration. If the AOGCC denies reconsideration, upon denial, this order or decision and the denial of reconsideration are FINAL and may be appealed to superior court. The appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision denying reconsideration, UNLESS the denial is by inaction, in which case the appeal MUST be filed within 40 days after the date on which the application for reconsideration was filed. If the AOGCC grants an application for reconsideration, this order or decision does not become final. Rather, the order or decision on reconsideration will be the FINAL order or decision of the AOGCC, and it may be appealed to superior court. That appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision on reconsideration. In computing a period of time above, the date of the event or default after which the designated period begins to run is not included in the period; the last day of the period is included, unless it falls on a weekend or state holiday, in which event the period runs until 5:00 p.m. on the next day that does not fall on a weekend or state holiday. Dan Seamount Digitally signed by Dan Seamount Date: 2022.01.27 08:48:32 -09'00' Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2022.01.27 09:05:42 -09'00' Jeremy Price Digitally signed by Jeremy Price Date: 2022.01.27 13:57:28 -09'00' From:Salazar, Grace (OGC) To:AOGCC_Public_Notices Subject:[AOGCC_Public_Notices] Area Injection Order Nos. 18E.001, 28.009, 35.004, 40.003 and 43.001 (ConocoPhillips, Alpine Pool) Date:Thursday, January 27, 2022 2:53:56 PM Attachments:AIO 18E.001_ AIO 28.009_ AIO 35.004_ AIO 40.003_AIO 43.001.pdf The Alaska Oil and Gas Conservation Commission has issued the attached administrative approval amending a number of Area Injection Orders for ConocoPhillips Alaska, Inc.’s Colville River Unit, Alpine Oil Pool. Grace ____________________________________ Respectfully, M. Grace Salazar, Special Assistant Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage, AK 99501 Direct: (907) 793-1221 Email: grace.salazar@alaska.gov https://www.commerce.alaska.gov/web/aogcc/ __________________________________ List Name: AOGCC_Public_Notices@list.state.ak.us You subscribed as: grace.salazar@alaska.gov Unsubscribe at: https://list.state.ak.us/mailman/options/aogcc_public_notices/grace.salazar%40alaska.gov AOGCC 333 W 7th Avenue, Anchorage, AK 99501 TO: BERNIE KARL K&K RECLYCLING, INC. PO BOX 58055 FAIRBANKS, AK 99711 Mailed 1/28/22gs Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.alaska.gov ADMINISTRATIVE APPROVAL AREA INJECTION ORDER 18E.002 March 31, 2022 Mr. Dusty Freeborn Well Integrity & Compliance Specialist ConocoPhillips Alaska, Inc. P.O. Box 1000360 Anchorage, AK 99510 Re: Docket Number: AIO-22-009 Request for Administrative Approval to Area Injection Order 18E; Water Alternating Gas Injection Colville River Unit (CRU) CD3-118 (PTD 2080250), Alpine Oil Pool Dear Mr. Freeborn: By emailed letter dated March 24, 2022, ConocoPhillips Alaska, Inc. (CPAI) requested administrative approval to continue water alternating gas (WAG) injection with a known tubing by inner annulus (TxIA) pressure communication. In accordance with 20AAC 25.556(d), the Alaska Oil and Gas Conservation Commission (AOGCC) hereby GRANTS, subject to conditions, CPAI’s request for administrative approval to continue WAG injection in the subject well. CPAI reported a potential TxIA pressure communication to AOGCC on February 15, 2022, while the well was on miscible injectant (MI)/gas injection. CPAI requested and AOGCC approved a monitoring and diagnostics period on MI. On February 24, 2022, CPAI performed additional diagnostics including a passing non state-witnessed mechanical integrity test (MIT) of the inner annulus (to a test pressure of 4,120 psi which is greater than the anticipated gas injection pressure of 3,800 psi). This indicates that CD3-118 exhibits at least two competent barriers to the release of well pressure. CPAI maintains live transmitters on the inner and outer annulus and alarm and remote shut down functions in the Supervisory Control and Data Acquisition (SCADA) system that create layers of protection from an over-pressure event. AOGCC believes CPAI can safely manage the TxIA communication with periodic pressure bleeds by maintaining the inner annulus to a pressure not to exceed 2,400 psi and the outer annulus not to exceed 1,000 psi. Accordingly, the AOGCC believes that the well’s condition does not compromise overall well integrity so as to threaten human safety or the environment. AIO 18E.002 March 31, 2022 Page 2 of 3 AOGCC’s approval to continue WAG injection in CRU CD3-118 is conditioned upon the following: 1) CPAI shall record wellhead pressures and injection rate daily; 2) CPAI shall submit to the AOGCC a monthly report of well pressures, injection rates, and pressure bleeds for all annuli. Bleeds to be flagged on the report; 3) CPAI shall perform a MIT of the inner annulus every two years to the greater of the maximum anticipated injection pressure or 0.25 x packer TVD, but not less than 1,500 psi; 4) CPAI shall limit the well’s inner annulus operating pressure to 2,400 psi during gas injection and 2,000 psi during water injection. Audible control room alarms shall be set at or below these limits; 5) CPAI shall limit the well’s outer annulus operating pressure to 1,000 psi. Audible control room alarms shall be set at or below these limits; 6) CPAI shall monitor the inner and outer annulus pressures in real time with its SCADA system; 7) CPAI shall maintain the injection line choke and surface safety valve (SSV) remote shut down capability. During gas injection, the IA protocols will include a drill site operator alarm set at 2,200 psi, and a high alarm set at 2,400 psi that will prompt the control room Board Operator to remotely shut in the choke or SSV; 8) CPAI shall immediately shut in the well and notify the AOGCC if there is any change in the well's mechanical condition; 9) After well shut in due to a change in the well's mechanical condition, AOGCC approval shall be required to restart injection; and 10)The next required MIT is to be before or during the month of February 2024. This is to align with the agreed upon CPAI Underground Injection Control MIT permanent test schedule for pad testing. DONE at Anchorage, Alaska and dated March 31, 2022 . Jeremy M. Price Daniel T. Seamount, Jr. Jessie L. Chmielowski Chair, Commissioner Commissioner Commissioner Daniel Seamount Digitally signed by Daniel Seamount Date: 2022.03.31 14:07:41 -08'00' Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2022.03.31 14:17:03 -08'00' Jeremy Price Digitally signed by Jeremy Price Date: 2022.03.31 15:30:42 -08'00' AIO 18E.002 March 31, 2022 Page 3 of 3 RECONSIDERATION AND APPEAL NOTICE As provided in AS 31.05.080(a), within 20 days after written notice of the entry of this order or decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration of the matter determined by it. If the notice was mailed, then the period of time shall be 23 days. An application for reconsideration must set out the respect in which the order or decision is believed to be erroneous. The AOGCC shall grant or refuse the application for reconsideration in whole or in part within 10 days after it is filed. Failure to act on it within 10 days is a denial of reconsideration. If the AOGCC denies reconsideration, upon denial, this order or decision and the denial of reconsideration are FINAL and may be appealed to superior court. The appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision denying reconsideration, UNLESS the denial is by inaction, in which case the appeal MUST be filed within 40 days after the date on which the application for reconsideration was filed. If the AOGCC grants an application for reconsideration, this order or decision does not become final. Rather, the order or decision on reconsideration will be the FINAL order or decision of the AOGCC, and it may be appealed to superior court. That appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision on reconsideration. In computing a period of time above, the date of the event or default after which the designated period begins to run is not included in the period; the last day of the period is included, unless it falls on a weekend or state holiday, in which event the period runs until 5:00 p.m. on the next day that does not fall on a weekend or state holiday. From:Salazar, Grace (OGC) To:AOGCC_Public_Notices Subject:[AOGCC_Public_Notices] AOGCC Area Injection Order No. 18E.002 Date:Thursday, March 31, 2022 3:50:38 PM Attachments:AIO 18E.002.pdf The Alaska Oil and Gas Conservation Commission has issued the attached administrative approval granting ConocoPhillips Alaska, Inc.’s request to continue Water Alternating Gas injection into Colville River Unit CD3-118 (PTD 2080250). Grace ____________________________________ Respectfully, M. Grace Salazar, Special Assistant Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage, AK 99501 Direct: (907) 793-1221 Email: grace.salazar@alaska.gov https://www.commerce.alaska.gov/web/aogcc/ __________________________________ List Name: AOGCC_Public_Notices@list.state.ak.us You subscribed as: grace.salazar@alaska.gov Unsubscribe at: https://list.state.ak.us/mailman/options/aogcc_public_notices/grace.salazar%40alaska.gov CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. From:Salazar, Grace (OGC) To:Well Integrity; Travis.T.Smith@conocophillips.com Cc:Wallace, Chris D (OGC) Subject:Area Injection Order 18E.002 Date:Thursday, March 31, 2022 3:48:00 PM Attachments:AIO 18E.002.pdf image001.png The Alaska Oil and Gas Conservation Commission has issued the attached administrative approval granting ConocoPhillips Alaska, Inc.’s request to continue Water Alternating Gas injection into Colville River Unit CD3-118 (PTD 2080250). If you have any questions, please do not hesitate to contact Mr. Chris Wallace, Senior Petroleum Engineer, at (907) 793-1250 or via email at chris.wallace@alaska.gov. Grace ____________________________________ Respectfully, M. Grace Salazar, Special Assistant Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage, AK 99501 Direct: (907) 793-1221 Email: grace.salazar@alaska.gov https://www.commerce.alaska.gov/web/aogcc/ From: AOGCC Permitting (CED sponsored) <aogcc.permitting@alaska.gov> Sent: Thursday, March 24, 2022 10:35 AM To: Salazar, Grace (OGC) <grace.salazar@alaska.gov> Subject: FW: Administrative approval request for CD3-118 (PTD# 208-025) From: Well Integrity Specialist CPF2 <n2549@conocophillips.com> Sent: Thursday, March 24, 2022 10:24 AM To: AOGCC Permitting (CED sponsored) <aogcc.permitting@alaska.gov> Cc: Smith, Travis T <Travis.T.Smith@conocophillips.com> Subject: Administrative approval request for CD3-118 (PTD# 208-025) All- Please see attached application for administrative approval for CD3-118 (PTD# 208-025) to remain on WAG injection with known TxIA communication while on gas injection. Dusty Freeborn Wells Integrity Specialist ConocoPhillips Alaska, Inc. Office phone: (907) 659-7224 Cell phone: (907) 830-9777 AOGCC 333 W 7th Avenue, Anchorage, AK 99501 TO: BERNIE KARL K&K RECLYCLING, INC. PO BOX 58055 FAIRBANKS, AK 99711 Mailed 3/31/22 gs Bernie Karl K&K Recycling Inc. P.O. Box 58055 Fairbanks, AK 99711 mailed 9/9/22 Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.alaska.gov ADMINISTRATIVE APPROVAL AREA INJECTION ORDER 18E.002 AMENDED Ms. Kate Dodson Senior Well Integrity Engineer ConocoPhillips Alaska, Inc. P.O. Box 1000360 Anchorage, AK 99510 Re: Docket Number: AIO-24-009 Request to Amend Administrative Approval to Area Injection Order 18E; Water Alternating Gas Injection Colville River Unit (CRU) CD3-118 (PTD 2080250), Alpine Oil Pool Dear Ms. Dodson: By emailed letter dated February 23, 2024, ConocoPhillips Alaska, Inc. (CPAI) requested to amend administrative approval AIO 18E.002 to change the due date of the next MIT from February 2024 to March 2024 to align with the new CPAI Underground Injection Control MIT permanent test schedule for pad testing and continue water alternating gas (WAG) injection with a known tubing by inner annulus (TxIA) pressure communication. In accordance with 20AAC 25.556(d), the Alaska Oil and Gas Conservation Commission (AOGCC) hereby GRANTS, subject to conditions, CPAI’s request to amend the administrative approval and continue WAG injection in the subject well. CPAI reported a potential TxIA pressure communication to AOGCC on February 15, 2022, while the well was on miscible injectant (MI)/gas injection. CPAI requested and AOGCC approved a monitoring and diagnostics period on MI. On February 24, 2022, CPAI performed additional diagnostics including a passing non state-witnessed mechanical integrity test (MIT) of the inner annulus (to a test pressure of 4,120 psi which is greater than the anticipated gas injection pressure of 3,800 psi). This indicates that CD3-118 exhibits at least two competent barriers to the release of well pressure. CPAI maintains live transmitters on the inner and outer annulus and alarm and remote shut down functions in the Supervisory Control and Data Acquisition (SCADA) system that create layers of protection from an over-pressure event. AOGCC believes CPAI can safely manage the TxIA communication with periodic pressure bleeds by maintaining the inner annulus to a pressure not to exceed 2,400 psi and the outer annulus not to exceed 1,000 psi. Accordingly, the AOGCC believes that the well’s condition does not compromise overall well integrity so as to threaten human safety or the environment. AIO 18E.002 Amended March 1, 2024 Page 2 of 2 AOGCC’s approval to continue WAG injection in CRU CD3-118 is conditioned upon the following: 1) CPAI shall record wellhead pressures and injection rate daily; 2) CPAI shall submit to the AOGCC a monthly report of well pressures, injection rates, and pressure bleeds for all annuli. Bleeds to be flagged on the report; 3) CPAI shall perform a MIT of the inner annulus every two years to the greater of the maximum anticipated injection pressure or 0.25 x packer TVD, but not less than 1,500 psi; 4) CPAI shall limit the well’s inner annulus operating pressure to 2,400 psi during gas injection and 2,000 psi during water injection. Audible control room alarms shall be set at or below these limits; 5) CPAI shall limit the well’s outer annulus operating pressure to 1,000 psi. Audible control room alarms shall be set at or below these limits; 6) CPAI shall monitor the inner and outer annulus pressures in real time with its SCADA system; 7) CPAI shall maintain the injection line choke and surface safety valve (SSV) remote shut down capability. During gas injection, the IA protocols will include a drill site operator alarm set at 2,200 psi, and a high alarm set at 2,400 psi that will prompt the control room Board Operator to remotely shut in the choke or SSV; 8) CPAI shall immediately shut in the well and notify the AOGCC if there is any change in the well's mechanical condition; 9) After well shut in due to a change in the well's mechanical condition, AOGCC approval shall be required to restart injection; and 10) The next required MIT is to be before or during the month of March 2024. This is to align with the agreed upon CPAI Underground Injection Control MIT permanent test schedule for pad testing. DONE at Anchorage, Alaska and dated March 5, 2024. Brett W. Huber, Sr. Jessie L. Chmielowski Chair, Commissioner Commissioner RECONSIDERATION AND APPEAL NOTICE As provided in AS 31.05.080(a), within 20 days after written notice of the entry of this order or decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration of the matter determined by it. If the notice was mailed, then the period of time shall be 23 days. An application for reconsideration must set out the respect in which the order or decision is believed to be erroneous. The AOGCC shall grant or refuse the application for reconsideration in whole or in part within 10 days after it is filed. Failure to act on it within 10 days is a denial of reconsideration. If the AOGCC denies reconsideration, upon denial, this order or decision and the denial of reconsideration are FINAL and may be appealed to superior court. The appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision denying reconsideration, UNLESS the denial is by inaction, in which case the appeal MUST be filed within 40 days after the date on which the application for reconsideration was filed. If the AOGCC grants an application for reconsideration, this order or decision does not become final. Rather, the order or decision on reconsideration will be the FINAL order or decision of the AOGCC, and it may be appealed to superior court. That appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision on reconsideration. In computing a period of time above, the date of the event or default after which the designated period begins to run is not included in the period; the last day of the period is included, unless it falls on a weekend or state holiday, in which event the period runs until 5:00 p.m. on the next day that does not fall on a weekend or state holiday. Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2024.03.05 14:11:00 -09'00' Brett W. Huber, Sr. Digitally signed by Brett W. Huber, Sr. Date: 2024.03.05 15:00:43 -09'00' From:Coldiron, Samantha J (OGC) To:AOGCC_Public_Notices Subject:[AOGCC_Public_Notices] Area Injection Order 18E.002 amended (CPAI) Date:Tuesday, March 5, 2024 3:19:05 PM Attachments:aio18E.002 amended.pdf Docket Number: AIO-24-009 Request to Amend Administrative Approval to Area Injection Order 18E; Water Alternating Gas Injection Colville River Unit (CRU) CD3-118 (PTD 2080250), Alpine Oil Pool Samantha Coldiron Special Assistant Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage, AK 99501 (907) 793-1223 __________________________________ List Name: AOGCC_Public_Notices@list.state.ak.us You subscribed as: samantha.coldiron@alaska.gov Unsubscribe at: https://list.state.ak.us/mailman/options/aogcc_public_notices/samantha.coldiron%40alaska.go v Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.alaska.gov ADMINISTRATIVE APPROVAL AREA INJECTION ORDER NO. 18E.003 CANCELLATION Ms. Kate Dodson Senior Well Integrity Engineer ConocoPhillips Alaska, Inc. P.O. Box 1000360 Anchorage, AK 99510 Re: Docket Number: AIO-23-015 Request to cancel Area Injection Order (AIO) 18E.003 Colville River Unit (CRU) CD3-302A (PTD 2100350), Alpine Oil Pool Dear Ms. Dodson: By letter dated June 5, 2023, ConocoPhillips Alaska, Inc. (CPAI) requested cancellation of administrative approval (AA) AIO 18E.003. In accordance with 20 AAC 25.556(d), the Alaska Oil and Gas Conservation Commission (AOGCC) hereby GRANTS CPAI’s request to cancel the AA. CPAI first reported a potential tubing by inner annulus (TxIA) pressure communication to AOGCC on February 15, 2022, and on September 8, 2022, AOGCC issued AIO 18E.003. AOGCC determined that water only injection could safely continue if CPAI complied with the restrictive conditions set out in AA AIO 18E.003. CPAI has repaired the well with new tubing under Sundry 323-027 and completed a passing state witnessed mechanical integrity test (MIT) of the inner annulus on April 5, 2023, which indicates that CD3-302A exhibits at least two competent barriers to the release of well pressure. AA AIO 18E.003 is no longer necessary to the operation of CD3-302A and is hereby CANCELLED. DONE at Anchorage, Alaska and dated June 14, 2023. Brett W. Huber, Sr Jessie L. Chmielowski Gregory C. Wilson Chair, Commissioner Commissioner Commissioner Brett W. Huber, Sr. Digitally signed by Brett W. Huber, Sr. Date: 2023.06.14 14:12:05 -08'00' Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2023.06.14 14:15:50 -08'00' Gregory Wilson Digitally signed by Gregory Wilson Date: 2023.06.14 14:20:48 -08'00' AIO 18E.003 Cancellation June 14, 2023 Page 2 of 2 RECONSIDERATION AND APPEAL NOTICE As provided in AS 31.05.080(a), within 20 days after written notice of the entry of this order or decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration of the matter determined by it. If the notice was mailed, then the period of time shall be 23 days. An application for reconsideration must set out the respect in which the order or decision is believed to be erroneous. The AOGCC shall grant or refuse the application for reconsideration in whole or in part within 10 days after it is filed. Failure to act on it within 10 days is a denial of reconsideration. If the AOGCC denies reconsideration, upon denial, this order or decision and the denial of reconsideration are FINAL and may be appealed to superior court. The appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision denying reconsideration, UNLESS the denial is by inaction, in which case the appeal MUST be filed within 40 days after the date on which the application for reconsideration was filed. If the AOGCC grants an application for reconsideration, this order or decision does not become final. Rather, the order or decision on reconsideration will be the FINAL order or decision of the AOGCC, and it may be appealed to superior court. That appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision on reconsideration. In computing a period of time above, the date of the event or default after which the designated period begins to run is not included in the period; the last day of the period is included, unless it falls on a weekend or state holiday, in which event the period runs until 5:00 p.m. on the next day that does not fall on a weekend or state holiday. From:Carlisle, Samantha J (OGC) To:AOGCC_Public_Notices Subject:[AOGCC_Public_Notices] Area Injection Order18E.003 cancellation Date:Wednesday, June 14, 2023 2:32:47 PM Attachments:aio18E.003 cancellation.pdf Docket Number: AIO-23-015 Request to cancel Area Injection Order (AIO) 18E.003 Colville River Unit (CRU) CD3-302A (PTD 2100350), Alpine Oil Pool Samantha Carlisle Special Assistant Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage, AK 99501 (907) 793-1223 __________________________________ List Name: AOGCC_Public_Notices@list.state.ak.us You subscribed as: samantha.carlisle@alaska.gov Unsubscribe at: https://list.state.ak.us/mailman/options/aogcc_public_notices/samantha.carlisle%40alaska.gov Bernie Karl K&K Recycling Inc. P.O. Box 58055 Fairbanks, AK 99711 Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.alaska.gov ADMINISTRATIVE APPROVAL AREA INJECTION ORDER 18E.003 Ms. Kate Dodson Senior Well Intervention Engineer ConocoPhillips Alaska, Inc. P.O. Box 1000360 Anchorage, AK 99510 Re: Docket Number: AIO-22-021 Request for Administrative Approval to Area Injection Order 18E;Water Only Injection Colville River Unit (CRU) CD3-302A (PTD 2100350), Alpine Oil Pool Dear Ms. Dodson: By emailed letter dated July 21, 2022, ConocoPhillips Alaska, Inc. (CPAI) requested administrative approval to continue water only injection with a known tubing by inner annulus (TxIA) pressure communication. In accordance with 20 AAC 25.556(d)1, the Alaska Oil and Gas Conservation Commission (AOGCC) hereby GRANTS, subject to conditions, CPAI’s request for administrative approval to continue water only injection in the subject well. CPAIreported a potential TxIA pressure communication to AOGCC on February 15, 2022, while the well was on miscible injectant (MI)/gas injection. CPAI requested and AOGCC approved a monitoring and diagnostics period injecting water. The well does not exhibit signs of pressure communication while on water injection. On March 31, 2022 CPAI performed a passing non state-witnessed mechanical integrity test (MIT) of the tubing. On April 1, 2022, CPAI performed additional diagnostics including a passing non state-witnessed mechanical integrity test (MIT) of the inner annulus. This indicates that CD3-302A exhibits at least two competent barriers to the release of well pressure. AOGCC believes CPAI can safely manage the TxIA communication with periodic pressure bleeds by maintaining the inner annulus to a pressure not to exceed 2,000 psi and the outer annulus not to exceed 1,000 psi. Accordingly, the AOGCC believes that the well’s condition does not compromise overall well integrity so as to threaten human safety or the environment. AOGCC’s approval to continue water injection only in CRU CD3-302A is conditioned upon the 1 The application asked for an administrative approval under Rule 11 of AIO 18E, which granted the AOGCC the authority to administratively amend the order. This rule was made obsolete on February 10, 2018, when 20 AAC 25.556(d) became effective and authorized the AOGCC to administratively amend any order it has issued. AIO 18E.003 September 8, 2022 Page 2 of 2 following: 1) CPAI shall record wellhead pressures and injection rate daily; 2) CPAI shall submit to the AOGCC a monthly report of well pressures, injection rates, and pressure bleeds for all annuli. Bleeds to be flagged on the report; 3) CPAI shall perform a MIT of the inner annulus every two years to the greater of the maximum anticipated injection pressure or 0.25 x packer TVD, but not less than 1,500 psi; 4) CPAI shall limit the well’s inner annulus operating pressure to 2000 psi and the outer annulus operating pressure to 1000 psi during water injection. Audible control room alarms shall be set at or below these limits; 5) CPAI shall monitor the inner and outer annulus pressures in real time with its SCADA system; 6) CPAI shall immediately shut in the well and notify the AOGCC if there is any change in the well's mechanical condition; 7) After well shut in due to a change in the well's mechanical condition, AOGCC approval shall be required to restart injection; and 8) The next required MIT is to be before or during the month of February 2024. This is to align with the agreed upon CPAI Underground Injection Control MIT permanent test schedule for pad testing. DONE at Anchorage, Alaska and dated September 8, 2022. Daniel T. Seamount, Jr. Jessie L. Chmielowski Commissioner Commissioner RECONSIDERATION AND APPEAL NOTICE As provided in AS 31.05.080(a), within 20 days after written notice of the entry of this order or decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration of the matter determined by it. If the notice was mailed, then the period of time shall be 23 days. An application for reconsideration must set out the respect in which the order or decision is believed to be erroneous. The AOGCC shall grant or refuse the application for reconsideration in whole or in part within 10 days after it is filed. Failure to act on it within 10 days is a denial of reconsideration. If the AOGCC denies reconsideration, upon denial, this order or decision and the denial of reconsideration are FINAL and may be appealed to superior court. The appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision denying reconsideration, UNLESS the denial is by inaction, in which case the appeal MUST be filed within 40 days after the date on which the application for reconsideration was filed. If the AOGCC grants an application for reconsideration, this order or decision does not become final. Rather, the order or decision on reconsideration will be the FINAL order or decision of the AOGCC, and it may be appealed to superior court. That appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision on reconsideration. In computing a period of time above, the date of the event or default after which the designated period begins to run is not included in the period; the last day of the period is included, unless it falls on a weekend or state holiday, in which event the period runs until 5:00 p.m. on the next day that does not fall on a weekend or state holiday. Dan Seamount Digitally signed by Dan Seamount Date: 2022.09.08 15:37:18 -08'00' Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2022.09.08 16:49:22 -08'00' 1 Prysunka, Anne E (OGC) From:Carlisle, Samantha J (OGC) <samantha.carlisle@alaska.gov> Sent:Friday, September 9, 2022 7:41 AM To:AOGCC_Public_Notices Subject:[AOGCC_Public_Notices] Area Injection Order 18E.003 (CRU) Attachments:aio18E.003.pdf Docket Number: AIO-22-021 Request for Administrative Approval to Area Injection Order 18E; Water Only Injection Colville River Unit (CRU) CD3-302A (PTD 2100350), Alpine Oil Pool. Samantha Carlisle AOGCC Special Assistant Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage, AK 99501 (907) 793-1223 __________________________________ List Name: AOGCC_Public_Notices@list.state.ak.us You subscribed as: samantha.carlisle@alaska.gov Unsubscribe at: https://list.state.ak.us/mailman/options/aogcc_public_notices/samantha.carlisle%40alaska.gov From:Carlisle, Samantha J (OGC) To:Dodson, Kate Subject:Area Injection Order 18E.003 Date:Friday, September 9, 2022 7:47:00 AM Attachments:aio18E.003.pdf Please see attached. Thank you, Samantha Carlisle 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 APPROVAL AREA INJECTION ORDER 18E.004 Ms. Kathleen Dodson Well Integrity Specialist ConocoPhillips Alaska, Inc. P.O. Box 1000360 Anchorage, AK 99510 Re: Docket Number: AIO-23-003 Request for Administrative Approval to Area Injection Order 18E; Water Alternating Gas Injection Colville River Unit (CRU) CD5-23 (PTD 2171550), Alpine Oil Pool Dear Ms. Dodson: By emailed letter dated February 21, 2023, ConocoPhillips Alaska, Inc. (CPAI) requested administrative approval to continue water alternating gas (WAG) injection with a known tubing by inner annulus (TxIA) pressure communication. In accordance with 20AAC 25.556(d), the Alaska Oil and Gas Conservation Commission (AOGCC) hereby GRANTS, subject to conditions, CPAI’s request for administrative approval to continue WAG injection in the subject well. CPAI reported a potential TxIA pressure communication to AOGCC on February 7, 2022, while the well was on miscible injectant (MI)/gas injection. CPAI requested and AOGCC approved a monitoring and diagnostics period on water. CPAI performed diagnostics including a failing mechanical integrity test (MIT) of the inner annulus and the well was shut in. On January 17, 2023, CPAI performed additional diagnostics including a passing non state-witnessed MIT of the inner annulus (to a test pressure of 4,140 psi which is greater than the anticipated gas injection pressure of 3,800 psi). This indicates that CD5-23 exhibits at least two competent barriers to the release of well pressure. CPAI maintains live transmitters on the inner and outer annulus and alarm and remote shut down functions in the Supervisory Control and Data Acquisition (SCADA) system that create layers of protection from an over-pressure event. AOGCC believes CPAI can safely manage the TxIA communication with periodic pressure bleeds by maintaining the inner annulus to a pressure not to exceed 2,400 psi and the outer annulus not to exceed 1,000 psi. Accordingly, the AOGCC believes that the well’s condition does not compromise overall well integrity so as to threaten human safety or the environment. AIO 18E.004 March 2, 2023 Page 2 of 2 AOGCC’s approval to continue WAG injection in CRU CD5-23 is conditioned upon the following: 1) CPAI shall record wellhead pressures and injection rate daily; 2) CPAI shall submit to the AOGCC a monthly report of well pressures, injection rates, and pressure bleeds for all annuli. Bleeds to be flagged on the report; 3) CPAI shall perform a MIT of the inner annulus every two years to the greater of the maximum anticipated injection pressure or 0.25 x packer TVD, but not less than 1,500 psi; 4) CPAI shall limit the well’s inner annulus operating pressure to 2,400 psi during gas injection and 2,000 psi during water injection. Audible control room alarms shall be set at or below these limits; 5) CPAI shall limit the well’s outer annulus operating pressure to 1,000 psi. Audible control room alarms shall be set at or below these limits; 6) CPAI shall monitor the inner and outer annulus pressures in real time with its SCADA system; 7) CPAI shall maintain the injection line choke and surface safety valve (SSV) remote shut down capability. During gas injection, the IA protocols will include a drill site operator alarm set at 2,200 psi, and a high alarm set at 2,400 psi that will prompt the control room Board Operator to remotely shut in the choke or SSV; 8) CPAI shall immediately shut in the well and notify the AOGCC if there is any change in the well's mechanical condition; 9) After well shut in due to a change in the well's mechanical condition, AOGCC approval shall be required to restart injection; and 10) The next required MIT is to be before or during the month of August 2023. This is to align with the agreed upon CPAI Underground Injection Control MIT permanent test schedule for pad testing. DONE at Anchorage, Alaska and dated March 2, 2023. Brett W. Huber, Sr Jessie L. Chmielowski Chair, Commissioner Commissioner RECONSIDERATION AND APPEAL NOTICE As provided in AS 31.05.080(a), within 20 days after written notice of the entry of this order or decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration of the matter determined by it. If the notice was mailed, then the period of time shall be 23 days. An application for reconsideration must set out the respect in which the order or decision is believed to be erroneous. The AOGCC shall grant or refuse the application for reconsideration in whole or in part within 10 days after it is filed. Failure to act on it within 10-days is a denial of reconsideration. If the AOGCC denies reconsideration, upon denial, this order or decision and the denial of reconsideration are FINAL and may be appealed to superior court. The appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision denying reconsideration, UNLESS the denial is by inaction, in which case the appeal MUST be filed within 40 days after the date on which the application for reconsideration was filed. If the AOGCC grants an application for reconsideration, this order or decision does not become final. Rather, the order or decision on reconsideration will be the FINAL order or decision of the AOGCC, and it may be appealed to superior court. That appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision on reconsideration. In computing a period of time above, the date of the event or default after which the designated period begins to run is not included in the period; the last day of the period is included, unless it falls on a weekend or state holiday, in which event the period runs until 5:00 p.m. on the next day that does not fall on a weekend or state holiday. Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2023.03.02 11:13:23 -09'00' Brett W. Huber, Sr. Digitally signed by Brett W. Huber, Sr. Date: 2023.03.02 11:22:19 -09'00' From:Carlisle, Samantha J (OGC) To:AOGCC_Public_Notices Subject:[AOGCC_Public_Notices] Area Injection Order 18E.004 (CRU) Date:Thursday, March 2, 2023 11:42:53 AM Attachments:aio18E.004.pdf Docket Number: AIO-23-003 Request for Administrative Approval to Area Injection Order 18E; Water Alternating Gas Injection Colville River Unit (CRU) CD5-23 (PTD 2171550), Alpine Oil Pool Samantha Carlisle AOGCC Special Assistant Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage, AK 99501 (907) 793-1223 __________________________________ List Name: AOGCC_Public_Notices@list.state.ak.us You subscribed as: samantha.carlisle@alaska.gov Unsubscribe at: https://list.state.ak.us/mailman/options/aogcc_public_notices/samantha.carlisle%40alaska.gov Bernie Karl K&K Recycling Inc. P.O. Box 58055 Fairbanks, AK 99711 mailed 3/6/23 Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.alaska.gov ADMINISTRATIVE APPROVAL AREA INJECTION ORDER 18E.005 Ms. Kate Dodson Senior Well Integrity Engineer ConocoPhillips Alaska, Inc. P.O. Box 1000360 Anchorage, AK 99510 Re: Docket Number: AIO-24-027 Request for Administrative Approval to Area Injection Order 18E; Water Injection Colville River Unit (CRU) CD2-57 (PTD 204-072), Alpine Oil Pool Dear Ms. Dodson: By emailed letter dated August 30, 2024, ConocoPhillips Alaska, Inc. (CPAI) requested administrative approval to continue water injection with a known outer annulus (OA) to atmosphere pressure communication. In accordance with 20 AAC 25.556(d), the Alaska Oil and Gas Conservation Commission (AOGCC) hereby GRANTS, subject to conditions, CPAI’s request for administrative approval to continue water only injection in the subject well. CPAI reported to AOGCC on July 2, 2024, that the well had a failed a surface casing leak detect log with the leak determined as approximately 24 ft. CPAI performed diagnostics including a passing non-witnessed mechanical integrity test (MIT) of the inner annulus on July 3, 2024, which indicates that the well exhibits at least two competent barriers to the release of well pressure. AOGCC believes CPAI can safely manage the OA to atmosphere pressure communication with periodic pressure bleeds by maintaining the inner annulus to a pressure not to exceed 2,000 psi and the outer annulus not to exceed 100 psi. Accordingly, the AOGCC believes that the well’s condition does not compromise overall well integrity so as to threaten human safety or the environment. AOGCC’s approval to continue water injection only in CRU CD2-57 is conditioned upon the following: 1. CPAI shall record wellhead pressures and injection rate daily; 2. CPAI shall submit to the AOGCC a monthly report of well pressures, injection rates, and pressure bleeds for all annuli. Bleeds to be flagged on the report; AIO 18E.005 September 6, 2024 Page 2 of 2 3. CPAI shall perform a MIT of the inner annulus every two years to the greater of the maximum anticipated injection pressure or 0.25 x packer TVD, but not less than 1500 psi; 4. CPAI shall limit the well’s inner annulus operating pressure to 2,000 psi and the outer annulus to 100 psi; 5. CPAI shall immediately shut in the well and notify the AOGCC if there is any change in the well's mechanical condition; 6. After well shut in due to a change in the well's mechanical condition, AOGCC approval shall be required to restart injection; and 7. The next required state-witnessed MITIA shall be completed within 10 days of restarting injection, when temperature and pressures have stabilized. Then the next MIT shall be completed before or during the month of June 2026. This is to align with the agreed upon CPAI Underground Injection Control MIT permanent test schedule for pad testing. DONE at Anchorage, Alaska and dated September 6, 2024. Jessie L. Chmielowski Gregory C. Wilson Commissioner Commissioner RECONSIDERATION AND APPEAL NOTICE As provided in AS 31.05.080(a), within 20 days after written notice of the entry of this order or decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration of the matter determined by it. If the notice was mailed, then the period of time shall be 23 days. An application for reconsideration must set out the respect in which the order or decision is believed to be erroneous. The AOGCC shall grant or refuse the application for reconsideration in whole or in part within 10 days after it is filed. Failure to act on it within 10 days is a denial of reconsideration. If the AOGCC denies reconsideration, upon denial, this order or decision and the denial of reconsideration are FINAL and may be appealed to superior court. The appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision denying reconsideration, UNLESS the denial is by inaction, in which case the appeal MUST be filed within 40 days after the date on which the application for reconsideration was filed. If the AOGCC grants an application for reconsideration, this order or decision does not become final. Rather, the order or decision on reconsideration will be the FINAL order or decision of the AOGCC, and it may be appealed to superior court. That appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision on reconsideration. In computing a period of time above, the date of the event or default after which the designated period begins to run is not included in the period; the last day of the period is included, unless it falls on a weekend or state holiday, in which event the period runs until 5:00 p.m. on the next day that does not fall on a weekend or state holiday. Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2024.09.05 21:57:02 -08'00' Gregory Wilson Digitally signed by Gregory Wilson Date: 2024.09.06 10:01:30 -08'00' From:Coldiron, Samantha J (OGC) To:AOGCC_Public_Notices Subject:[AOGCC_Public_Notices] Area Injection Orders 18E.005 and 18E.006 (CPAI) Date:Friday, September 6, 2024 10:21:21 AM Attachments:aio18E.005.pdf aio18E.006.pdf Docket Number: AIO-24-027 Request for Administrative Approval to Area Injection Order 18E; Water Injection Colville River Unit (CRU) CD2-57 (PTD 204-072), Alpine Oil Pool Docket Number: AIO-24-026 Request for Administrative Approval to Area Injection Order 18E; Water Injection Colville River Unit (CRU) CD4-213B (PTD 212-005), Alpine Oil Pool Samantha Coldiron AOGCC Special Assistant Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage, AK 99501 (907) 793-1223 __________________________________ List Name: AOGCC_Public_Notices@list.state.ak.us You subscribed as: samantha.coldiron@alaska.gov Unsubscribe at: https://list.state.ak.us/mailman/options/aogcc_public_notices/samantha.coldiron%40alaska.go v Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.alaska.gov ADMINISTRATIVE APPROVAL AREA INJECTION ORDER 18E.006 Ms. Kate Dodson Senior Well Integrity Engineer ConocoPhillips Alaska, Inc. P.O. Box 1000360 Anchorage, AK 99510 Re: Docket Number: AIO-24-026 Request for Administrative Approval to Area Injection Order 18E; Water Injection Colville River Unit (CRU) CD4-213B (PTD 212-005), Alpine Oil Pool Dear Ms. Dodson: By emailed letter dated August 30, 2024, ConocoPhillips Alaska, Inc. (CPAI) requested administrative approval to continue water injection with a known outer annulus (OA) to atmosphere pressure communication. In accordance with 20 AAC 25.556(d), the Alaska Oil and Gas Conservation Commission (AOGCC) hereby GRANTS, subject to conditions, CPAI’s request for administrative approval to continue water only injection in the subject well. CPAI reported to AOGCC on June 23, 2022, that the well had a surface casing leak at approximately 24 ft. In 2023, CPAI performed an unsuccessful leak repair. CPAI performed diagnostics including a passing non-witnessed mechanical integrity test (MIT) of the inner annulus on March 23, 2024, which indicates that the well exhibits at least two competent barriers to the release of well pressure. AOGCC believes CPAI can safely manage the OA to atmosphere pressure communication with periodic pressure bleeds by maintaining the inner annulus to a pressure not to exceed 2,000 psi and the outer annulus not to exceed 100 psi. Accordingly, the AOGCC believes that the well’s condition does not compromise overall well integrity so as to threaten human safety or the environment. AOGCC’s approval to continue water injection only in CRU CD4-213B is conditioned upon the following: 1. CPAI shall record wellhead pressures and injection rate daily; 2. CPAI shall submit to the AOGCC a monthly report of well pressures, injection rates, and pressure bleeds for all annuli. Bleeds to be flagged on the report; AIO 18E.006 September 6, 2024 Page 2 of 2 3. CPAI shall perform a MIT of the inner annulus every two years to the greater of the maximum anticipated injection pressure or 0.25 x packer TVD, but not less than 1500 psi; 4. CPAI shall limit the well’s inner annulus operating pressure to 2,000 psi and the outer annulus to 100 psi; 5. CPAI shall immediately shut in the well and notify the AOGCC if there is any change in the well's mechanical condition; 6. After well shut in due to a change in the well's mechanical condition, AOGCC approval shall be required to restart injection; and 7. The next required state-witnessed MITIA shall be completed within 10 days of restarting injection, when temperature and pressures have stabilized. Then the next MIT shall be completed before or during the month of June 2026. This is to align with the agreed upon CPAI Underground Injection Control MIT permanent test schedule for pad testing. DONE at Anchorage, Alaska and dated September 6, 2024. Jessie L. Chmielowski Gregory C. Wilson Commissioner Commissioner RECONSIDERATION AND APPEAL NOTICE As provided in AS 31.05.080(a), within 20 days after written notice of the entry of this order or decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration of the matter determined by it. If the notice was mailed, then the period of time shall be 23 days. An application for reconsideration must set out the respect in which the order or decision is believed to be erroneous. The AOGCC shall grant or refuse the application for reconsideration in whole or in part within 10 days after it is filed. Failure to act on it within 10 days is a denial of reconsideration. If the AOGCC denies reconsideration, upon denial, this order or decision and the denial of reconsideration are FINAL and may be appealed to superior court. The appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision denying reconsideration, UNLESS the denial is by inaction, in which case the appeal MUST be filed within 40 days after the date on which the application for reconsideration was filed. If the AOGCC grants an application for reconsideration, this order or decision does not become final. Rather, the order or decision on reconsideration will be the FINAL order or decision of the AOGCC, and it may be appealed to superior court. That appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision on reconsideration. In computing a period of time above, the date of the event or default after which the designated period begins to run is not included in the period; the last day of the period is included, unless it falls on a weekend or state holiday, in which event the period runs until 5:00 p.m. on the next day that does not fall on a weekend or state holiday. Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2024.09.05 21:58:10 -08'00' Gregory Wilson Digitally signed by Gregory Wilson Date: 2024.09.06 10:04:53 -08'00' From:Coldiron, Samantha J (OGC) To:AOGCC_Public_Notices Subject:[AOGCC_Public_Notices] Area Injection Orders 18E.005 and 18E.006 (CPAI) Date:Friday, September 6, 2024 10:21:21 AM Attachments:aio18E.005.pdf aio18E.006.pdf Docket Number: AIO-24-027 Request for Administrative Approval to Area Injection Order 18E; Water Injection Colville River Unit (CRU) CD2-57 (PTD 204-072), Alpine Oil Pool Docket Number: AIO-24-026 Request for Administrative Approval to Area Injection Order 18E; Water Injection Colville River Unit (CRU) CD4-213B (PTD 212-005), Alpine Oil Pool Samantha Coldiron AOGCC Special Assistant Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage, AK 99501 (907) 793-1223 __________________________________ List Name: AOGCC_Public_Notices@list.state.ak.us You subscribed as: samantha.coldiron@alaska.gov Unsubscribe at: https://list.state.ak.us/mailman/options/aogcc_public_notices/samantha.coldiron%40alaska.go v Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.alaska.gov ADMINISTRATIVE APPROVALS AREA INJECTION ORDER 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 Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.alaska.gov ADMINISTRATIVE APPROVAL AREA INJECTION ORDER 18E.009 Mr. Dusty Freeborn Well Integrity Engineer ConocoPhillips Alaska, Inc. P.O. Box 1000360 Anchorage, AK 99510 Re: Docket Number: AIO-25-031 Request for Administrative Approval to Area Injection Order 18E; Water Only Injection Colville River Unit (CRU) CD2-30 (PTD 2031350), Alpine Oil Pool Dear Mr. Freeborn: By emailed letter dated December 3, 2025, ConocoPhillips Alaska, Inc. (CPAI) requested administrative approval to continue water only injection with a known tubing by inner annulus (TxIA) pressure communication. In accordance with 20 AAC 25.556(d)1, the Alaska Oil and Gas Conservation Commission (AOGCC) hereby GRANTS, subject to conditions, CPAI’s request for administrative approval to continue water only injection in the subject well. CPAI reported a potential TxIA pressure communication to AOGCC on May 19, 2025, while the well was on gas injection. CPAI requested and AOGCC approved a monitoring and diagnostics period injecting water. The well does not exhibit signs of pressure communication while on water injection. On May 21, 2025, CPAI performed a passing non state-witnessed mechanical integrity test (MIT) of the inner annulus. This indicates thatCD2-30exhibits at least two competent barriers to the release of well pressure. AOGCC believes CPAI can safely manage the TxIA communication with periodic pressure bleeds by maintaining the inner annulus to a pressure not to exceed 2,000 psi and the outer annulus not to exceed 1,000 psi. Accordingly, the AOGCC believes that the well’s condition does not compromise overall well integrity so as to threaten human safety or the environment. 1 The application asked for an administrative approval under Rule 11 of AIO 18E, which granted the AOGCC the authority to administratively amend the order. This rule was made obsolete on February 10, 2018, when 20 AAC 25.556(d) became effective and authorized the AOGCC to administratively amend any order it has issued. AIO 18E.009 December 8, 2025 Page 2 of 2 AOGCC’s approval to continue water injection only in CRU CD2-30 is conditioned upon the following: 1) CPAI shall record wellhead pressures and injection rate daily; 2) CPAI shall submit to the AOGCC a monthly report of well pressures, injection rates, and pressure bleeds for all annuli. Bleeds to be flagged on the report; 3) CPAI shall perform a MIT of the inner annulus every two years to the greater of the maximum anticipated injection pressure or 0.25 x packer TVD, but not less than 1,500 psi; 4) CPAI shall limit the well’s inner annulus operating pressure to 2000 psi and the outer annulus operating pressure to 1000 psi during water injection. 5) CPAI shall immediately shut in the well and notify the AOGCC if there is any change in the well's mechanical condition; 6) After well shut in due to a change in the well's mechanical condition, AOGCC approval shall be required to restart injection; and 7) The next required state-witnessed MITIA is to be before or during the month of June 2026. This is to align with the agreed upon CPAI Underground Injection Control MIT permanent test schedule for pad testing. DONE at Anchorage, Alaska and dated December 8, 2025. Jessie L. Chmielowski Gregory C. Wilson Commissioner Commissioner RECONSIDERATION AND APPEAL NOTICE As provided in AS 31.05.080(a), within 20 days after written notice of the entry of this order or decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration of the matter determined by it. If the notice was mailed, then the period of time shall be 23 days. An application for reconsideration must set out the respect in which the order or decision is believed to be erroneous. The AOGCC shall grant or refuse the application for reconsideration in whole or in part within 10 days after it is filed. Failure to act on it within 10 days is a denial of reconsideration. If the AOGCC denies reconsideration, upon denial, this order or decision and the denial of reconsideration are FINAL and may be appealed to superior court. The appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision denying reconsideration, UNLESS the denial is by inaction, in which case the appeal MUST be filed within 40 days after the date on which the application for reconsideration was filed. If the AOGCC grants an application for reconsideration, this order or decision does not become final. Rather, the order or decision on reconsideration will be the FINAL order or decision of the AOGCC, and it may be appealed to superior court. That appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision on reconsideration. In computing a period of time above, the date of the event or default after which the designated period begins to run is not included in the period; the last day of the period is included, unless it falls on a weekend or state holiday, in which event the period runs until 5:00 p.m. on the next day that does not fall on a weekend or state holiday. Gregory C Wilson Digitally signed by Gregory C Wilson Date: 2025.12.08 08:00:02 -09'00' Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2025.12.08 08:34:28 -09'00' From:Coldiron, Samantha J (OGC) To:AOGCC_Public_Notices Subject:[AOGCC_Public_Notices] Area Injection Order 18E.009 (CPAI) Date:Monday, December 8, 2025 9:18:01 AM Attachments:AIO18E.009.pdf Docket Number: AIO-25-031 Request for Administrative Approval to Area Injection Order 18E; Water Only Injection Colville River Unit (CRU) CD2-30 (PTD 2031350), Alpine Oil Pool Samantha Coldiron AOGCC Special Assistant Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage, AK 99501 (907) 793-1223 __________________________________ List Name: AOGCC_Public_Notices@list.state.ak.us You subscribed as: samantha.coldiron@alaska.gov Unsubscribe at: https://list.state.ak.us/mailman/options/aogcc_public_notices/samantha.coldiron%40alaska.go v INDEXES 13 P.O. BOX 100360 ANCHORAGE, ALASKA 99510-0360 3rd of December 2025 Commissioner Chmielowski Alaska Oil & Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, AK 99501 Dear Commissioner Chmielowski, ConocoPhillips Alaska, Inc. presents the attached proposal per AIO 18E, Rule 11, to request administrative approval to allow well CD2-30 (PTD# 203-135) to be online in water-only injection service. Currently, the well displays TxIA communication only while injecting gas. If you need additional information, please contact me at (907)265-6218. Sincerely, Dusty Freeborn Well Integrity Engineer ConocoPhillips Alaska, Inc. By Samantha Coldiron at 2:00 pm, Dec 04, 2025 Dusty Freeborn Digitally signed by Dusty Freeborn Date: 2025.12.04 10:44:33 -09'00' 12/4/2025 1 ConocoPhillips Alaska, Inc. Alpine Well CD2-30 (PTD# 203-135) Technical Justification for Administrative Relief Request Purpose ConocoPhillips Alaska, Inc., proposes that the AOGCC approve this Administrative Relief request for Alpine injection well CD2-30 (PTD 203-135), as per Area Injection Order 18E, Rule 11, to allow water-only injection due to known tubing by inner annulus communication during gas injection service. Well History and Status Colville River Unit well CD2-30 (PTD# 203-135) was drilled and completed in 2003 as a service well for WAG injection. The well had a work over to add an additional packer and new 4.5” tubing in February of 2019. CD2-30 was reported to the Commission on 19 May 2025 for suspect inner annulus pressure increase during gas injection. Initial diagnostics yielded a passing MIT-IA and a failing IA draw down test. Subsequent diagnostics and AOGCC approved monitor periods suggested TxIA communication exists while the well in on gas injection. An additional AOGCC approved monitor period on water injection confirmed TxIA integrity while on water injection and the TxIA leak is only present during gas injection. ConocoPhillips requests administrative approval to allow continued water-only injection into CD2-30 due to known tubing by IA communication while on gas injection. Barrier and Hazard Evaluation Tubing: The 4-1/2”, 12.6 lb/ft, L-80 grade tubing has integrity to the packer at 10,742’ RKB based on a passing MITIA to 3300 psi performed on 21 May 2025, and a 30-day monitor period on water injection. Production casing: The 7”, 26 lb/ft, L-80 grade production casing has integrity to the packer at 10,742’ RKB based on the previously mentioned MITIA and monitor period. Surface casing: The well is completed with 9-5/8”, 36 lb/ft, J-55 grade surface casing with an internal yield pressure rating of 3520 psi. The surface casing is set at 3006’ MD (2380’ TVD). The surface casing displays pressure integrity based on current TIO trends. Primary barrier: The primary barrier to prevent a release from the well and provide zonal isolation during water injection is the tubing and packer. Secondary barrier: The production casing is the secondary barrier should the tubing or packer fail. Monitoring: Each well is monitored daily for wellhead pressure changes. Should leaks develop in the completion it will be noted during the daily monitoring process. Any pressure trends that indicate annular communication require investigation, Commission notification, and corrective action, up to and including a shut-in of the well. TIO trends are compiled, reviewed, and ubmitted to the AOGCC for review monthly. 12/4/2025 2 Approved Operating and Monitoring Plan 1. Well will be used for water injection (no MI or gas injection allowed). 2. Perform a passing MITIA every 2-years to maximum anticipated injection pressure. 3. Allow operating IA pressure up to 2,000 psi during water injection service; operating OA pressure up to 1,000 psi. 4. Submit monthly reports of daily tubing, IA, and OA pressures, injection volumes and pressure bleeds for all annuli. 5. Shut-in the well should diagnostic testing or injection rates and pressures indicate further problems with appropriate notification to the AOGCC. 6. MIT Anniversary date to be set the month June 2024 to align the 2-year AOGCC witnessed testing with the UIC MIT permanent 4-year scheduled pad testing. Submit to: OOPERATOR: FIELD / UNIT / PAD: DATE: OPERATOR REP: AOGCC REP: Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD 203-135 Type Inj G Tubing 4062 4056 4054 4058 Type Test P Packer TVD 7089 BBL Pump 3.0 IA 1623 3300 3191 3161 Interval O Test psi 1772 BBL Return 3.6 OA 627 634 635 634 Result P Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result TYPE INJ Codes TYPE TEST Codes INTERVAL Codes Result Codes W = Water P = Pressure Test I = Initial Test P = Pass G = Gas O = Other (describe in Notes) 4 = Four Year Cycle F = Fail S = Slurry V = Required by Variance I = Inconclusive I = Industrial Wastewater O = Other (describe in notes) N = Not Injecting ConocoPhillips Alaska Inc, Kuparuk / KRU / XX Pad VanCamp 05/21/25 Notes:Diagnostics MIT-IA Notes: CD2-30 Notes: Notes: Notes: STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION MMechanical Integrity Test jim.regg@alaska.gov;AOGCC.Inspectors@alaska.gov;phoebe.brooks@alaska.gov chris.wallace@alaska.gov Form 10-426 (Revised 01/2017)10-426 MIT-IA 21 May 2025.xlsx CD2-30 90-Day Bleed History WELL DATE STR-PRES END-PRES DIF-PRES CASING CD2-30 2025-11-03 1490 800 -690 IA Last Tag Annotation Depth (ftKB)Wellbore End Date Last Mod By Last Tag:CD2-30 lmosbor Last Rev Reason Annotation Wellbore End Date Last Mod By Rev Reason: SBHP, Set A1 CD2-30 10/14/2023 oberr Notes: General & Safety Annotation End Date Last Mod By NOTE: View Schematic w/ Alaska Schematic 10.03/11/2019 jennalt NOTE: In order to facilitate diagnostics, the IA should be circulated to clean fluid. 12/6/2016 pproven NOTE: Troubled with TxIA communication, & recently has demonstrated an elevated sustained IA pressur 12/6/2016 pproven NOTE: TREE: FMC 4 1/16 5K TREE CAP CONNECTION: 7" OTIS 10/29/2003 WV5.3 Conversio n Casing Strings Csg Des OD (in)ID (in)Top (ftKB) Set Depth (ftKB) Set Depth (TVD) (ftKB)Wt/Len (lb/ft)Grade Top Thread CONDUCTOR1615.06 37.0 109.0 109.062.50 H-40 WELDED SURFACE 9 5/8 8.92 36.7 3,006.3 2,379.8 36.00 J-55 BTC PRODUCTION 7 6.28 34.6 11,481.1 7,304.5 26.00 L-80 BTCM OPEN HOLE 6 1/8 6.13 11,481.0 15,700.0 7,298.8 Tubing Strings: "String Max Nominal OD" is the OD of the LONGEST segment in string Top (ftKB) 32.9 Set Depth… 10,838.2 Set Depth… 7,078.8 String Max No… 4 1/2 Tubing Description Tubing – Production Wt (lb/ft) 12.60 Grade L-80 Top Connection Hyd563 ID (in) 3.96 Completion Details: excludes tubing, pup, space out, thread, RKB... Top (ftKB) Top (TVD) (ftKB) Top Incl (°)Item Des OD Nominal (in)Com Make Model Nominal ID (in) 32.9 32.9 0.10 HANGER 4.500 FMC Tubing Hanger FMC 3.958 2,795.8 2,258.7 54.47 NIPPLE 5.200 "X" Nipple 3.813" HES X 3.813 10,676.96,998.5 57.30 INJ 5.9854-1/2" x 1" Camco KBG-2 GLM w/DCK-2 SOV 2000 psi csg- tbg, H563 bxp Camco KBG-23.895 10,742.2 7,033.0 59.55 PACKER 5.940 Premium Baker Packer, 4-1/2" x 7" Baker Premier 3.850 10,810.9 7,066.3 62.26 NIPPLE 5.200 "X" Nipple 3.813" HES X 3.813 10,831.0 7,075.6 62.87 SEAL ASSY 4.500 7" x 4-1/2" non-sealing overshot - 6.56' Swallow Baker Poorboy 4.640 Top (ftKB) 10,832.6 Set Depth… 10,938.2 Set Depth… 7,122.3 String Max No… 4 1/2 Tubing Description Tubing – Completion Lower Wt (lb/ft) 12.60 Grade L-80 Top Connection IBTM ID (in) 3.96 Completion Details: excludes tubing, pup, space out, thread, RKB... Top (ftKB) Top (TVD) (ftKB) Top Incl (°)Item Des OD Nominal (in)Com Make Model Nominal ID (in) 10,861.1 7,089.1 63.79 PACKER 5.970 4.5" X 7" BAKER S-3 PACKER w/ Millout ext. 5.97" OD x 3.875" ID BakerPremier 3.875 10,925.9 7,117.1 64.59 NIPPLE 5.200 4.5" "XN" NIPPLE HES XN 3.725 10,936.9 7,121.8 64.61 4 1/2" WLEG 5.000 4 1/2" WLEG 5" OD 3.875 Other In Hole (Wireline retrievable plugs, valves, pumps, fish, etc.) Top (ftKB) Top (TVD) (ftKB)Top Incl (°)Des Com Make Model SN Run Date ID (in) 2,795.8 2,258.7 54.47 INJ VALVE 4.5" Injection Valve on 3.813" X-Lock Halliburt on MCX42816 78-2 10/14/2023 1.563 10,831.0 7,075.6 62.87 OVERSHOT TUBING CUT @ 10,830' RKB 1/20/2019 3.958 Mandrel Inserts : excludes pulled inserts Top (ftKB) Top (TVD) (ftKB) Top Incl (°) St ati on No /S Serv Valve Type Latch Type OD (in) TRO Run (psi)Run Date Com Make Model Port Size (in) 10,676.9 6,998.5 57.30 1INJ DMY 1 2/17/2019Schlumb erger Camco DCK-2 0.000 Liner Details: Excludes Liner, Pup, Joints, casing, float, sub, shoe... Top (ftKB) Top (TVD) (ftKB) Top Incl (°)Item Des OD Nominal (in)Com Make Model Nominal ID (in) 11,481.0 7,304.5 79.12 OPEN HOLE 6.125 6.125 CD2-30, 10/15/2023 9:15:59 AM Vertical schematic (actual) OPEN HOLE; 11,481.0-15,700.0 PRODUCTION; 34.6-11,481.1 FLOAT SHOE; 11,479.0- 11,481.1 FLOAT COLLAR; 11,391.5- 11,392.9 4 1/2" WLEG; 10,936.9 NIPPLE; 10,925.9 PACKER; 10,861.1 OVERSHOT; 10,831.0 NIPPLE; 10,810.9 PACKER; 10,742.2 INJ; 10,676.8 SURFACE; 36.7-3,006.3 FLOAT SHOE; 3,004.0-3,006.3 FLOAT COLLAR; 2,917.9- 2,919.3 INJ VALVE; 2,795.8 NIPPLE; 2,795.7 CONDUCTOR; 37.0-109.0 HANGER; 36.7-38.9 HANGER; 34.6-37.2 HANGER; 32.9 WNS INJ KB-Grd (ft) 43.91 RR Date 10/30/200 3 Other Elev… Elevation Hi t CD2-30 ... TD Act Btm (ftKB) 15,700.0 Well Attributes Field Name ALPINE Wellbore API/UWI 501032046500 Wellbore Status INJ Max Angle & MD Incl (°) 92.17 MD (ftKB) 12,258.37 WELLNAME WELLBORE Annotation Last WO: End Date 2/14/2019 H2S (ppm)DateComment SSSV: NIPPLE 12 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 11 August 30, 2024 Commissioner Jessie Chmielowski Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, AK 99501 Commissioner Chmielowski, ConocoPhillips Alaska, Inc. presents the attached proposal per AIO 18E, Rule 11, to apply for Administrative Approval to allow CRU injection well CD4-213B (PTD 212-005) to remain in water only injection service. The well has known OA x Atmosphere communication. Please contact me at 265-6181 if you have any questions. Sincerely, Kate Dodson Well Integrity Specialist ConocoPhillips Alaska, Inc. By Samantha Coldiron at 12:46 pm, Sep 03, 2024 Digitally signed by Kate Dodson DN: OU=Wells, O=ConocoPhillips , CN=Kate Dodson, E= kate.dodson@conocophillips.com Reason: I am the author of this document Location: Date: 2024.08.30 12:05:16 -08'00' Foxit PDF Editor Version: 13.0.0 Kate Dodson Well Integrity Specialist 8/30/2024 1 ConocoPhillips Alaska, Inc. Alpine Well CD4-213B (PTD 212-005) Technical Justification for Administrative Relief Request Purpose ConocoPhillips Alaska, Inc. (CPAI) proposes that the AOGCC approve this Administrative Relief request as per Area Injection Order 18E, Rule 11, to continue water only injection for Alpine injection well CD4-213B (PTD 212-005) with known OA x Atmosphere communication. Well History and Status Colville River Unit well CD4-213B (PTD 212-005) was drilled and completed in 2006 as an injection well. On June 23rd, 2022, the well was reported to the AOGCC for a surface casing leak. The leak was identified at approximately 24ft. In 2023, CPAI attempted to repair the leak. The repair was unsuccessful. In preparation for AA request DHD performed passing tubing and inner casing pack off tests on March 22, 2024, and then a passing diagnostic MITIA to 3335 psi on March 23, 2024, proving integrity of the tubing and production casing. ConocoPhillips requests an AA which will allow the well to remain online in water only injection service. The well will remain shut in until approval is granted. After the well is returned to injection and stabilization is achieved, a witnessed MITIA will be scheduled with AOGCC inspectors. Barrier and Hazard Evaluation Tubing: The 4-1/2” 12.6 lb L-80 tubing has integrity to the packer at 12,013’ MD (7,315’ TVD), based on passing diagnostic MIT-IA to 3335 psi on March 23, 2024, and TIO trends. Production casing: The 7”, 26 lb., L-80 production casing has integrity to the packer at 12,013’ MD (7,315’ TVD), based on the passing diagnostic MIT-IA to 3335 psi on March 23, 2024, and TIO trends. Surface casing: The surface casing has a known leak at ~24’. Primary barrier: The primary barrier to prevent a release from the well and provide zonal isolation is the tubing and packer at 12,013’ MD (7,315’ TVD). Secondary barrier: The secondary barrier to prevent a release from the well and provide zonal isolation is the production casing. Monitoring: Each well is monitored daily for wellhead pressure changes. Should leaks develop in the tubing or production casing it will be noted during the daily monitoring process. Any pressure trends that indicate annular communication require investigation, Commission notification, and corrective action, up to and including a shut-in of the well. T/IO plots are compiled, reviewed, and submitted to the AOGCC monthly. Proposed Operating and Monitoring Plan Well Integrity Specialist 8/30/2024 2 1. Well will be used for water only injection (no MI or gas injection allowed). 2. Perform a passing MITIA every 2-years to maximum anticipated injection pressure. 3. Allow operating IA pressure up to 2000 psi, operating OA pressure up to 100 psi. 4. Submit monthly reports of daily tubing, IA & OA pressures, injection volumes and pressure bleeds for all annuli. 5. Shut-in the well with appropriate notification to the AOGCC should diagnostic testing or injection rates and pressures indicate additional problems. 6. Anniversary date to be set the month of June to align the AOGCC biennial AA witnessed testing with the UIC MIT permanent 4-year scheduled pad testing. CD4-213B 90-Day Bleed History WELL DATE STR-PRES END-PRES DIF-PRES CASING Last Tag Annotation Depth (ftKB) Wellbore End Date Last Mod By Last Tag: 12,359' RKB 12,359.0 CD4-213B 5/3/2022 oberr Last Rev Reason Annotation Wellbore End Date Last Mod By Rev Reason: Set Plug for SCR CD4-213B 12/11/2022 boehmbh Notes: General & Safety Annotation End Date Last Mod By NOTE: RIG WORKOVER CHANGE TUBING STRING 3/12/2016 pproven NOTE: SIDETRACK TO B 11/12/2014 smsmith Casing Strings Csg Des OD (in) ID (in) Top (ftKB) Set Depth (ftKB) Set Depth (TVD) (ftKB) Wt/Len (lb/ft) Grade Top Thread CONDUCTOR 16 15.25 36.4 114.0 114.0 65.00 H-40 SURFACE 9 5/8 8.83 36.7 2,713.1 2,381.5 40.00 L-80 INTERMEDIATE 7 6.28 34.1 12,203.5 7,395.8 26.00 L-80 BTC-M WINDOW 7 6.28 2,491.0 2,511.0 2,242.0 LINER 4 1/2 3.96 12,012.7 12,413.0 7,470.8 12.60 L-80 Hyd 563 Tubing Strings: string max indicates LONGEST segment of string Top (ftKB) 31.1 Set Depth … 12,029.1 Set Depth … 7,322.7 String Ma… 4 1/2 Tubing Description Tubing – Production Wt (lb/ft) 12.60 Grade L-80 Top Connection Hyd 563 ID (in) 3.96 Completion Details: excludes tubing, pup, space out, thread, RKB... Top (ftKB) Top (TVD) (ftKB) Top Incl (°) Item Des OD Nominal (in)Com Make Model Nominal ID (in) 31.1 31.1 0.00 HANGER 4.500 FMC 4 1/2'' Tubing Hanger Bottom Thread TXP FMC Unihead horizona l Gen II, 4 1/16" 5K 3.958 2,286.9 2,081.7 42.69 NIPPLE 5.210 4 1/2'' Camco DB Nipple 5.62'' OD x 3.813'' ID CAMCO 3.813" DB 3.813 11,897.4 7,259.2 60.06 GAS LIFT 5.990 Camco KBG-2 GLM with DCK-2 Valve Shear @ 2500 PSI annulus to tbg CAMCO KBG-2 3.860 11,963.2 7,291.5 61.02 PACKER 7.000 Baker 4 1/2'' x 7'' Premier Packer Assembly Baker Premier 3.890 11,993.8 7,306.2 61.72 NIPPLE 5.030 HES "X" Nipple ( 3.813'' Profile) OTIS 3.813" X 3.813 12,012.8 7,315.2 62.23 LOCATOR 5.750 Shear Pin Fluted No-Go Sub 3.900 12,028.1 7,322.2 62.65 WLEG 4.850 Wireline Entry Guide Baker WLEG 3.950 Other In Hole (Wireline retrievable plugs, valves, pumps, fish, etc.) Top (ftKB) Top (TVD) (ftKB)Top Incl (°)Des Com Make Model SN Run Date ID (in) 2,491.0 2,227.7 44.32 Whipstock Baker XL Gen II whipstock slide. Tagged bridge plug at 2515', set WS 50°R. TOW at 2491', BOW at 2511' 11/18/2014 11,931.0 7,275.8 60.55 PLUG Quadco RBP, Set with DPU Quadco RBP 12/11/2022 0.000 11,993.0 7,305.8 61.70 PLUG XX Plug- Passed MITT, Failed DDT 12/8/2022 0.000 Mandrel Inserts : excludes pulled inserts Top (ftKB) Top (TVD) (ftKB) Top Incl (°) St ati on No /S Serv Valve Type Latch Type OD (in) TRO Run (psi) Run Date Com Make Model Port Size (in) 11,897.4 7,259.2 60.06 1 GAS LIFT DMY BK 1" 1 0.0 3/19/2016 0.000 Liner Details: Excludes Liner, Pup, Joints, casing, float, sub, shoe... Top (ftKB) Top (TVD) (ftKB) Top Incl (°) Item Des OD Nominal (in)Com Make Model Nominal ID (in) 12,012.7 7,315.1 62.23 PACKER 5.000 BAKER HRD-E ZXP LINER TOP PACKER Baker ZXP 3.875 12,049.1 7,331.8 63.21 XO BUSHING 4.500 BAKER XO BUSHING H521 x H563 3.958 12,091.2 7,350.4 64.44 NIPPLE 4.500 XN NIPPLE NO-G0 Camco XN 3.725 12,249.2 7,412.6 68.86 SWELL PACKER 4.500 TAM FREECAP II FSC-11 SWELL PACKER (3' seal, water activated) Slip on Tam FCS-11 3.958 12,347.3 7,447.5 69.23 FRAC SLEEVE 5.610 BAKER PRESSURE ACTIVATED FRAC SLEEVE Baker P Sleeve 3.890 12,353.9 7,449.8 69.23 FRAC SLEEVE 5.610 BAKER PRESSURE ACTIVATED FRAC SLEEVE Baker P Sleeve 3.890 12,360.4 7,452.2 69.23 VALVE 5.000 BAKER WELLBORE ISOLATION VALVE Baker WIV 3.958 Perforations & Slots Top (ftKB) Btm (ftKB) Top (TVD) (ftKB) Btm (TVD) (ftKB) Linked Zone Date Shot Dens (shots/ft)Type Com 12,347.3 12,350.0 7,447.5 7,448.4 12/12/2014 PERFP FRAC PORT 12,353.9 12,356.6 7,449.8 7,450.8 12/12/2014 PERFP FRAC PORT Cement Squeezes Top (ftKB) Btm (ftKB) Top (TVD) (ftKB) Btm (TVD) (ftKB) Des Com Pump Start Date 4,911.0 5,780.0 3,625.9 4,079.8 CMT PLUG 9/18/2014 HORIZONTAL, CD4-213B, 6/13/2023 1:08:32 PM Vertical schematic (actual) LINER; 12,012.7-12,413.0 PERFP; 12,353.9-12,356.6 PERFP; 12,347.3-12,350.0 INTERMEDIATE; 34.1-12,203.5 PLUG; 11,993.0 PACKER; 11,963.2 PLUG; 11,931.0 GAS LIFT; 11,897.4 CMT PLUG; 4,911.0 ftKB SURFACE; 36.7-2,713.1 WINDOW; 2,491.0-2,511.0 Whipstock; 2,491.0 CONDUCTOR; 36.4-114.0 HANGER; 31.1 WNS INJ KB-Grd (ft) 37.10 RR Date 1/6/2007 Other Elev… CD4-213B ... TD Act Btm (ftKB) 12,420.0 Well Attributes Field Name NANUQ Wellbore API/UWI 501032054002 Wellbore Status INJ Max Angle & MD Incl (°) 69.24 MD (ftKB) 12,268.90 WELLNAME WELLBORECD4-213B Annotation Last WO: End Date 3/12/2016 H2S (ppm) DateComment SSSV: NIPPLE 10 August 30, 2024 Commissioner Jessie Chmielowski Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, AK 99501 Commissioner Chmielowski, ConocoPhillips Alaska, Inc. presents the attached proposal per AIO 18E, Rule 11, to apply for Administrative Approval to allow CRU injection well CD2-57 (PTD 204-072) to remain in water only injection service. The well has known OA x Atmosphere communication. Please contact me at 265-6181 if you have any questions. Sincerely, Kate Dodson Well Integrity Specialist ConocoPhillips Alaska, Inc. By Samantha Coldiron at 12:50 pm, Sep 03, 2024 Digitally signed by Kate Dodson DN: OU=Wells, O= ConocoPhillips, CN=Kate Dodson, E=kate.dodson@ conocophillips.com Reason: I am the author of this document Location: Date: 2024.08.30 12:32:52-08'00' Foxit PDF Editor Version: 13.0.0 Kate Dodson Well Integrity Specialist 8/30/2024 1 ConocoPhillips Alaska, Inc. Alpine Well CD2-57 (PTD 204-072) Technical Justification for Administrative Relief Request Purpose ConocoPhillips Alaska, Inc. (CPAI) proposes that the AOGCC approve this Administrative Relief request as per Area Injection Order 18E, Rule 11, to continue water only injection for Alpine injection well CD2-57 (PTD 204-072) with known OA x Atmosphere communication. Well History and Status Colville River Unit well CD2-57 (PTD 204-072) was drilled and completed in 2004 as an injection well. On July 2nd, 2024, the well was reported to the AOGCC for a failed surface casing leak detect. The leak was identified at approximately 24ft. The well passed tubing and inner casing pack off tests on June 28, 2024, and then a passing diagnostic MITIA to 2500 psi on July 3rd, 2024, proving integrity of the tubing and production casing. ConocoPhillips requests an AA which will allow the well to remain online in water only injection service. The well will remain shut in until approval is granted. After the well is returned to injection and stabilization is achieved, a witnessed MITIA will be scheduled with AOGCC inspectors. Barrier and Hazard Evaluation Tubing: The 4-1/2” 12.6 lb L-80 tubing has integrity to the packer at 11,932’ MD (7,000’ TVD), based on passing diagnostic MIT-IA to 2500 psi on July 3rd, 2024, and TIO trends. Production casing: The 7”, 26 lb., L-80 production casing has integrity to the packer at 11,932’ MD (7,000’ TVD), based on the passing diagnostic 2500 psi on July 3rd, 2024, and TIO trends. Surface casing: The surface casing has a known leak at ~24’. Primary barrier: The primary barrier to prevent a release from the well and provide zonal isolation is the tubing and packer at 11,932’ MD (7,000’ TVD). Secondary barrier: The secondary barrier to prevent a release from the well and provide zonal isolation is the production casing. Monitoring: Each well is monitored daily for wellhead pressure changes. Should leaks develop in the tubing or production casing it will be noted during the daily monitoring process. Any pressure trends that indicate annular communication require investigation, Commission notification, and corrective action, up to and including a shut-in of the well. T/IO plots are compiled, reviewed, and submitted to the AOGCC monthly. Well Integrity Specialist 8/30/2024 2 Proposed Operating and Monitoring Plan 1. Well will be used for water only injection (no MI or gas injection allowed). 2. Perform a passing MITIA every 2-years to maximum anticipated injection pressure. 3. Allow operating IA pressure up to 2000 psi, operating OA pressure up to 100 psi. 4. Submit monthly reports of daily tubing, IA & OA pressures, injection volumes and pressure bleeds for all annuli. 5. Shut-in the well with appropriate notification to the AOGCC should diagnostic testing or injection rates and pressures indicate additional problems. 6. Anniversary date to be set the month of June to align the AOGCC biennial AA witnessed testing with the UIC MIT permanent 4-year scheduled pad testing. CD2-57 90-Day Bleed History WELL DATE STR-PRES END-PRES DIF-PRES CASING CD2-57 2024-06-11 47.0 200 153.0 OA CD2-57 2024-07-13 220.0 145 -75.0 IA Last Tag Annotation Depth (ftKB)Wellbore End Date Last Mod By Last Tag:CD2-57 lmosbor Last Rev Reason Annotation Wellbore End Date Last Mod By Rev Reason: Pull A1, Drift, SBHP, Set A1 CD2-57 5/18/2024 oberr Notes: General & Safety Annotation End Date Last Mod By NOTE: VIEW SCHEMATIC w/Alaska Schematic9.011/3/2010 hipshkf NOTE: TREE: FMC 4-1/16 5K - TREE CAP CONNECTION: 7" OTIS6/4/2004WV5.3 Conversio n Casing Strings Csg Des OD (in)ID (in)Top (ftKB) Set Depth (ftKB) Set Depth (TVD) (ftKB)Wt/Len (lb/ft)Grade Top Thread CONDUCTOR1614.69 38.0 114.0 114.0 109.00 H-40 WELDED SURFACE 9 5/8 8.92 36.7 3,391.2 2,378.4 36.00 J-55 BTC PRODUCTION 7 6.28 34.5 12,642.4 7,248.0 26.00 L-80 BTCM OPEN HOLE 6 1/8 12,642.4 16,432.0 7,295.9 Tubing Strings: "String Max Nominal OD" is the OD of the LONGEST segment in string Top (ftKB) 32.5 Set Depth… 11,995.9 Set Depth… 7,033.9 String Max No… 4 1/2 Tubing Description TUBING Wt (lb/ft) 12.60 Grade L-80 Top Connection IBTM ID (in) 3.96 Completion Details: excludes tubing, pup, space out, thread, RKB... Top (ftKB) Top (TVD) (ftKB) Top Incl (°)Item Des OD Nominal (in)Com Make Model Nominal ID (in) 32.532.50.00 HANGER 10.800 FMC TUBING HANGER 4.500 2,666.0 1,997.4 58.42 NIPPLE 5.620 CAMCO 'DB' NIPPLE 3.812 11,817.66,939.1 57.01 GAS LIFT 5.984 CAMCO KBG-23.938 11,932.0 7,000.5 58.13 PACKER 5.970 BAKER S-3 PACKER w/MILLOUT EXTENSION 3.875 11,983.5 7,027.5 58.83 NIPPLE 5.000 HES 'XN' NIPPLE 3.725 11,994.5 7,033.1 58.98 WLEG 5.000 BAKER WLEG 3.875 Other In Hole (Wireline retrievable plugs, valves, pumps, fish, etc.) Top (ftKB) Top (TVD) (ftKB)Top Incl (°)Des Com Make Model SN Run Date ID (in) 2,666.01,997.4 58.42 INJ VALVE 4.5" A1 Injection Valve on 3.812" DB Lock (OAL-= 41") Camco A1 HWS- 210 5/16/2024 1.250 Mandrel Inserts : excludes pulled inserts Top (ftKB) Top (TVD) (ftKB) Top Incl (°) St ati on No /S Serv Valve Type Latch Type OD (in) TRO Run (psi)Run Date Com Make Model Port Size (in) 11,817.6 6,939.1 57.01 1 GAS LIFT DMY BK 1 0.06/22/2004 0.000 Liner Details: Excludes Liner, Pup, Joints, casing, float, sub, shoe... Top (ftKB) Top (TVD) (ftKB) Top Incl (°)Item Des OD Nominal (in)Com Make Model Nominal ID (in) 12,642.4 7,248.0 83.79 OPEN HOLE 6.125 CD2-57, 5/18/2024 10:07:11 AM Vertical schematic (actual) OPEN HOLE; 12,642.4-16,432.0 OPEN HOLE; 12,642.4-16,432.0 PRODUCTION; 34.5-12,642.4 FLOAT SHOE; 12,640.2- 12,642.4 FLOAT COLLAR; 12,552.0- 12,553.3 WLEG; 11,994.5 NIPPLE; 11,983.5 PACKER; 11,932.0 GAS LIFT; 11,817.6 SURFACE; 36.7-3,391.2 FLOAT SHOE; 3,388.9-3,391.2 FLOAT COLLAR; 3,301.3- 3,302.8 INJ VALVE; 2,666.0 NIPPLE; 2,666.0 CONDUCTOR; 38.0-114.0 HANGER; 36.7-38.9 HANGER; 34.5-36.3 HANGER; 32.5 WNS INJ KB-Grd (ft) 44.30 RR Date 6/5/2004 Other Elev… CD2-57 ... TD Act Btm (ftKB) 16,432.0 Well Attributes Field Name ALPINE Wellbore API/UWI 501032049200 Wellbore Status INJ Max Angle & MD Incl (°) 91.25 MD (ftKB) 15,215.09 WELLNAME WELLBORE Annotation Last WO: End DateH2S (ppm)DateComment SSSV: WRDP 9 P.O. BOX 100360 ANCHORAGE, ALASKA 99510-0360 February 23, 2024 Commissioner Jessie Chmielowski Alaska Oil & Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, AK 99501 Commissioner Chmielowski: ConocoPhillips Alaska, Inc. (CPAI) requests to amend administrative approval AIO18E.002 for CRU CD3-118 (PTD 208-025). CPAI would like to modify the date in condition 10 to match the agreed upon CPAI Underground Injection Control MIT permanent test schedule for pad testing. The MIT 4-year test schedule was updated via email approval in January of 2024. The update changed the 4yr test schedule on CD3 pad from February to March. CPAI would like the next required MIT to be before or during the month of March 2024. This is to align with the agreed upon CPAI Underground Injection Control MIT permanent test schedule for pad testing. If you need additional information, please contact me at your convenience. Sincerely, Kate Dodson Well Integrity Engineer ConocoPhillips Alaska, Inc. By Samantha Coldiron at 10:09 am, Feb 28, 2024 Digitally signed by Kate Dodson DN: OU=Wells, O=ConocoPhillips, CN= Kate Dodson, E=kate.dodson@ conocophillips.com Reason: I am the author of this document Location: Date: 2024.02.23 10:10:19-09'00' Foxit PDF Editor Version: 13.0.0 Kate Dodson ConocoPhillips Alaska, Inc. UIC MIT Permanent Test Schedule Revised January 29, 2024 Year 1 Kuparuk Alpine May 2A, 2B, 2G, 2H June 1F, 1L, 2M, 2V July 2E, 2F, 3J, 3M MT6, MT7 August 3N, 3Q, 3R, 2P* Year 2 May 3K June 1B & WSW, 2T, 3H, 30 CD1 July 1Q, 1Y August 1H, 2C, 2D, 3A, 3C Year 3 March CD3 May 1C, 1J June 1E CD2 July 1D, 2S August 2L, 2N, 2P*, 2U, 3S Year 4 May 1R, 2W June 2K, 2X, 3B, 3F CD4 July 1A, 1G, 3I August 3G, 2Z CD5 Note: Year 1=2024 2P* is on a 2-year test cycle Target 4-year Cycle: The following schedule repeats every 4 years 1 WNS Integrity From:Regg, James B (OGC) <jim.regg@alaska.gov> Sent:Monday, February 5, 2024 12:34 PM To:Dodson, Kate; Earhart, Will C; WNS Integrity Cc:Brooks, Phoebe L (OGC); Wallace, Chris D (OGC); Carlisle, Samantha J (OGC) Subject:RE: [EXTERNAL]RE: CPAI Request to amend 4yr MIT Schedule MITs on CRU CD3 pad were last done in February 2022, March 2022, April 2022, and April 2023. In addi!on to ice road availability as jus!fica!on, AOGCC supports a single test month for future 4-year cycle MITs on CRU CD3 pad. Next 4- year MITs for CD3 injectors must occur in March 2026. The schedule for wells that are on an increased test frequency should follow the requirements in Administra!ve Approvals. Jim Regg Supervisor, Inspections AOGCC 333 W. 7th Ave, Suite 100 Anchorage, AK 99501 907-793-1236 From: Dodson, Kate <Kate.Dodson@conocophillips.com> Sent: Tuesday, January 30, 2024 3:30 PM To: Regg, James B (OGC) <jim.regg@alaska.gov> Cc: Brooks, Phoebe L (OGC) <phoebe.brooks@alaska.gov> Subject: RE: [EXTERNAL]RE: CPAI Request to amend 4yr MIT Schedule Hi Jim, That is correct. The CD3 ice road is planned to open in early to mid- March. -Kate From: Regg, James B (OGC) <jim.regg@alaska.gov> Sent: Tuesday, January 30, 2024 9:22 AM To: Dodson, Kate <Kate.Dodson@conocophillips.com> Cc: Brooks, Phoebe L (OGC) <phoebe.brooks@alaska.gov> Subject: [EXTERNAL]RE: CPAI Request to amend 4yr MIT Schedule CAUTION:This email originated from outside of the organization. Do not click links or open attachments unless you recognize the sender and know the content is safe. Received your request. Your jus!fica!on is unclear – are you saying the annual ice road to CD3 pad will not be available un!l March? Jim Regg You don't often get email from kate.dodson@conocophillips.com. Learn why this is important 2 Supervisor, Inspections AOGCC 333 W. 7th Ave, Suite 100 Anchorage, AK 99501 907-793-1236 From: AOGCC Permitting (CED sponsored) <aogcc.permitting@alaska.gov> Sent: Monday, January 29, 2024 3:04 PM To: Regg, James B (OGC) <jim.regg@alaska.gov>; Brooks, Phoebe L (OGC) <phoebe.brooks@alaska.gov> Subject: FW: CPAI Request to amend 4yr MIT Schedule Please let me know if you need a docket for this. Thanks, Sam From: Dodson, Kate <Kate.Dodson@conocophillips.com> Sent: Monday, January 29, 2024 2:09 PM To: AOGCC Permitting (CED sponsored) <aogcc.permitting@alaska.gov> Cc: WNS Integrity <WNSIntegrity@conocophillips.com>; Earhart, Will C <William.C.Earhart@conocophillips.com>; Wallace, Chris D (OGC) <chris.wallace@alaska.gov> Subject: CPAI Request to amend 4yr MIT Schedule Good afternoon, Please see attached with proposed amendment to the 4yr MIT schedule. In support of Ice road access to CD3, ConocoPhillips requests to change the testing on CD3 from February to March. The latest schedule revision is attached to reflect this proposal. If you need additional information, please contact me at 265-6181. Thanks, Kate Dodson | Senior Well Integrity Engineer ConocoPhillips Alaska | AK Intervention & Integrity O: 907-265-6181 | M: 435-640-7200 | Kate.Dodson@conocophillips.com Some people who received this message don't often get email from kate.dodson@conocophillips.com. Learn why this is important CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.alaska.gov ADMINISTRATIVE APPROVAL AREA INJECTION ORDER 18E.002 March 31, 2022 Mr. Dusty Freeborn Well Integrity & Compliance Specialist ConocoPhillips Alaska, Inc. P.O. Box 1000360 Anchorage, AK 99510 Re: Docket Number: AIO-22-009 Request for Administrative Approval to Area Injection Order 18E; Water Alternating Gas Injection Colville River Unit (CRU) CD3-118 (PTD 2080250), Alpine Oil Pool Dear Mr. Freeborn: By emailed letter dated March 24, 2022, ConocoPhillips Alaska, Inc. (CPAI) requested administrative approval to continue water alternating gas (WAG) injection with a known tubing by inner annulus (TxIA) pressure communication. In accordance with 20AAC 25.556(d), the Alaska Oil and Gas Conservation Commission (AOGCC) hereby GRANTS, subject to conditions, CPAI’s request for administrative approval to continue WAG injection in the subject well. CPAI reported a potential TxIA pressure communication to AOGCC on February 15, 2022, while the well was on miscible injectant (MI)/gas injection. CPAI requested and AOGCC approved a monitoring and diagnostics period on MI. On February 24, 2022, CPAI performed additional diagnostics including a passing non state-witnessed mechanical integrity test (MIT) of the inner annulus (to a test pressure of 4,120 psi which is greater than the anticipated gas injection pressure of 3,800 psi). This indicates that CD3-118 exhibits at least two competent barriers to the release of well pressure. CPAI maintains live transmitters on the inner and outer annulus and alarm and remote shut down functions in the Supervisory Control and Data Acquisition (SCADA) system that create layers of protection from an over-pressure event. AOGCC believes CPAI can safely manage the TxIA communication with periodic pressure bleeds by maintaining the inner annulus to a pressure not to exceed 2,400 psi and the outer annulus not to exceed 1,000 psi. Accordingly, the AOGCC believes that the well’s condition does not compromise overall well integrity so as to threaten human safety or the environment. AIO 18E.002 March 31, 2022 Page 2 of 3 AOGCC’s approval to continue WAG injection in CRU CD3-118 is conditioned upon the following: 1) CPAI shall record wellhead pressures and injection rate daily; 2) CPAI shall submit to the AOGCC a monthly report of well pressures, injection rates, and pressure bleeds for all annuli. Bleeds to be flagged on the report; 3) CPAI shall perform a MIT of the inner annulus every two years to the greater of the maximum anticipated injection pressure or 0.25 x packer TVD, but not less than 1,500 psi; 4) CPAI shall limit the well’s inner annulus operating pressure to 2,400 psi during gas injection and 2,000 psi during water injection. Audible control room alarms shall be set at or below these limits; 5) CPAI shall limit the well’s outer annulus operating pressure to 1,000 psi. Audible control room alarms shall be set at or below these limits; 6) CPAI shall monitor the inner and outer annulus pressures in real time with its SCADA system; 7) CPAI shall maintain the injection line choke and surface safety valve (SSV) remote shut down capability. During gas injection, the IA protocols will include a drill site operator alarm set at 2,200 psi, and a high alarm set at 2,400 psi that will prompt the control room Board Operator to remotely shut in the choke or SSV; 8) CPAI shall immediately shut in the well and notify the AOGCC if there is any change in the well's mechanical condition; 9) After well shut in due to a change in the well's mechanical condition, AOGCC approval shall be required to restart injection; and 10)The next required MIT is to be before or during the month of February 2024. This is to align with the agreed upon CPAI Underground Injection Control MIT permanent test schedule for pad testing. DONE at Anchorage, Alaska and dated March 31, 2022. Jeremy M. Price Daniel T. Seamount, Jr. Jessie L. Chmielowski Chair, Commissioner Commissioner Commissioner February 2024 AIO 18E.002 March 31, 2022 Page 3 of 3 RECONSIDERATION AND APPEAL NOTICE As provided in AS 31.05.080(a), within 20 days after written notice of the entry of this order or decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration of the matter determined by it. If the notice was mailed, then the period of time shall be 23 days. An application for reconsideration must set out the respect in which the order or decision is believed to be erroneous. The AOGCC shall grant or refuse the application for reconsideration in whole or in part within 10 days after it is filed. Failure to act on it within 10 days is a denial of reconsideration. If the AOGCC denies reconsideration, upon denial, this order or decision and the denial of reconsideration are FINAL and may be appealed to superior court. The appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision denying reconsideration, UNLESS the denial is by inaction, in which case the appeal MUST be filed within 40 days after the date on which the application for reconsideration was filed. If the AOGCC grants an application for reconsideration, this order or decision does not become final. Rather, the order or decision on reconsideration will be the FINAL order or decision of the AOGCC, and it may be appealed to superior court. That appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision on reconsideration. In computing a period of time above, the date of the event or default after which the designated period begins to run is not included in the period; the last day of the period is included, unless it falls on a weekend or state holiday, in which event the period runs until 5:00 p.m. on the next day that does not fall on a weekend or state holiday. Submit to: OOPERATOR: FIELD / UNIT / PAD: DATE: OPERATOR REP: AOGCC REP: Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD 208-025 Type Inj G Tubing 3818 3818 3822 3816 Type Test O Packer TVD 6593 BBL Pump 6.6 IA 125 4200 4135 4120 Interval O Test psi 1648 BBL Return 5.5 OA 204 347 346 344 Result P Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result TYPE INJ Codes TYPE TEST Codes INTERVAL Codes Result Codes W = Water P = Pressure Test I = Initial Test P = Pass G = Gas O = Other (describe in Notes) 4 = Four Year Cycle F = Fail S = Slurry V = Required by Variance I = Inconclusive I = Industrial Wastewater O = Other (describe in notes) N = Not Injecting ConocoPhillips Alaska Inc, Alpine / CRU / CD3 Pad Van Camp 02/24/22 Notes:Diagnostic testing for AA prep Notes: CD3-118 Notes: Notes: Notes: STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION MMechanic al Integri ty Tes t jim.regg@alaska.gov;AOGCC.Inspectors@alaska.gov;phoebe.brooks@alaska.gov chris.wallace@alaska.gov Form 10-426 (Revised 01/2017)CD3-118 Diagnostic MIT-IA 24 Feb 2022.xlsx 8 P.O. BOX 100360 ANCHORAGE, ALASKA 99510-0360 June 5, 2023 Commissioner Jessie Chmielowski Alaska Oil & Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, AK 99501 Commissioner Chmielowski: ConocoPhillips Alaska, Inc. (CPAI) presents the attached cancellation request for Administrative Approval AIO 18E.003. CRU CD3-302A (PTD 210-035) was granted AIO 18E.003 on September 8, 2022, due to known TxIA communication. A RWO was completed in March of 2023. After the RWO, the well completed a monitor period on gas injection and no TxIA communication was observed. As the RWO repaired the annular communication, AIO 18E.003 is no longer needed. CPAI requests that AIO 18E.003 be canceled and that CD3-302A be returned to normal WAG operation. If you need additional information, please contact us at your convenience. Sincerely, Kate Dodson Senior Well Integrity Engineer ConocoPhillips Alaska, Inc. Office phone: 907-265-6181 Email: wnsintegrity@conocophillips.com Kate Dodson Digitally signed by Kate Dodson Date: 2023.06.05 16:47:44 -08'00' CD3-302A 90-Day Bleed History WELL DATE STR-PRES END-PRES DIF-PRES CASING CD3-302 2023-03-31 985.0 600 -385.0 OA CD3-302 2023-04-02 1000.0 700 -300.0 OA CD3-302 2023-04-30 1855.0 1350 -505.0 IA Last Tag Annotation Depth (ftKB)Wellbore End Date Last Mod By Last Tag: SLM 12,449.0CD3-302A 9/23/2011 ninam Last Rev Reason Annotation Wellbore End Date Last Mod By Rev Reason: Set DMY, pulled B&R / RHC / Set A1 - post RWOCD3-302A 3/14/2023 rmoore22 Notes: General & Safety Annotation End Date Last Mod By NOTE: Welded 9"x0.500" Conductor extension 4/5/2022 mouser NOTE: Well SIDETRACKED, OLD PROD CSG CUT @ 2673' 4/18/2010 osborl Casing Strings Csg Des OD (in)ID (in)Top (ftKB) Set Depth (ftKB) Set Depth (TVD) (ftKB)Wt/Len (lb/ft)Grade Top Thread INTERMEDIATE 7 6.28 24.8 12,592.9 6,935.2 26.40 L-80 BTCM Tubing Strings: string max indicates LONGEST segment of string Top (ftKB) 24.5 Set Depth … 12,072.5 Set Depth… 6,690.6 String Ma… 4 1/2 Tubing Description Tubing – Completion Upper Wt (lb/ft) 12.60 Grade L-80 Top Connection Hyd563 ID (in) 3.96 Completion Details: excludes tubing, pup, space out, thread, RKB... Top (ftKB) Top (TVD) (ftKB) Top Incl (°)Item Des OD Nominal (in)Com Make Model Nominal ID (in) 2,160.4 2,070.233.82 Nipple - Landing 4.500 HES 3.813'' Landing Nipple "X" HES X Nipple 3.813 11,925.36,631.366.58 Mandrel – GAS LIFT 4.500 Camco DCK-2 GLM (3.883" ID)Camco DCK-2 GLM 3.860 11,988.26,656.4 66.29 Permanent Packer 5.720 7" x 4½ D & L Packer D&L Packer 4.000 12,049.66,681.266.01 Nipple - Landing 4.500 HES 3.813'' Landing Nipple "X" HES X Nipple 3.813 12,066.4 6,688.165.93 Overshot 5.960 Baker PoorBoy Over Shot 5' of swallow Spaced 1' off NoGo Baker Oversho t 4.670 Top (ftKB) 12,068.6 Set Depth … 12,211.9 Set Depth… 6,748.6 String Ma… 4 1/2 Tubing Description Tubing – Completion Lower Wt (lb/ft) 12.60 Grade L-80 Top Connection IBTM ID (in) 3.96 Completion Details: excludes tubing, pup, space out, thread, RKB... Top (ftKB) Top (TVD) (ftKB) Top Incl (°)Item Des OD Nominal (in)Com Make Model Nominal ID (in) 12,098.5 6,701.265.78 PACKER 5.970 BAKER PREMIER PACKER Baker Premier 3.875 12,160.66,726.965.28 NIPPLE 5.984HES 'XN' NIPPLE (3.813" ID w/3.725" NO GO) HES XN 3.725 12,210.5 6,748.064.86 WLEG 5.312 WIRELINE ENTRY GUIDE 4.000 Other In Hole (Wireline retrievable plugs, valves, pumps, fish, etc.) Top (ftKB) Top (TVD) (ftKB)Top Incl (°)Des Com Make Model SN Run Date ID (in) 2,160.0 2,069.9 33.81 INJ VALVE 4.5" MCX A-1 INJ VALVE SET ON X LOCK (OAL=55") MCXA1 3/14/2023 1.570 Mandrel Inserts : excludes pulled inserts Top (ftKB) Top (TVD) (ftKB) Top Incl (°) St ati on No /S Serv Valve Type Latch Type OD (in) TRO Run (psi)Run Date Com Make Model Port Size (in) 11,925.3 6,631.366.58 1 DMY BK 1 3/9/2023 Camco DCK-2 GLM Perforations & Slots Top (ftKB)Btm (ftKB) Top (TVD) (ftKB) Btm (TVD) (ftKB)Linked Zone Date Shot Dens (shots/ft)Type Com 12,361.0 12,371.0 6,814.0 6,818.6 KUPC, CD3- 302A 4/23/20106.0 IPERF 3-1/8" MILLENIUM GUN w/60 deg phase CD3-302A, 3/15/2023 1:35:09 PM Vertical schematic (actual) INTERMEDIATE; 24.8-12,592.9 Float Shoe (Silver Bullet); 12,590.7-12,592.9 Float Collar (Weatherford); 12,505.9-12,506.8 IPERF; 12,361.0-12,371.0 WLEG; 12,210.5 NIPPLE; 12,160.6 PACKER; 12,098.5 Overshot; 12,066.3 Nipple - Landing; 12,049.5 Mandrel – GAS LIFT; 11,925.3 Annular Fluid - Seawater; 2,092.5-12,072.5; 2/11/2023 INJ VALVE; 2,160.0 Nipple - Landing; 2,160.4 Annular Fluid - Diesel; 24.5- 2,092.5; 2/16/2023 Hanger; 24.8-27.4 WNS INJ KB-Grd (ft) 35.68 RR Date 4/18/2010 Other Elev… Elevation Hi t CD3-302A ... TD Act Btm (ftKB) 12,603.0 Well Attributes Field Name FIORD KUPARUK Wellbore API/UWI 501032052201 Wellbore Status INJ Max Angle & MD Incl (°) 68.48 MD (ftKB) 11,634.23 WELLNAME WELLBORE Annotation Last WO: End Date 2/16/2023 H2S (ppm)DateComment SSSV: WRDP Submit to: OOPERATOR: FIELD / UNIT / PAD: DATE: OPERATOR REP: AOGCC REP: Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD 2100350 Type Inj G Tubing 3850 3850 3860 3860 Type Test P Packer TVD 6701 BBL Pump 1.2 IA 1540 2495 2490 2490 Interval O Test psi 1675 BBL Return 1.0 OA 695 765 765 765 Result P Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result TYPE INJ Codes TYPE TEST Codes INTERVAL Codes Result Codes W = Water P = Pressure Test I = Initial Test P = Pass G = Gas O = Other (describe in Notes) 4 = Four Year Cycle F = Fail S = Slurry V = Required by Variance I = Inconclusive I = Industrial Wastewater O = Other (describe in notes) N = Not Injecting STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION MMec h an ic al Integ rit y Tes t jim.regg@alaska.gov;AOGCC.Inspectors@alaska.gov;phoebe.brooks@alaska.gov chris.wallace@alaska.gov Notes:MITIA post RWO well is current operating under AIO 18E.003 Submitall for AA cancellation to follow passing MITIA and 30 day monitor on gas injection. Notes: CD3-302A Notes: Notes: Notes: ConocoPhillips Alaska Inc, Alpine / CRU / CD3 PAD Guy Cook Van Camp / Weimer 04/05/23 Form 10-426 (Revised 01/2017)MIT CRU CD3-302A and 303 04-05-23.xlsx 7 P.O. BOX 100360 ANCHORAGE, ALASKA 99510-0360 Commissioner Chmielowski, ConocoPhillips Alaska, Inc. submits the attached proposal per AIO 18E, to apply for administrative approval to allow CRU injection well CD5-23 (PTD 217-155) to allow water alternating gas (WAG) injection. The well currently has known tubing by inner annulus communication only while on gas injection. Please contact me at 907-265-6181 if you have any questions. Sincerely, Kate Dodson Well Integrity Specialist ConocoPhillips Alaska, Inc. February 21, 2023 Commissioner Jessie Chmielowski Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, AK 99501 y, By Samantha Carlisle at 1:41 pm, Feb 21, 2023 Kathleen Dodson Digitally signed by Kathleen Dodson Date: 2023.02.21 10:42:20 -09'00' Well Integrity Specialist 1 ConocoPhillips Alaska, Inc. Colville River Unit Well CD5-23 (PTD 217-155) Technical Justification for Administrative Relief Request Purpose ConocoPhillips Alaska, Inc. requests AOGCC approve Administrative Relief request as per Area Injection Order 18E, to allow water alternating gas (WAG) injection for Colville River Unit injection well CD5-23 (PTD 217-155). The well displays tubing by inner annulus (IA) communication only during gas injection. Well History and Status Colville River Unit well CD5-23 (PTD 217-155) was completed in January 2018 as a producer. In January 2019, the well was converted to injection. In February 2022, the well was reported to AOGCC for IA pressurization. Since that report, CPAI has discovered a significant benefit to maintaining gas injection. During AOGCC approved injection monitor period (January 20 –February 20, pressure trends showed TxIA communication exists only when the well is on gas injection service. Diagnostics performed during the monitor period, including passing MITIA and packoff tests, also confirmed the well’s integrity to liquid. ConocoPhillips requests Administrative Approval (AA) to allow the CD5-23 to resume WAG injection. Barrier and Hazard Evaluation Tubing:The 4-1/2”, 12.6 lb, L-80 tubing has integrity to the packer at 8,129’ RKB (7,338’ TVD) based on a passing MITIA to 4,240 psi on 1/23/2023. Production casing:The 7-5/8”, 29.7 lb, L-80 production casing has integrity down to the packer at 8,129’ RKB (7,338’ TVD)based on the previously mentioned passing MITIA to 4,240 psi. This production casing has an internal yield pressure rating of 6,890 psi. Surface casing:The well is completed with 10-3/4”, 45.5 lb, L-80 surface casing. This surface casing has an internal yield pressure rating of 5,210 psi. Primary barrier:The primary barrier to prevent a release from the well and provide zonal isolation is the tubing and packer. Secondary barrier:The production casing is the secondary barrier should the tubing fail. Monitoring:Each well is monitored daily for wellhead pressure changes. Should leaks develop in the tubing or casing it will be noted during the daily monitoring process. Any pressure trends that indicate annular communication require investigation, Commission notification, and corrective action, up to and including a shut-in of the well. T/I/O plots are compiled, reviewed, and submitted to the AOGCC for review monthly. 2/21/2023 Well Integrity Specialist 2 Proposed Operating and Monitoring Plan 1. Well will be used for water alternating gas injection. 2. Perform a passing MITIA every 2-years to maximum anticipated injection pressure. 3. Allow operating IA pressure up to 2,400 psi during gas injection service and 2,000 psi during water injection service. The operating OA pressure is allowed up to 1,000 psi. 4. Pressure transmitters will be maintained on the IA and OA allowing real time monitoring and alarm notifications. 5. Submit monthly reports of daily tubing, IA, and OA pressures, injection volumes and pressure bleeds for all annuli. 6. Shut-in the well if diagnostic testing or injection rates and pressures indicate further problems with appropriate notification to the AOGCC. 7.Maintain the injection line choke and SSV remote shut down capability. During gas injection, the inner annulus protocols will include a drill site operator alarm set at 2,200 psi, and a high alarm set at 2,400 psi that will prompt the control room Board Operator to remotely shut in the choke or SSV. 8.MIT Anniversary date to be set the month of August 2023 to align the 2-year AOGCC witnessed testing with the UIC MIT permanent 4-year scheduled pad testing. 2/21/2023 CD5-23 90-Day Bleed History WELL DATE STR-PRES END-PRES DIF-PRES CASING CD5-23 2022-12-11 934.0 1005 71.0 IA CD5-23 2023-01-23 1400.0 1400 0.0 IA CD5-23 2023-01-25 999.0 394 -605.0 OA CD5-23 2023-01-29 2400.0 1500 -900.0 IA CD5-23 2023-02-04 2401.0 1575 -826.0 IA Last Rev Reason Annotation Wellbore End Date Last Mod By Rev Reason: Set Gauges CD5-23 10/14/2022 oberr Notes: General & Safety Annotation End Date Last Mod By NOTE: CONVERTED f/ PROD TO INJECTOR 1/16/2019 claytg NOTE: RUNNING NECK AND FISHING SWIVELED OFF DV IN STA #2. WOBBLE RING & SPRING RECOVERED. 2/9/2018 claytg Casing Strings Casing Description CONDUCTOR OD (in) 20 ID (in) 19.12 Top (ftKB) 33.3 Set Depth (ft… 115.0 Set Depth … 115.0 Wt/Len (lb/ft) 94.00 Grade H-40 Top Connection Welded Casing Description SURFACE OD (in) 10 3/4 ID (in) 9.95 Top (ftKB) 37.0 Set Depth (ft… 2,219.6 Set Depth … 2,179.0 Wt/Len (lb/ft) 45.50 Grade L-80 Top Connection Hyd 563 Casing Description INTERMEDIATE OD (in) 7 5/8 ID (in) 6.88 Top (ftKB) 34.0 Set Depth (ft… 8,620.8 Set Depth … 7,444.3 Wt/Len (lb/ft) 29.70 Grade L80 Top Connection Hyd563 Tubing Strings: string max indicates LONGEST segment of string Top (ftKB) 31.0 Set Depth … 7,485.1 String Ma… 4 1/2 Tubing Description Tubing – Production Set Depth (ftKB) 8,946.5 Wt (lb/ft) 12.60 Grade L-80 Top Connection H563 ID (in) 3.96 Completion Details: excludes tubing, pup, space out, thread, RKB... Top (ftKB) Top (TVD) (ftKB) Top Incl (°) Item Des OD Nominal (in)Com Make Model Nominal ID (in) 31.0 31.0 0.00 HANGER 11.000 FMC 4-1/2" Tubing Hanger H563 FMC TC-EMS 11"x5" 3.958 2,070.9 2,039.2 20.13 NIPPLE 5.030 NIPPLE,LANDING,4 1/2",X,3.813", HYD563 HES X 3.813 3,583.3 3,453.8 21.12 GAS LIFT 6.473 GLM KBMG,Camco,4 1/2" X 1",H563 SLB Camco KBMG 3.860 5,882.0 5,595.5 21.05 GAS LIFT 6.473 GLM KBMG,Camco,4 1/2" X 1",H563 SLB Camco KBMG 3.860 6,398.3 6,077.2 21.08 GAS LIFT 6.473 GLM KBMG,Camco,4 1/2" X 1",H563 SLB Camco KBMG 3.860 8,129.3 7,337.8 70.77 PACKER 6.620 Baker permanent production packer 4.5" TC-II x 7 5/8" 29# Baker Premier 3.870 8,183.1 7,354.7 72.57 NIPPLE 5.030 NIPPLE,LANDING,4 1/2",X,3.813", HYD563 ***POLISH BORE DAMAGED*** HES X 3.813 8,227.7 7,367.5 74.04 NIPPLE 5.030 NIPPLE,LANDING,4 1/2",3.813" XN, 3.725" No-go HYD563 ***NIPPLED MILLED OUT TO 3.80" PRE-CTD 1/12/20*** HES XN 3.800 8,231.0 7,368.4 74.13 LINER 4.500 CROSSOVER,4 1/2"HYD563 X TXP,BP,24" 3.958 8,232.9 7,368.9 74.18 LINER 4.500 Tubing,4 1/2",12.6#,L80, TXP 3.958 8,941.3 7,484.6 84.20 SHOE 4.500 Orange Peel Shoe (MILLED OUT FROM 1.00" TO 3.70" ON 3/23/2018) 3.700 Other In Hole (Wireline retrievable plugs, valves, pumps, fish, etc.) Top (ftKB) Top (TVD) (ftKB) Top Incl (°) Des Com Make Model SN ID (in) 8,183.1 7,354.7 72.58 GAUGES 3.813" X-lock (no packing) Flow Thru Sub, Shock, Dual Gauges Spartec 80640 / 08093 4 0.000 8,750.0 7,461.3 82.46 4-1/2" BOT Mono-bore XL tray Whipstock 4-1/2" BOT Mono-bore XL tray Whipstock Mandrel Inserts : excludes pulled inserts Top (ftKB) Top (TVD) (ftKB) Top Incl (°) St ati on No /S Serv Valve Type Latch Type OD (in) TRO Run (psi) Run Date Com Make Model Port Size (in) 3,583.3 3,453.8 21.12 1 GAS LIFT DMY BK-5 1 1/13/2019 Schlumb erger Camco BK-5 5,882.0 5,595.5 21.05 2 GAS LIFT DMY BK-5 1 1/21/2018 No Latch Schlumb erger Camco BK-5 6,398.3 6,077.2 21.08 3 GAS LIFT DMY BK-5 1 6/20/2020 Schlumb erger Camco DCK-2 HORIZONTAL, CD5-23, 10/14/2022 7:58:34 PM Vertical schematic (actual) SHOE; 8,941.3 PERF PUP; 8,930.6 4-1/2" BOT Mono-bore XL tray Whipstock ; 8,750.0 OPEN HOLE; 8,621.0-27,430.0 OPEN HOLE; 8,621.0-27,430.0 INTERMEDIATE; 34.0-8,620.8 SHOE; 8,618.7-8,620.8 NIPPLE; 8,227.7 GAUGES; 8,183.1 NIPPLE; 8,183.1 XO THREADS; 8,133.5 PACKER; 8,129.3 XO THREADS; 8,121.5 GAS LIFT; 6,398.3 GAS LIFT; 5,882.0 GAS LIFT; 3,583.3 SURFACE; 37.0-2,219.6 SHOE; 2,216.9-2,219.6 NIPPLE; 2,070.9 CONDUCTOR; 33.3-115.0 HANGER; 37.0-37.2 HANGER; 34.0-34.8 HANGER; 31.0 WNS INJ KB-Grd (ft) 36.55 RR Date 1/24/2018 Other Elev… CD5-23 ... TD Act Btm (ftKB) 27,430.0 Well Attributes Field Name ALPINE Wellbore API/UWI 501032076100 Wellbore Status INJ Max Angle & MD Incl (°) 94.15 MD (ftKB) 19,914.56 WELLNAME WELLBORECD5-23 Annotation LAST WO: End DateH2S (ppm) DateComment SSSV: NIPPLE Submit to: OOPERATOR: FFIELD / UNIT / PAD: DDATE: OOPERATOR REP: AAOGCC REP: Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD 217155 Type Inj G Tubing 1600 1600 1602 1602 Type Test P Packer TVD 7338 BBL Pump 3.8 IA 607 4240 4150 4140 Interval O Test psi 1835 BBL Return 3.8 OA 295 370 370 370 Result P Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result TYPE INJ Codes TYPE TEST Codes INTERVAL Codes Result Codes W = Water P = Pressure Test I = Initial Test P = Pass G = Gas O = Other (describe in Notes) 4 = Four Year Cycle F = Fail S = Slurry V = Required by Variance I = Inconclusive I = Industrial Wastewater O = Other (describe in notes) N = Not Injecting Notes: ConocoPhillips Alaska Inc, Alpine / CRU / CD5 Pad Hills 01/17/23 Notes:Non-witnessed diagnostic MITIA Notes: Notes: Notes: CD5-23 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION MMechani cal Integrity Test jim.regg@alaska.gov;AOGCC.Inspectors@alaska.gov;phoebe.brooks@alaska.gov chris.wallace@alaska.gov Notes: Notes: Notes: Form 10-426 (Revised 01/2017)CD5-23 10-426 17Jan23.xlsx 6 P.O. BOX 100360 ANCHORAGE, ALASKA 99510-0360 Commissioner Chmielowski, ConocoPhillips Alaska, Inc. presents the attached proposal per AIO 18E, Rule 11 to apply for administrative approval to allow CRU injection well CD3-302A (PTD 210-035) to remain in water only injection service. The well currently has known tubing by inner annulus communication only while in gas injection service. Please contact me at 265-6181 if you have any questions. Sincerely, Kate Dodson Senior Well Intervention Engineer ConocoPhillips Alaska, Inc. Office phone: 907-265-6181 Email: kate.dodson@conocophillips.com July 21, 2022 Commissioner Jessie Chmielowski Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, AK 99501 Kathleen Dodson Digitally signed by Kathleen Dodson Date: 2022.07.21 11:29:08 -08'00' P.O. BOX 100360 ANCHORAGE, ALASKA 99510-0360 CPAI Well Integrity 7/20/2022 1 Colville River Unit Well CD3-302A (PTD 210-035) Technical Justification for Administrative Relief Request Purpose ConocoPhillips Alaska, Inc. proposes that the AOGCC approve this administrative relief request as per Area Injection Order 18E, Rule 11 to continue water only injection for CRU injection well CD3-302A (PTD 210-035). The well displays inner annulus pressurization only during gas injection. Well History and Status CRU CD3-302 was first drilled in 2006. In 2007 the well was drilled again as a sidetrack. A second sidetrack was drilled in 2010. CD3-302A was reported to the Commission on March 22, 2022, for a suspect inner annulus pressure increase while on gas injection. In April, DHD performed several diagnostics on the well after a plug was set, including an MIT-T, MIT-IA, and packoff testing. All of these passed. These tests, and the circumstances of the original issue, indicate the well has a gas-only leak. A 30-day monitor period took place from June 20, 2022, through July 20, 2022, during which the well was on water-only injection. No TxIA communication was observed while on water injection. ConocoPhillips requests an administrative approval (AA) which will allow for continued injection of water only. Barrier and Hazard Evaluation With only water injection, this well has all the barriers of a normal injection well Tubing: The 4-1/2”, 12.6 lb/ft, L-80 grade tubing has integrity to the packer at 12,099’ MD (6,701’ TVD), based on a passing MIT-IA in April 2022 and water injection TIO trends. Intermediate casing: The 7”, 26.4 lb/ft, L-80 grade casing has integrity to the packer at 12,099’ MD (6,701’ TVD), based on a passing MIT-IA April 2022 and water injection TIO trends. Surface casing: The 9-5/8”, 40 lb/ft, L-80 grade casing has integrity to the set depth at 2,669’ MD (2,495’ TVD) based on TIO trends. The 9-5/8” casing has an internal yield pressure rating of 5,750 psi. Primary barrier: The primary barrier to prevent a release from the well and provide zonal isolation is the tubing and packer. Secondary barrier: The intermediate casing is the secondary barrier should the tubing fail. CPAI Well Integrity 7/20/2022 2 P.O. BOX 100360 ANCHORAGE, ALASKA 99510-0360 Tertiary barrier:The surface casing will act as a third barrier in the unlikely event that the primary and secondary barriers lose integrity. Monitoring:Each well is monitored daily for wellhead pressure changes. Should leaks develop in the completion, it will be noted during the daily monitoring process. Any pressure trends that indicate annular communication require investigation, Commission notification, and corrective action, up to and including a shut-in of the well. TIO trends are compiled, reviewed, and submitted to the AOGCC for review on a monthly basis. Proposed Operating and Monitoring Plan 1. Well will be used for water only injection (no MI or gas injection allowed). 2. Perform a passing MITIA every 2-years to maximum anticipated injection pressure. 3. Allow operating IA pressure up to 2000 psi, operating OA pressure up to 1000 psi. 4. Pressure transmitters will be maintained on the IA and OA allowing real time monitoring and alarm notifications 5. Submit monthly reports of daily tubing & IA pressures, injection volumes and pressure bleeds for all annuli. 6. Shut-in the well if diagnostic testing or injection rates and pressures indicate further problems with appropriate notification to the AOGCC. 7. Anniversary date for the AOGCC witnessed testing to be set for the month of February 2022 (last AOGCC witnessed test was February 14, 2022) to align with the UIC MIT permanent pad testing schedule. Last Tag Annotation Depth (ftKB)End Date Wellbore Last Mod By Last Tag: SLM 12,449.0 9/23/2011 CD3-302A ninam Last Rev Reason Annotation End Date Wellbore Last Mod By Rev Reason: Pull XXN plug, Set Injection Valve 6/9/2022 CD3-302Aoberr Casing Strings Casing Description CONDUCTOR OD (in) 16 ID (in) 15.25 Top (ftKB) 37.7 Set Depth (ftKB) 114.8 Set Depth (TVD)… 114.7 Wt/Len (lb… 54.50 Grade H-40 Top Connection WELDED Casing Description SURFACE OD (in) 9 5/8 ID (in) 8.83 Top (ftKB) 27.4 Set Depth (ftKB) 2,669.1 Set Depth (TVD)… 2,495.1 Wt/Len (lb… 40.00 Grade L-80 Top Connection BTC Casing Description INTERMEDIATE OD (in) 7 ID (in) 6.28 Top (ftKB) 24.8 Set Depth (ftKB) 12,592.9 Set Depth (TVD)… 6,935.2 Wt/Len (lb… 26.40 Grade L-80 Top Connection BTCM Tubing Strings: string max indicates LONGEST segment of string Tubing Description TUBING String … 4 1/2 ID (in) 3.96 Top (ftKB) 21.7 Set Depth (ft… 12,211.9 Set Depth (TVD… 6,748.6 Wt (lb/ft) 12.60 Grade L-80 Top Connection IBTM Completion Details: excludes tubing, pup, space out, thread, RKB... Top (ftKB) Top (TVD) (ftKB)Top Incl (°)Item Des Nominal ID (in) OD Nominal (in)Make Model 21.7 21.7 0.00 HANGER 3.958 11.000 2,062.1 1,988.1 32.63 NIPPLE 3.813 5.570 CAMCO DB 12,029.7 6,673.2 66.10 GAS LIFT 3.860 5.984 CAMCO KBG-2 12,098.5 6,701.2 65.78 PACKER 3.875 5.970 Baker Premier 12,160.6 6,726.9 65.28 NIPPLE 3.725 5.984 HES XN 12,210.5 6,748.0 64.86 WLEG 4.000 5.312 Other In Hole (Wireline retrievable plugs, valves, pumps, fish, etc.) Top (ftKB) Top (TVD) (ftKB) Top Incl (°)Des Com Run Date ID (in)SN 2,062.1 1,988.1 32.63 VALVE 3.81" Injection Valve on DB Lock Set in DB nipple, Closure test Good 6/9/2022 1.250 HSS-157 Mandrel Inserts : excludes pulled inserts St ati on N o/Top (ftKB) Top (TVD) (ftKB) Top Incl (°)Make Model OD (in)Serv Valve Ty pe Latch Ty pe Port Size (in) TRO Run (psi)Run Date Com 1 12,029.7 6,673.2 66.10 1 GAS LIFT DMY INT 0.000 0.06/7/2022 Fruit. Ext. Pkg. Perforations & Slots Top (ftKB)Btm (ftKB) Top (TVD) (ftKB) Btm (TVD) (ftKB)Linked Zone Date Shot Dens (shots/ft )Type Com 12,361.0 12,371.0 6,814.0 6,818.6 KUPC, CD3- 302A 4/23/20106.0 IPERF 3-1/8" MILLENIUM GUN w/60 deg phase Notes: General & Safety End Date Annotation 4/5/2022 NOTE: Welded 9"x0.500" Conductor extension 4/19/2010 NOTE: View Schematic w/ Alaska Schematic9.0 4/18/2010 NOTE: Well SIDETRACKED, OLD PROD CSG CUT @ 2673' CD3-302A, 6/9/2022 5:13:01 PM Vertical schematic (actual) INTERMEDIATE; 24.8-12,592.9 Float Shoe (Silver Bullet); 12,590.7-12,592.9 Float Collar (Weatherford); 12,505.9-12,506.8 IPERF; 12,361.0-12,371.0 WLEG; 12,210.5 NIPPLE; 12,160.6 PACKER; 12,098.5 GAS LIFT; 12,029.7 SURFACE; 27.4-2,669.1 SHOE; 2,667.7-2,669.1 FLOAT COLLAR; 2,588.9- 2,590.3 VALVE; 2,062.1 NIPPLE; 2,062.1 CONDUCTOR; 37.7-114.7 HANGER; 27.4-29.6 Hanger; 24.8-27.4 HANGER; 21.7 WNS INJ KB-Grd (ft) 43.18 RR Date 4/18/2010 Other Elev… CD3-302A ... TD Act Btm (ftKB) 12,603.0 Well Attributes Field Name FIORD KUPARUK Wellbore API/UWI 501032052201 Wellbore Status INJ Max Angle & MD Incl (°) 68.48 MD (ftKB) 11,634.23 WELLNAME WELLBORE Annotation Last WO: End Date 4/16/2010 H2S (ppm)DateComment SSSV: WRDP Submit to: OOPERATOR: FIEL D / UNIT / PAD: DATE: OPERATOR REP: AOGCC REP: Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD 2100350 Type Inj G Tubing 3845 3845 3845 3845 Type Test P Packer TVD 6701 BBL Pump 0.9 IA 1940 2710 2700 2700 Interval 4 Test psi 1675 BBL Return 0.9 OA 728 772 751 746 Result P Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test P Packer TVD BBL Pump IA Interval 4 Test psi BBL Return OA Result P Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test P Packer TVD BBL Pump IA Interval 4 Test psi BBL Return OA Result P Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result TYPE INJ Codes TYPE TEST Codes INTERVAL Codes Result Codes W = Water P = Pressure Test I = Initial Test P = Pass G = Gas O = Other (describe in Notes) 4 = Four Year Cycle F = Fail S = Slurry V = Required by Variance I = Inconclusive I = Industrial Wastewater O = Other (describe in notes) N = Not Injecting ConocoPhillips Alaska Inc, Alpine / CRU / CD3 Pad Adam Earl Caudle / Miller 02/14/22 Notes: Notes: CD3-302A Notes:MITIA to maximum anticipated injection pressure per AIO 18C.009 Notes: Notes: STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION MM ec h an i c al In teg r i t y Tes t jim.regg@alaska.gov;AOGCC.Inspectors@alaska.gov;phoebe.brooks@alaska.gov chris.wallace@alaska.gov Form 10-426 (Revised 01/2017)MIT CRU CD3-302A 2 2-14-22.xlsx From:Wallace, Chris D (OGC) To:dusty.freeborn@conocophillips.com Cc:Well Integrity Specialist CPF2 Subject:FW: CPAI application CD3-302A AA received072122.pdf Date:Friday, August 5, 2022 11:56:00 AM Attachments:CPAI application CD3-302A AA received072122.pdf Dusty – Kate says you are in charge while she is out of the office… Thanks Chris From: Wallace, Chris D (OGC) Sent: Friday, August 5, 2022 11:53 AM To: kate.dodson@conocophillips.com Subject: FW: CPAI application CD3-302A AA received072122.pdf Kate, I am processing this CD3-302A AA request and I do not have a record of the mentioned MIT-IA and MIT-T of April 2022. Please provide so we may continue our review. I have an email from Travis dated 2/16/2022 for the first notification of potential TxIA, and I have the record of the passing witnessed MITIA of 2/14/2022. So I would need a valid MITIA after the communication was discovered to proceed with this application. Thanks and Regards, Chris Wallace, Sr. Petroleum Engineer, Alaska Oil and Gas Conservation Commission, 333 West 7th Avenue, Anchorage, AK 99501, (907) 793-1250 (phone), (907) 276-7542 (fax), chris.wallace@alaska.gov CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Chris Wallace at 907-793-1250 or chris.wallace@alaska.gov. From: Carlisle, Samantha J (OGC) <samantha.carlisle@alaska.gov> Sent: Thursday, July 21, 2022 12:32 PM To: Wallace, Chris D (OGC) <chris.wallace@alaska.gov> Subject: CPAI application CD3-302A AA received072122.pdf Docket number AIO-22-021 CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. From:Well Integrity Specialist CPF2 To:Wallace, Chris D (OGC) Subject:RE: [EXTERNAL]FW: CPAI application CD3-302A AA received072122.pdf Date:Wednesday, August 24, 2022 10:37:28 AM Attachments:image001.png CD3-302A Diagnostic MIT-IA 1 April 22.xlsx CD3-302A Diagnostic MIT-T 31 March 22.xlsx Chris- Attached are the 10-426 forms for the diagnostic MIT-T and MIT-IA Kate referenced in her AA request. Please let me know if you have any questions or concerns. Dusty Freeborn Well Integrity Specialist ConocoPhillips Alaska, Inc. Office phone: (907) 659-7224 Cell phone: (907) 830-9777 From: Wallace, Chris D (OGC) <chris.wallace@alaska.gov> Sent: Friday, August 5, 2022 11:57 AM To: Freeborn, Dusty <Dusty.Freeborn@conocophillips.com> Cc: Well Integrity Specialist CPF2 <n2549@conocophillips.com> Subject: [EXTERNAL]FW: CPAI application CD3-302A AA received072122.pdf CAUTION:This email originated from outside of the organization. Do not click links or open attachments unless you recognize the sender and know the content is safe. Dusty – Kate says you are in charge while she is out of the office… Thanks Chris From: Wallace, Chris D (OGC) Sent: Friday, August 5, 2022 11:53 AM To: kate.dodson@conocophillips.com Subject: FW: CPAI application CD3-302A AA received072122.pdf Kate, I am processing this CD3-302A AA request and I do not have a record of the mentioned MIT-IA and MIT-T of April 2022. Please provide so we may continue our review. I have an email from Travis dated 2/16/2022 for the first notification of potential TxIA, and I have the record of the passing witnessed MITIA of 2/14/2022. So I would need a valid MITIA after the communication was discovered to proceed with this application. Thanks and Regards, Chris Wallace, Sr. Petroleum Engineer, Alaska Oil and Gas Conservation Commission, 333 West 7th Avenue, Anchorage, AK 99501, (907) 793-1250 (phone), (907) 276-7542 (fax), chris.wallace@alaska.gov CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Chris Wallace at 907-793-1250 or chris.wallace@alaska.gov. From: Carlisle, Samantha J (OGC) <samantha.carlisle@alaska.gov> Sent: Thursday, July 21, 2022 12:32 PM To: Wallace, Chris D (OGC) <chris.wallace@alaska.gov> Subject: CPAI application CD3-302A AA received072122.pdf Docket number AIO-22-021 5 P.O. BOX 100360 ANCHORAGE, ALASKA 99510-0360 March 24, 2022 Commissioner Jessie Chmielowski Alaska Oil & Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, AK 99501 Commissioner Chmielowski: ConocoPhillips Alaska, Inc. presents the attached proposal per AIO 18E, Rule 11, to apply for Administrative Approval to allow CRU injection well CD3-118 (PTD 208-025) to continue WAG injection service with known TxIA communication while on gas injection. If you need additional information, please contact us at your convenience. Sincerely, Dusty Freeborn Well Integrity Specialist ConocoPhillips Alaska, Inc. Office phone: (907) 659-7224 Cell phone: (907) 830-9777 Digitally signed by Dusty Freeborn DN: OU=AK WELLS, O=ConocoPhillips, CN=Dusty Freeborn, E=dusty.freeborn@conocophillips.com Reason: I am the author of this document Location: Anchorage, Alaska Date: 2022.03.24 09:57:25-08'00' Foxit PDF Editor Version: 11.0.0 Dusty Freeborn P.O. BOX 100360 ANCHORAGE, ALASKA 99510-0360 1 Colville River Unit Well CD3-118 (PTD# 208-025) Technical Justification for Administrative Relief Request Purpose ConocoPhillips Alaska, Inc. (CPAI) requests that the AOGCC approve this Administrative Approval request as per AIO 18E, Rule 11, to allow water alternating gas (WAG) injection for Colville River Unit WAG injector CD3-118 (PTD# 208-025). The well displays tubing by inner annulus communication only during gas injection. Well History and Status Colville River Unit well CD3-118 was completed in March of 2008. CD3-118 was initially reported to the Commission on the 15th of February 2022 for a suspect inner annulus pressure increase while on MI injection. The report was the day after the injector passed an AOGCC witnessed MIT-IA performed on 14th of February 2022. CPAI communicated a plan to the AOGCC that included intent to observe the well on MI injection. The MI monitor period was completed, and the diagnostics yielded a passing MIT-IA, a passing one-hour IA draw down test and passing surface casing leak detect. The IA showed long term pressure increase but was capable of stabilization below the DNE of 2400 psi while injection rates and temperature were also stable. CPAI has developed criteria under which it believes a gas injection well may operate safely with TxIA communication. That criterion includes the well having casing rated high enough to support MAIP of gas injection should a barrier fail, passing a MITIA to MAIP of gas injection, passing a MITOA or SCLD, and passing an IA DDT on water or gas injection. During gas injection service the IA pressure must maintain below the MAOP of 2400 psi. In addition, pressure transmitters will be maintained on the IA and OA allowing real time monitoring and alarm notifications. CPAI believes that CD3-118’s current condition along with the well testing and operating criteria above will allow the well to be operated safely without threatening human safety or the environment. Therefore, CPAI request Administrative Approval that will allow CD3-118 to continue WAG injection with known TxIA communication. Barrier and Hazard Evaluation Barriers in place are sufficient to allow safe operation with water alternating gas injection service. Tubing: The 3-1/2”, 9.3 lb/ft, L-80 tubing has integrity to the Baker Premier production packer at 12,236’ MD (6,593’ TVD) based on the passing MITIA to 4,200 psi on 24th February 2022 (MIT-IA results are attached) and TIO trends. There is known TxIA communication while on gas injection based on TIO trend data. P.O. BOX 100360 ANCHORAGE, ALASKA 99510-0360 2 Production casing: The 7”, 26 lb/ft, L-80 intermediate casing have integrity to the Baker Premier production packer at 12,236’ MD (6,593’ TVD) based on the aforementioned passing MITIA and TIO trends. Surface casing: The 9-5/8”, 40 lb/ft, L-80 surface casing has an internal yield pressure rating of 5,750 psi. The surface casing has integrity based on a passing SCLD/gas MITOA to 1,200 psi on 23 March 2022 and TIO trends. Primary barrier: The primary barrier during water injection to prevent a release from the well and provide zonal isolation is the tubing and packer. The primary barrier during gas injection to prevent a release from the well and provide zonal isolation is the production casing. The tubing and packer also act as a limited barrier, so that the pressure build-up is manageable below 2,400 psi. Secondary barrier: The production casing is the secondary barrier during water injection, should the tubing fail. The surface casing is the secondary barrier during gas injection, should the production casing fail. Tertiary barrier: The surface casing will act as a tertiary barrier during water injection, in the unlikely case that the first two normal barriers have failures. Monitoring: This well will be monitored real time for wellhead pressure changes. Any pressure trends that indicate further annular communication require investigation, Commission notification, and corrective action, up to and including a shut-in of the well. TIO trends are compiled, reviewed, and submitted to the AOGCC for review monthly. Proposed Operating and Monitoring Plan 1. Well will be used for water alternating gas injection. 2. Perform a passing MITIA every 2-years to maximum anticipated injection pressure. 3. Allow operating IA pressure up to 2,400 psi during gas injection service and 2,000 psi during water injection service. The operating OA pressure is allowed up to 1,000 psi. 4. Pressure transmitters will be maintained on the IA and OA allowing real time monitoring and alarm notifications. 5. Submit monthly reports of daily tubing, IA, and OA pressures, injection volumes and pressure bleeds for all annuli. 6. Shut-in the well should diagnostic testing or injection rates and pressures indicate further problems with appropriate notification to the AOGCC. 7. Maintain the injection line choke and SSV remote shut down capability. During gas injection, the inner annulus protocols will include a drill site operator alarm set at 2,200 psi, and a high alarm set at 2,400 psi that will prompt the control room Board Operator to remotely shut in the choke or SSV. 8. MIT Anniversary date to be set the month of February 2022 to align the 2-year AOGCC witnessed testing with the UIC MIT permanent 4-year scheduled pad testing. Last Tag Annotation Depth (ftKB)End Date Wellbore Last Mod By Last Tag: SLM 12,449.0 9/23/2011 CD3-302A ninam Last Rev Reason Annotation End Date Wellbore Last Mod By Rev Reason: PULL INJ VALVE, GLV C/O, SET A1-INJ VLV 8/30/2016 CD3-302A pproven Casing Strings Casing Description CONDUCTOR OD (in) 16 ID (in) 15.25 Top (ftKB) 37.0 Set Depth (ftKB) 114.0 Set Depth (TVD)… 114.0 Wt/Len (l… 54.50 Grade H-40 Top Thread WELDED Casing Description SURFACE OD (in) 9 5/8 ID (in) 8.83 Top (ftKB) 27.4 Set Depth (ftKB) 2,669.1 Set Depth (TVD)… 2,495.1 Wt/Len (l… 40.00 Grade L-80 Top Thread BTC Casing Description INTERMEDIATE OD (in) 7 ID (in) 6.28 Top (ftKB) 24.8 Set Depth (ftKB) 12,592.9 Set Depth (TVD)… 6,935.2 Wt/Len (l… 26.40 Grade L-80 Top Thread BTCM Tubing Strings Tubing Description TUBING String Ma… 4 1/2 ID (in) 3.96 Top (ftKB) 21.7 Set Depth (ft… 12,211.9 Set Depth (TVD) (… 6,748.5 Wt (lb/ft) 12.60 Grade L-80 Top Connection IBTM Completion Details Top (ftKB) Top (TVD) (ftKB) Top Incl (°)Item Des Com Nominal ID (in) 21.7 21.7 0.00 HANGER FMC TUBING HANGER 3.958 2,062.1 1,988.1 32.63 NIPPLE CAMCO 'DB' LANDING NIPPLE 3.813 12,098.5 6,701.265.78 PACKER BAKER PREMIER PACKER 3.875 12,160.6 6,726.9 65.28 NIPPLE HES 'XN' NIPPLE (3.813" ID w/3.725" NO GO) 3.725 12,210.5 6,748.064.86 WLEG WIRELINE ENTRY GUIDE 4.000 Other In Hole (Wireline retrievable plugs, valves, pumps, fish, etc.) Top (ftKB) Top (TVD) (ftKB) Top Incl (°)Des Com Run Date ID (in)SN 2,062.0 1,988.0 32.62 VALVE 3.81" INJ VLV ON DB LOCK IN SSSV 8/27/2016 1.250 Perforations & Slots Top (ftKB)Btm (ftKB) Top (TVD) (ftKB) Btm (TVD) (ftKB)Linked Zone Date Shot Dens (shots/ft )Type Com 12,361.0 12,371.0 6,814.0 6,818.6 KUPC, CD3- 302A 4/23/20106.0 IPERF 3-1/8" MILLENIUM GUN w/60 deg phase Mandrel Inserts St ati on N o/Top (ftKB) Top (TVD) (ftKB)Make Model OD (in)Serv Valve Ty pe Latch Ty pe Port Size (in) TRO Run (psi)Run Date Com 1 12,029.7 6,673.2 CAMCO KBG-2 1 GAS LIFT DMY BK 0.000 0.08/26/2016 Notes: General & Safety End Date Annotation 4/19/2010 NOTE: View Schematic w/ Alaska Schematic9.0 4/18/2010 NOTE: Well SIDETRACKED, OLD PROD CSG CUT @ 2673' CD3-302A, 5/28/2020 4:22:19 PM Vertical schematic (actual) INTERMEDIATE; 24.8-12,592.9 IPERF; 12,361.0-12,371.0 WLEG; 12,210.5 NIPPLE; 12,160.6 PACKER; 12,098.5 GAS LIFT; 12,029.7 SURFACE; 27.4-2,669.1 NIPPLE; 2,062.1 VALVE; 2,062.0 CONDUCTOR; 37.0-114.0 HANGER; 21.7 WNS INJ KB-Grd (ft) 43.18 Rig Release Date 4/18/2010 CD3-302A ... TD Act Btm (ftKB) 12,603.0 Well Attributes Field Name FIORD KUPARUK Wellbore API/UWI 501032052201 Wellbore Status INJ Max Angle & MD Incl (°) 68.48 MD (ftKB) 11,634.23 WELLNAME WELLBORE Annotation Last WO: End Date 4/16/2010 H2S (ppm)DateComment SSSV: WRDP Submit to: OOPERATOR: FIELD / UNIT / PA D: DATE: OPERATOR REP: AOGCC REP: Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD 208-025 Type Inj G Tubing 3818 3818 3822 3816 Type Test O Packer TVD 6593 BBL Pump 6.6 IA 125 4200 4135 4120 Interval O Test psi 1648 BBL Return 5.5 OA 204 347 346 344 Result P Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result TYPE INJ Codes TYPE TEST Codes INTERVAL Codes Result Codes W = Water P = Pressure Test I = Initial Test P = Pass G = Gas O = Other (describe in Notes) 4 = Four Year Cycle F = Fail S = Slurry V = Required by Variance I = Inconclusive I = Industrial Wastewater O = Other (describe in notes) N = Not Injecting ConocoPhillips Alaska Inc, Alpine / CRU / CD3 Pad Van Camp 02/24/22 Notes:Diagnostic testing for AA prep Notes: CD3-118 Notes: Notes: Notes: STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION MMec h an i c al Int egr i t y Tes t jim.regg@alaska.gov;AOGCC.Inspectors@alaska.gov;phoebe.brooks@alaska.gov chris.wallace@alaska.gov Form 10-426 (Revised 01/2017)CD3-118 Diagnostic MIT-IA 24 Feb 2022.xlsx By Grace Salazar at 1:21 pm, May 26, 2021 RECEIVED By Jody Colombie at 2:33 pm, Feb 22, 2021 ConocoPhillips February 22, 2021 Alaska Oil and Gas Conservation Commission 333 W 7th Ave #100 Anchorage, Alaska, 99501-3539 RE Request for Reconsideration Area Injection Order No. 18E, Alpine Oil Pool, North Slope, AK Dear Commissioners. Stephen Thatcher Manager WNS Development North Slope Development ConocoPhillips Alaska. Inc P O Box 100360 Anchorage, AK 99510-0360 phone 907 263 4464 ConocoPhillips Alaska, Inc. (CPAI) appreciates the Commission's timely Issuance of the area Injection order referenced above Pursuant to AS 31.05.080(a), CPAI respectfully requests reconsideration of the decision on Rules 1 and 7 for the following reasons: • Area Injection Order Rule 1. CPAI requests that the fluids authorized for injection in the FOR interval include the following: small amounts of Class II fluids, which will be mixed with the source or produced water including. sump fluid, hydra -test fluid, rinsate from washing mud hauling trucks, excess well- work fluids, melt water collected from well cellars. These fluids were authorized in the Fiord Oil Pool rules (AID 30) to provide operational flexibility at the remote roadless CD3 drillsite where there is limited disposal capabilities and limited storage capacity. CPAI continues to need these Fluids authorized for injection now that the Fiord Oil Pool has been combined into the Alpine Oil Pool (AOP) Additionally, these fluids were previously authorized for injection in the AOP in AIO 18B.002 but were not captured in AIO 18D. The proposed language limits injection to small quantities that must be mixed with source or produced water. Additionally, these fluids are expected to be fully compatible with the AOP reservoirs and the fluids are not expected to negatively impact hydrocarbon recovery. Proposed Revision to AIO Rule 1: Based on the foregoing explanation, CPAI requests that Rule 1 be revised to provide as follows (revised language shown in red) a. Source water from the Kuparuk seawater treatment plant, b. Produced water from the Alpine Central Facility, c. Enriched hydrocarbon gas (MI) from Alpine Central Facility, d. Lean gas, e. Tracer survey fluids to monitor reservoir performance (chemical, radioactive, etc ), f. Fluids used to improve near wellbore injectivity (via use of acid or similar treatment), g. Fluids used to seal wellbore intervals which negatively impact recovery efficiency (cement, Request for Reconsideration of Conservation Order No. 443D and Area Injection Order No.18E Page 2 of 2 resin, etc.), h Fluids associated with freeze protection (diesel, dead crude, glycol methanol, etc ), and i. Standard oilfield chemicals (corrosion inhibitor, scale inhibitor, etc.) j. small amounts of Class II fluids, which will be mixed with the source or produced water including: sump fluid, hydra -test fluid, rinsate from washing mud hauling trucks, excess well -work fluids, melt water collected from well cellars. • Area Injection Order Rule 7. In its AIO application CPAI erroneously included the word 'immediately` in the rule rather than "by the next business day " CPAI requests this rule be revised as set forth below to align with similar area injection order rules (see, for example A10 28 and AIO 35) (revised language shown in red). Whenever any pressure communication, leakage or lack of injection zone isolation is indicated by injection rate, operating pressure observation, test, survey, log, or other evidence. the operator shall :�;4ned tely by the next business day notify the Commission and submit a plan of corrective action on a Form 10403 for Commission approval. The operator shall immediately shut in the well if continued operation would be unsafe or would threaten contamination of freshwater, or if so directed by the Commission. A monthly report of daily tubing and casing annuli pressures and injection rates must be provided to the Commission for all injection wells indicating well integrity failure or lack of injection zone isolation. Please contact Dana Glessner (265-6478, glessd@conocophillips.com) if you have questions or would like to discuss this request for reconsideration. Regards, Stephen Thatcher Manager, WNS Development North Slope Development Notice of Public Hearing STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION Re: Docket Number: CO-20-024 And AIO-20-021 Colville River Unit, Alpine and Fiord Oil Pools The application of ConocoPhillips Alaska, Inc. (CPAI) for amendments to Conservation Order (CO) No. 433C and Area Injection Order (AIO) No. 18D to expand the areal and vertical limits of the Colville River Unit (KRU), Alpine Oil Pool (AOP) and to incorporate the existing Fiord Oil Pool (FOP) into the AOP. CPAI, by letter dated November 5, 2020, requests the Alaska Oil and Gas Conservation Commission (AOGCC) amend CO No. 433C and AIO No. 18D to expand the affected area of the AOP to include acreage that is currently within the CRU but outside of the areal extent of the AOP and expand the vertical limits of the AOP, which would have the effect of incorporating the FOP (governed by CO No. 569 and AIO No. 30) into the AOP. The AOGCC has tentatively scheduled a public hearing on this application for December 15, 2020, at 10:00 a.m. at 333 West 71h Avenue, Anchorage, Alaska 99501. 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 November 25, 2020. If a request for a hearing is not timely filed, the AOGCC may consider the issuance of an order without a hearing. To learn if the AOGCC will hold the hearing, call (907) 279-1433 after November 30, 2020. If a hearing is requested, the COVID-19 virus may necessitate that the hearing be held telephonically. Those desiring to participate or be present at the hearing should check with AOGCC the day before the hearing to ascertain if the hearing will be telephonic. If the hearing is telephonic, on the day of the hearing, those desiring to be present or participate should call 1-800- 315-6338 and, when instructed to do so, enter the code 14331 followed by the # sign. Because the hearing will start at 10:00 a.m., the phone lines will be available starting at 9:45 a.m. Depending on call volume, those calling in may need to make repeated attempts before getting through. In addition, written comments regarding this application may be submitted to the AOGCC, at 333 West 7th Avenue, Anchorage, Alaska 99501. Comments must be received no later than 4:30 p.m. on December 14, 2020, except that, if a hearing is held, comments must be received no later than the conclusion of the December 15, 2020 hearing. If, because of a disability, special accommodations may be needed to comment or attend the hearing, contact the AOGCC at (907) 279-1433, no later than December 4, 2020. C� Jeremy M. Price Chair, Commissioner ANcHORAGE DAiLy NEws AFFIDAVIT OF PUBLICATION Account #: 270227 ST OF AK/AK OIL AND GAS CONSERVATION COMMISSION 333 W. 7TH AVE STE 100, ANCHORAGE, AK 99501 Order #: W0018919 STATE OF ALASKA THIRD JUDICIAL DISTRICT 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 11 / 10/2020 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 ind;viduals. Signed V `,- y v I Subscribed and sworn to before me this 13th day of November 2020. Notary Publicin and for TVState of Alaska. '' Third Division Anchorage, Alaska MY COMMIS ONN XPIRESco J Z) w <ff w J O z <Q W� ®Q Q 0 U Cost: $303.82 Notice of Public Hearing STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION Re: Docket Number: CO-20-024 And AIO-20-021 Colville River Unit, Alpine and Fiord Oil Pools The application of ConocoPhillipsAlaska, Inc. (CPAI) for amendments to Conservation Order (CO) No. 433C and Area Injection Order (AIO) No. 18D to expand the areal and vertical limits of the Colville River Unit (KRU), Alpine Oil Pool (AOP) and to incorporate the existing Fiord Oil Pool (FOP) into the AOP CPAI, by letter dated November 5, 2020, requests the Alaska Oil and Gas Conservation Commission (AOGCC) amend CO No. 433C and AIO No. 18D to expand the affected area of the AOP to include acreage that is currently within the CRU but outside of the areal extent of the AOP and expand the vertical limits of the AOP, which would have the effect of incorporating the FOP (governed by CO No. 569 and AIO No. 30) into the AOP. The AOGCC has tentatively scheduled a public hearing on this application for December 15, 2020, at 10:00 a.m. at 333 West 7th Avenue, Anchorage, Alaska 99501. 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 November 25, 2020. If a request for a hearing is not timely filed, the AOGCC may consider the issuance of an order without a hearing. To learn if the AOGCC will hold the hearing, call (907) 279-1433 after November 30, 2020. If a hearing is requested, the COVID-19 virus may necessitate that the hearing be held telephonically. Those desiring to participate or be present at the hearing should check with AOGCC the day before the hearing to ascertain if the hearing will be telephonic. If the hearing is telephonic, on the day of the hearing, those desiring to be present or participate should call 1-800-315-6338 and, when instructed to do so, enter the code 14331 followed by the # sign. Because the hearing will start at 10:00 a.m., the phone lines will be available starting at 9:45 a.m. Depending on call volume, those calling in may need to make repeated attempts before getting through. In addition, written comments regarding this application may be submitted to the AOGCC, at 333 West 7th Avenue, Anchorage, Alaska 99501. Comments must be received no later than 4:30 p.m. on December 14, 2020, except that, if a hearing is held, comments must be received no later than the conclusion of the December 15, 2020 hearing. If, because of a disability, special accommodations may be needed to comment or attend the hearing, contact the AOGCC at (907) 279-1433, no later than December 4, 2020. Jeremy M. Price Chair, Commissioner Published: November 10, 2020 Carlisle, Samantha J (CED) From: Carlisle, Samantha J (CED) Sent: Monday, November 9, 2020 3:12 PM To: AOGCC Public Notices Subject: CO-20-021 and AIO-20-024 public hearing notice.pdf Attachments: CO-20-021 and AIO-20-024 public hearing notice.pdf Docket Number: CO-20-024 And AIO-20-021 Colville River Unit, Alpine and Fiord Oil Pools The application of ConocoPhillips Alaska, Inc. (CPAI) for amendments to Conservation Order (CO) No. 433C and Area Injection Order (AIO) No.18D to expand the areal and vertical limits of the Colville River Unit (KRU), Alpine Oil Pool (AOP) and to incorporate the existing Fiord Oil Pool (FOP) into the AOP. Samantha Carlisle Executive Secretary III Alaska Oil and Gas Conservation Commission 333 West 71h Avenue Anchorage, AK 99501 (907)793-1223 ALASKANS STAND TOGETHER 6 FT APART CONFIDENTIALITY NOTICE. Thus 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 untended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Samantha Carlisle at (907) 793-1223 or Samantha.Carlisle@alaska.gov. Bernie Karl K&K Recycling Inc. P.O. Box 58055 Fairbanks, AK 99711 George Vaught, Jr. P.O. Box 13557 Denver, CO 80201-3557 Gordon Severson 3201 Westmar Cir. Anchorage, AK 99508-4336 Darwin Waldsmith P.O. Box 39309 Ninilchik, AK 99639 Richard Wagner P.O. Box 60868 Fairbanks, AK 99706 STATE OF ALASKA ADVERTISING ORDER NOTICE TO PUBLISHER SUBMIT INVOICE SHOWING ADVERTISING ORDER NO., CERTIFIED AFFIDA VIT OF PUBLICATION WITH ATTACHED COPY OF ADVERTI AD VERTIS ING ORDER NUMBER A O-O8-� t -O ASMENT. FROM: Alaska Oil and Gas Conservation Commission AGENCY CONTACT: Jody Colombie/Samantha Carlisle DATE OF A.O. 11/9/20201(907)279-1433 AGENCY PHONE: 333 West 7th Avenue Anchorage, Alaska 99501 DATES ADVERTISEMENT REQUIRED: COMPANY CONTACT NAME: PHONE NUMBER: ASAP FAX NUMBER: (907) 276-7542 TO PUBLISHER: Anchorage Daily News, LLC SPECIAL INSTRUCTIONS: PO Box 140147 Anchorage, Alaska 99514-0174 TYPE OF ADVERTISEMENT: v LEGAL DISPLAY CLASSIFIED 1 OTHER (Specify below) DESCRIPTION PRICE CO-20-021 and AIO-20-024 Initials of who prepared AO: Alaska Non -Taxable 92-600185 SUBMIT INVOICE SHOWING ADVERTISING ORDER NO.,.CERTIFIED .AFFIDAVIT OF PUBLICATION WITH ATTACHED COPY OF: ADVEPTISMENTTO. AOGCC 333 West 7th Avenue Anchorage, Alaska 99501 Page 1 of 1 Total of All Pa es $ REF Type Number Amount Date Comments I PVN VCO21795 2 Ao AO-08-21-012 3 4 FIN AMOUNT SY Act. Template PGM LGR Object FY DIST LIQ 1 21 AOGCC 3046 21 2 3 4 5 Purchasing Authority Name: Title: Tracie L. Paladijczuk, Admin Officer II urchasin 'ty's Signature 4 Telephone Number 907-793-1239 1. A.O. # and receiving agency name must appear on all invoices and documents relating to this purchase. 2. The state is registered for tax free transactions under Chapter 32, IRS code. Registration number 92-73-0006 K. Items are for the exclusive use of the state and not for resale. DISTRIBUTION: Division Fiscal/Original AO Copies- Publisher (faxed), Division Fiscal; Receiving Form:02-901 Revised: 11 /9/2020 from: ANC Legal Ads To: _Cadisle, Samantha h ( D) Subject: Re: Please publish AO-08-21-012 Date: Monday, November 9, 2020 12:50:27 PM Attachments: image ono Please see below for the ad confirmation and let me know before 4pm if this is approved to run. Thank you, ADDITIONAL OPTIONS SCHEDULE FOR AD NUMBER WO0189190 .: ' C. 2020 Aru nonage Daily News l.rgals STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION Re I)Xket Nu rnt),?r CO-?04Yl4 And AK170-f1:'1 CONtite River Unit, Alpahe and Fcrd Oil Pools n1Pag)pfica"lofCOnOCOPtIRIipSA4151W,UX.(CPAi)1U( arr*ndrrertts to re,,s ivahOh Ordler (CO) No. 433C and Area "K ti)n Urdu ;AID! No lan fo expand the ef8al and verdcai RmitS 01 me COvIllP Rtdel Unit (KRLI), Alpine Olt Pool 1AOPI and to InCOrpOralP the 01"TK' Fiord OfPA01(FOR Into the AOP. CPAs, by letter (latetl Novorlhbef 5, 2020, regkP%u. the Alaska ()it and Gas Conservation COmmiSSOn (AOGGC) amend CO No 4"a3C and 410 NO. 18D to expand the affected area Of the AOP to Indilde acreage that is ao(ently Within the CAU bin Outst(la Of the cereal 4Mem of The AOP alid expand the Wmica) InutS Of ille AGF, Which Would have the effect of I Corporatang the FDP 10MMOd 0/ CO No. S69 and NO No. 30) into the AOP rytP AOGCC bas t9m8tNP•ly Srliwfuleil a VLOIL hoiring 0h This application for December 15, 20:0, h, 10.00 am. M 333 West 7th Avenue, Arldlo We, ALISkd 99501, N retale5t that the teritatjvely scl"Juled Iheah%t�Uk held, a whltten rt-q est must be tiled with due ADGCC no later If1an 4 30 IT m. On N(IW rit2P.r 25, 2020 if a retptest for a fleshing is not oneely filed, the AOCAC may PrN wiu llol the (x? ling. Of all CAI Without0yh0e 3klanY NNOV al ber If a hearing IS re(AW$t d, The COVID-19 Virus may A&Ce5Sltate that The hearing I*twki lelepll(Aucatly These desh"Ing to pt IClDat_ Or be pre5ant at the hearing shlo(dd chfick With AOGCC the daV before the hearing to ascertain t the treating wig be tel"ITT"Mc. IP Uhe 11,anI1B is telaph0nic, on the clay Of dig hearing, dwsa rteSldr>B In be pteswN Or parocipaitiisrroulo Call 1.800-315-6338 and. W!wn instructed t0 do W. entail' the Code 14331 followed by the it SIM Because the hearing will Stan at 10 00 a m , the phone lines .11 be avallttile Starting at 9 45 a m DOD611dignt$q 011 call VOIIit11a. Uxise calling 8h Tray need t0 make rep9atPo attwnpt5 t OIV gentry tra'otr6h. in alldNWn, Written catnag nts regarding this a1lpticatWih maybe sutxnthed to the AOGCC,. at 3333 west 7th Avenue, AJrJWaee, Alaska 9950h. torrunam nxistbe received no iator fhan 4'30pm on December 1•1, 2020, except that, t a hearing Is held, com hens must be received no later Ltk3n the conclusion Of die Decerybef 15, 2020 hearing t, because of a disability special accortxnodations may be c4011ed t0 commern or attend The boarkg contact file AOGCC at (907i 279-1433, no later tt In Decenl[W 4, 2020 teferhy M Price Chair, COMISSIOner Published Nwambel 10. 2020 Lisi Misa Legal Advertising IeOalads(aadn com ' 907-257-4286 cal. Anchorage Daily News l adn.com 300 W. 31st Ave. Anchorage, AK 99503 Ile Ila, "As at July 8th, we will be charging for affidavits. The standard affidavit charge is $5, This charge will autwercalN be included in all costlquotes unless requested otherwise. Please keep all correspondence for legal advertising addressed tg10,Ta61d dn.com. to assure best service and hacking ATTENTION AFFIDAVITS ARE IL AILED OUT ON TUESDAYS/t=RIDAYS - On Mon, Nov 9, 2020 at 11:39 AM Carlisle, Samantha J (CED) <eemaniha c Aisle alacka Vov> wrote: Thank you! Stephen Thatcher Manager, WNS Development North Slope Development ConocoPhillips Alaska, Inc. P.O. Box 100360 Anchorage, AK 99510-0360 phone 907.263.4464 November 5, 2020 Jeremy Price, Chair Alaska Oil and Gas Conservation Commission 333 W. 7th Ave #100 Anchorage, Alaska, 99501-3539 RE: Application for Amendment of Pool Rules, Alpine Oil Pool, North Slope, AK Dear Commissioner Price, In accordance with 20 ACC 25.520 (Field and pool regulation and classification), 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 amendment to Conservation Order ("CO") 443C to reclassify the Alpine Oil Pool ("AOP") and to prescribe pool rules for development of the AOP within the CRU. This amendment includes a proposed expansion of the AOP: (1) for future Fiord West ("FW') development to be drilled from the CD2 drillsite, (2) to accommodate continued western and southern development from CD5 drillsite, and (3) to update and standardize pool rules for the deep CRU intervals to enable efficient operation and development under a single set of rules for these similar, related, and interconnected intervals. This would effectively incorporate the Fiord Oil Pool ("FOP") into the AOP, terminating Fiord CO 569. Pursuant to AS 31.05.035 and 20 AAC 25.537, CPAI requests that Appendix 1 to this application be treated as confidential as the information is a trade secret or commercially confidential and proprietary information. 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 Dana Glessner (265-6478, glessd@conocophillips.com) if you have questions or require additional information. Regards, Stephen Thatcher Manager, WNS Development Cc: Tom Stokes, Alaska Department of Natural Resources, Division of Oil and Gas Chait Borade, Arctic Slope Regional Corporation Erik Kenning, Arctic Slope Regional Corporation Wayne Svejnoha, United States Department of Interior, Bureau of Land Management Enclosures (2) CPAI Application for Pool Rules November 5, 2020 Page 2 of 43 ConocoPhillin.c. APPLICATION FOR POOL RULES OF THE ALPINE OIL POOL November 5, 2020 1. Introduction 2. Geology 3. Reservoir 4. Reservoir Development 5. Drilling 6. Well Operations 7. Facilities 8. Proposed AOP Rules List of Figures: 1. Existing Alpine and Fiord Oil Pools 2. Existing Alpine and Fiord Pools with Reservoir Outlines 3. Proposed Expanded Alpine Pool Area 4. Individual Reservoirs of the Proposed Expanded Alpine Oil Pool 5. Defining well, Alpine No. 3, highlighting Pool interval 6. Representative Wells, Alpine No. 1 and Fiord No. 5 7. Stratigraphic cross section, LCU Datum 8. Stratigraphic cross section, West to East, LCU Datum 9. Existing Fiord West Kuparuk Wells with Kuparuk / Nechelik Selective Completions 10, Proposed Alpine Pool and Confining Intervals 11. CRU Map with Potential Drilling Locations within the Proposed Expanded AOP 12. Alpine Producer Well Schematic 13. Alpine -Fiord West Producer Well Schematic Appendix 1 — Confidential Information 14. Fiord West Kuparuk C Gross Thickness (Appendix 1 — Confidential information) 15. Nechelik Net Pay Map (Appendix 1 — Confidential information) 16. Combined Alpine C and Alpine A net pay (Appendix 1 — Confidential information) 17. LambdaRho seismic attribute from the Alpine 10 seismic survey (Appendix 1 — Confidential information) 18. Alpine A net pay map (Appendix 1 — Confidential information) CPAI Application for Pool Rules November 5, 2020 Page 3 of 43 1. INTRODUCTION Document Scope This application is submitted for approval by the AOGCC to amend the AOP and FOP and establish Pool Rules pursuant to 20 ACC 25.520. The current AOP and FOP areas can be seen in Figure 1 and the outlines of all reservoirs referred to in this application can be found in Figure 2. The current AOP includes the Alpine and Nanuq-Kuparuk ("NK") reservoirs and the current FOP includes the Fiord Nechelik ("FIN"), Fiord Kuparuk ("FK") and eastern Fiord West Kuparuk ("FWK") reservoirs. The purpose of this document is to gain authorization from the AOGCC for expansion of the AOP to: 1. Include the new FW development area, which encompasses the western continuation of both the existing FWK and FIN accumulations. 2. Expand the AOP to the west and south to include continued development from CD5 3. Combine the existing AOP and FOP into one pool to update and align rules Changes are requested for the following rules from the current AOP and FOP: AOP CO 433C (2017) Change Proposed this Order Rule 1 Field and Pool Name (Source: CO 443A) No Rule 2 Pool Definition (Source: CO 443B) Yes Rule 3 Well Spacing (Source: CO 443B) No Rule 4 Drilling and Completion Practices (Source: CO 443) No Rule 5 Well Safety Valve Systems (Source: Other Order No. 66) No Rule 6 Reservoir Pressure Monitoring (Source: CO 443) No Rule 7Gas-Oil Ratio Exemption (Source: CO443C) No Rule 8 Reservoir Surveillance Report (Source: CO 443) No Rule 9 Well Testing (Source: CO 443) No Rule 10 Sustained Casing Pressure (Source: CO 443A) No Rule 11 Administrative Action (Source: CO 433C) No Rule 12 Gas Offtake Rate (Source: CO 443C.001) No Fiord CO 569 (2006) Change Proposed this Order Rule 1 Field and Pool Name Yes -becomes Rule 1 in AOP Rule 2 Pool Definition Yes - becomes Rule 2 in AOP Rule 3 Well Spacing No - becomes Rule 3 in AOP Rule 4 Drilling Waivers Yes - update to current AOP Rule 4wording Rule 5 Automatic Shut-in Equipment Yes - reference Other Order 66 now Rule 6 Common Production Facilities and Surface Commingling Yes - becomes Rule 9 in AOP Rule 7 Reservoir Pressure Monitoring Yes - becomes Rule 6 in AOP Rule 8 Gas -Oil Ration Exemption Yes - becomes Rule 7 in AOP Rule 9 Annual Reservoir Review Yes - becomes Rule 8 in AOP Rule 10Annular Pressures Yes- update to current AOP Rule 10wording Rule 11 Use of Multiphase Flowmeters in Well Testing No - replaced already by CO 569.002 Rule 12 Administrative Action Yes - update to current AOP Rule 11 wording CPAI is concurrently and separately seeking an amendment to Area Injection Order ("AIO") 18D from the AOGCC for the classification and rules to govern the expanded AOP. CPAI submits this application to the AOGCC in its capacity as Operator and 100% owner of the producing intervals in the CRU. The scope of this application includes a discussion of geological and reservoir properties of the proposed expanded AOP as they are currently understood, and CPAI's plans for reservoir development, reservoir surveillance, and well construction. CPAI Application for Pool Rules November 5, 2020 Page 4 of 43 This application will enable the AOGCC to establish rules that will allow economic development of the resources, promote greater ultimate recovery, prevent waste, and improve operational efficiency within the AOP. This application contains confidential data and interpretation concerning the AOP which is being provided confidentially in accordance with the provisions of AS 31.05.035 and 20 ACC 25.537. Confidential information is provided in Appendix 1. Pool Area and Interval The proposed area to be covered by the expanded AOP Rules is shown in Figure 3. The individual reservoirs of the proposed expanded AOP with potential development wells can be found in Figure 4. The vertical limits of the proposed expanded Alpine pool is defined as the strata common to, and correlating with, the interval between 6,920 feet and 7,559 feet measured depth in the Alpine No. 3 well (Figure 5). Three reservoirs are present within the proposed pool: the Jurassic reservoirs commonly known as the Nechelik and Alpine sandstones within the Kingak Formation, and sands within the Lower Cretaceous Kuparuk River Formation (Kuparuk C). A more representative stratigraphic section for the Alpine and Kuparuk reservoirs is exhibited by the Alpine No. 1 well between the measured depths of 6,980 feet and 7,276 feet, due to the presence of complete Alpine A and Alpine C intervals, and a thicker Kuparuk sand package. The Fiord No. 5 well, between the measured depths of 7,021 and 7,172 feet, exhibits a more representative section of the Nechelik reservoir (Figure 6). Project Background The original AOP was established through CO 443 effective in October 1998. When originally established, the AOP included the accumulation of hydrocarbons common to and correlating with the interval between the measured depths of 6,876 feet and 6,976 feet in the Bergschrund No. 1 well. This accumulation stratigraphically defined the oil-bearing sandstone body named Alpine. The AIO to inject fluids for enhanced oil recovery from the AOP was granted in January 2000. In October 2004, CO 443 and AIO 18 were concurrently expanded and amended into CO 443A & AIO 18B to accommodate additional development. In March 2009, the AOP was again amended to CO 443B in order to stratigraphically include the NK Oil Pool acreage within the AOP due to the communication that was indicated between the Kuparuk and Alpine intervals from drilling, well log, pressure and production log data. The AOP was redefined as the accumulation of hydrocarbons common to and correlating with the interval between the measured depths of 6,980 feet and 7,276 feet in the Alpine No. 1 well. The AOP AIO was also concurrently amended to AIO 18C. In June 2017, the AOP and AIO were again amended into CO 443C and AIO 18D to include sections in the west for continued development and to exclude full and partial sections on the eastern boundary of the AOP. The AOP currently includes the Alpine and NK formations (AIO 18D & CO 443C) defined as the accumulation of hydrocarbons common to and correlating with the interval between the measured depths of 6,980 feet and 7,276 feet in the Alpine No. 1 well. The FOP is made up of the FK and the FN intervals found between the measured depths of 6,876 feet and 7,172 feet in the Fiord No. 5 well. Both of these intervals were included in the same pool due to the sand -on -sand contact and hydraulic communication observed between the FK interval which directly overlays the FN interval (AIO 30 & CO 569). The FOP is overlain and confined from above by approximately 90 feet of Kuparuk D and Kalubik shales. The pool is underlain and confined from below by at least 330 feet to 1,100 feet of interbedded mudstone, siltstone and very fine-grained sandstone assigned to the Kingak formation. The AOP expansion is requested for three reasons: (1) include the FW development area to be drilled from the Colville Delta ("CD") 2 drillsite, (2) to accommodate continued western and southern development from CD5 drillsite, and (3) to update and standardize pool rules for the deep CRU intervals to enable efficient operation and development under a single set of rules for these similar, related, and interconnected intervals. CPAI Application for Pool Rules November 5, 2020 Page 5 of 43 The FW development area is located to the west of the FOP and the north of the AOP and encompasses the western continuation of the existing FWK and FN accumulations. The FWK is a third accumulation of the Kuparuk C sandstone in the CRU; portions of this accumulation are covered within the existing AOP and FOP. The overlying and underlying confining intervals in the AOP, FOP, and FW area are laterally continuous throughout the development area (Figures 7 & 8). The AOP, FOP, and FW development area all share the same upper confining interval, the Kalubik Formation and HRZ shales, which has historically shown confinement of injected fluids and is expected to confine injected fluids across the expanded area. Similarly, the proposed AOP will share the same lower confining zones, the silts and shales of the Kingak Formation, which has historically shown confinement of injected fluids in the FOP. Additionally, it is requested that the FOP be terminated, and the FOP be combined into the existing AOP to form the expanded AOP (Figure 3). CPAI believes that the combination of AOP, FOP, and FW reservoirs into a single AOP will harmonize pool rules for these deep interconnected and related CRU reservoirs. This will promote operational efficiency and standardization across accumulations, and will not result in waste, jeopardize correlative rights, or compromise ultimate recovery. Ownership CPAI is the operator and 100% working interest owner of the producing intervals in the CRU. The Surface Owners of the proposed expanded AOP area are Kuukpik Corporation, the State of Alaska, the United States of America, Lydia Sovalik, Joeb Woods, Jr., Marlene Michelle Woods, and Martha Lynn Neakok. The Subsurface Owners of the AOP are the State of Alaska, the United States of America, and Arctic Slope Regional Corporation. Participating Areas are unaffected by this pool expansion. CPAI Application for Pool Rules November 5, 2020 Page 6 of 43 157QUA I "7■■■■■■■■■ SEEM ■■■■■ •■■■■■■■ii■ • • . • • •■■■■ MEN ■■■■■ME M ON _ ■i■■■■■■■■■■■ NONE ■N ■■■i ■■ ■■■■■■ ■■■■■■■■■11■■i■i■■■ ■■ i■■■■■ ■1■■■■■■ iii■i■■■■■ii■ ■■■■■■■ ■■■■■■■ t■■■■■■■■■■■■ MEN ON =■il■■■■■■�■■■■■1■■■■■■ ■■o■■®■■■ �■■■■■■®i■i■■■■■i ■i'�l�iOEM ■■■■ 1■■ ■■i■■■11■■■■i■ ■ �'1■■■■■■ _ 1■■ ■■■■■■■■■■■ ■ ON ME �■■■■■■■■■■■■■ ■ ■■■t■■■■■■■ 1■■i■■■sly■■ ■■■■■■■mom ■■■■■■■ 1■®■■■■■■■■■■■■■ ■®�li ON :1■11■■■■■■■■■1!■■■■■■ ME mom ■■■■■■■ 1■■■■■■■00■■■■■■0■■i■■11■■■■■■ t■■■■■■■■■■■■■■■■Niii■■tit■■■ o■■®■■■■■■■■■■+w■■■■■■■■■®■■■■ t■A■■®■■®■■®■■!f■i�■■■i■■ mom ■■ li �■■■■ i■�l■■■®■■i■i■■■MMMIN 114JLJV`J 14Quuvu '�'� •�-�-' Figure 1: Existing Alpine and Fiord Oil Pools CPAI Application for Pool Rules November 5, 2020 Page 7 of 43 . tnnnnn 1"95" 1650ON 15793481 Elmo P. ■■ ■■■■■ ColvilleD61 1. x 'Pools 1....... — ■■■■■■■■ ■■■■■■ Oil ■■■■■■■ ■■■■■ _ .. ■■■■■ ■■i ■ ■■■■E ... ............. ■■■■ ■■■■■ ■■■■ 1 ... - -rvolf oil ■■■■■■■■■■■■�■■■■■■■�■ ■■■■ IE ■■■■■■1■■i ■■M■■ ■■i'�■■■■■■■ 1■ ■■■■■®■■ E■i■ ■■1!O■■!�■■■■■■ 1■■■■■■■■■�@ ■■■! ■�■■■■■■■■■■ !■■■■■■■■■■ ■®oEiEM ME■ ONE ■■■ 1■■■■■■■■lil■1liiMEMS n■■ MEMO ■■■■■ 1■■■■■■■■■■!MM■E■■■■ItENE ■■■■■ 1■II�E■■■■■■■O■MIf■■■■■■■■OEM■■■ I■ ■EEM■■EOE■■■■■■■11M■■N No it®off■■■■■�����®������e����:�� 11432309 1450000 1475000 Figure 2: Existing Alpine and Fiord Pools with Reservoir Outlines CPAI Application for Pool Rules November 5, 2020 Page 8 of 43 11432309 1450000 1475000 1500000 1525000 IbwUUU Proposed AOP Overview Map Proposed AOP Reservoir .........._......... .....__.... C RU Drdlsites.................................................... Colville River Will ............................ ....— • — - — Proposed AOP Boundary ......... ....... ........... - ewung Pools Alpine Oil Pool ....._............ wew.._-..........._..._..-�� Added Lands AOP Expansion ....... ............ ---- Figure Figure 3: Proposed Expanded Alpine Pool Area CPAI Application for Pool Rules November 5, 2020 Page 9 of 43 1440000 1450000 1475000 1500000 1525000 taauvvu t�Dtnta D o I Rese—V OUWnes , ' f n NeCnel!V.................... ....... .......... .... 1 ____- � Kuparur Alone A ands .... .............` .COIYiiIE.RIVeC' Boundary ! _ - Un4......... ........... ............ Proposed A.OP Reservoir Wine ... _.... - ' ... - . PtopDeeC AOP Bounds, ............................. :. ' �v KIO�Y •�f+./rk Potential tVeile Alone Potenaai Well .......... . ' Kupauk Potential Wel t i e i.. .. � �Ff6Rf WestKu�efstk.,,;,,,,;.�"""t,,,,,„�,,,...•""'� 1. { t \ r;a*e ate. _p01 ;4 „. ptpiae A p }} o G Tooth 1 L 0 o tt .tl :4eE t.. .. .�.r'_....r r �; • ..g.,y" [}gyp $S_c .. s I t Miles, „ tddntxltl 1d50000 t475000 1500000 1525000 1550000 1561519 Figure 4: Individual Reservoirs of the Proposed Expanded Alpine Oil Pool CPAI Application for Pool Rules November 5, 2020 Page 10 of 43 Alpine 3 Strat Tops. Formation GR b!D R:so 0o c :ai isa 73 1900 onm m 10 o i' s :�—# m 6900 Kalubik Fm. 6920' MD Top Kuparuk 6950 Kuparuk River Fm. Kuparuk C 7000 Miluveach Fm. Top Alpine 7050 1 a 7100 i i 7150 i I Top Nuiqsut + I 7250 I i f Kingak Fm. .� 7300 7350 Top Nechelik 7400 i i 7450 i 1 7500 iI i "T550__ 7559' MD Base Nechelik Figure 5: Defining well, Alpine No. 3, highlighting Pool interval CPAI Application for Pool Rules November 5, 2020 Page 11 of 43 A n C b A 3 a n 3 b V Mu r zn O In a Ln Figure 6: Representative Wells, Alpine No. 1 and Fiord No. 5 CPAI Application for Pool Rules November 5, 2020 Page 12 of 43 �p S 1 Figure i. Stratigraphic cross section, LCU Datum. Proposed pool reservoir layers in yellow, intervening silts and shales in light gray, and confining zones in dark gray. Presence of strata in wells below well TD is established through offset well control and seismic data. Note that reservoir intervals are not reservoir quality across all wells in cross section. CPAI Application for Pool Rules November 5, 2020 Page 13 of 43 r5 �m O1 Figure 8: Stratigraphic cross section, West to East, LCU Datum. Proposed pool reservoir layers in yellow, intervening silts and shales in light gray, and confining zones in dark gray. CPAI Application for Pool Rules November 5, 2020 Page 14 of 43 2. GEOLOGY The proposed expanded AOP is defined as the strata common to, and correlating with, the interval between 6,920 feet and 7,559 feet measured depth in the Alpine No. 3 well. Three reservoirs are present within the proposed pool: the Jurassic reservoirs commonly known as the Nechelik and Alpine sandstones within the Kingak Formation, and sands within the Lower Cretaceous Kuparuk River Formation (Kuparuk C). A stratigraphic cross section through the CRU is shown in Figures 7 and 8. The Alpine and Nechelik, which are aerially more extensive, are locally overlain by the Kuparuk C at the Lower Cretaceous Unconformity ("LCU") and the three sands are in communication via sand -on -sand contact through the LCU. Pressure communication between the underlying Alpine and Nechelik to the overlying Kuparuk has also been historically interpreted via natural faulting. This communication has been shown to only exist below the Kalubik / HRZ confining interval. • The communication from the Alpine to the FWK is established by the "toe up" of the CD2-02 Alpine A injection well at TD, per previous AOP 2009 vertical expansion (CO 443B). This well exhibits sand -on -sand contact of the underlying Alpine to the overlying Kuparuk C at the LCU. This sand -on -sand contact is a result of the angular truncation of Jurassic strata at the LCU, on top of which the Kuparuk C sandstone was deposited. • Pressure communication between the FIN and the FK is interpreted to be a result of sand -on -sand contact, as observed in the injector CD3-108 at TD, per CO 569 in 2006. This sand -on -sand contact is a result of the angular truncation of Jurassic strata at the LCU, on top of which the Kuparuk C sandstone was deposited. • Additionally, as per previous AOP 2009 vertical expansion (CO 443B), the Alpine communicates to the overlying Kuparuk at CD1 drillsite and the NK at CD4 drillsite through faults as evidenced by pressure observations within the Kuparuk at those locations. • Similarly, communication between the FWK and western FIN is expected to continue to occur through the LCU and/or faults as FW development continues. • Additional reservoir connections to note: the FW reservoirs (both FN and FWK) are aerially expansive enough to fall within both the existing FOP and AOP areas, and the active wells CD3- 118, CD3-127 and CD3-128 which are currently part of the FOP, have already been drilled and completed into the eastern portion of the FWK reservoir in both the Kuparuk and Nechelik sands (Figure 9). The overlying and underlying confining intervals, which are expected to confine all injected fluids, are common to all intervals across the proposed expanded AOP and are defined below: Upper Confining Interval Deep marine shales and silts of the HRZ and Kalubik Formation form the upper confining zone for the proposed expanded AOP. Total thickness as observed in available wells varies from 100 feet to over 230 feet. Recommended Pool Three reservoirs are present within the proposed pool: the Jurassic reservoirs commonly known as the Nechelik and Alpine sandstones within the Kingak Formation, and sands within the Lower Cretaceous Kuparuk River Formation (Kuparuk C). Three informally -named Kuparuk accumulations are present within the pool: the NK, the FK, and the FWK. Lower Confining Interval The shales and silts of the Lower Kingak Formation form the lower confining zone for the proposed expanded AOP. The Lower Kingak is approximately 700 feet to 1300 feet thick in the proposed area of development, as estimated by available well and seismic data. The lower confining zone is not penetrated in the Alpine No. 3 type log (the total depth of the well is just CPAI Application for Pool Rules November 5, 2020 Page 15 of 43 below the base of the Nechelik reservoir); however, the Nechelik No. 1 exploratory well penetrated and logs the entire lower confining zone (Figure 10). CPAI Application for Pool Rules November 5, 2020 Paqe 16 of 43 1501002 1505000 1510000 1515000 152000U iazouw iuowuu Colville River Unit ............... ..._.................. ... - .. m ° Exploration t Test Well ..._..._._._... Kuparuk Reservoir Oultine Kuparuk C Formation Top _....... ..... ._.......... + FAD 5 \ Nechelik Formation Top _............................ + 8 Existing Pools Alpine W Pool ....._........._...__.._._ ............. © o aFiord 00 Pool ....................................._.._.... ���y '� Fiord Kuparuk m CD3-118 MGLIQ : 3 3 Lruk Fiord Wes CD3-127 \l RHEA I HE�Ltx I `` , CD3-128 s � W E � 5 \\ n 15010n2 1505otio 1510000 t i 152MM Miles )000 1536134 Figure 9: Existing Fiord West Kuparuk Wells with Kuparuk / Nechelik Selective Completions within the FOP CPAI Application for Pool Rules November 5, 2020 Page 17 of 43 NECH£uK i SSTVO! S" REM - 189fa'(68. f.G oQnA'm.. f.dT MW. f.6*tlR � 6428 4 65C 0 Av s 3 t! _ _ - 6600 RMA Kup 6800 { 6800 7000 — ..... MO 7200 7300 _....._._..__. 7400 _.._...__.. __ 75M 4 r Ota 7600 Z700 7800 7900 8000 _. etecr 820D fisoo Figure 10: Proposed Alpine Pool and Confining Intervals at Nechelik No. 1 10 CPAI Application for Pool Rules November 5, 2020 Page 18 of 43 Geologic Description of Added Lands Fiord West Kuparuk The FWK reservoir in the FW area is the western continuation of the FWK reservoir already under production and injection within the current FOP via the completions in CD3-118, CD3-127 and CD3-128 (Figure 9). The presence of this reservoir in the FW area was established with the Temptation No. 1 and 1A, Iapetus No. 2, and Char No. 1 wells. More recently, the stratigraphic test well Rhea No. 1, drilled in 2020, established FWK reservoir presence south of prior well control. Connectivity in the FW area to the FWK reservoir in the FOP area is suggested by similar oil gravity in both areas. Nechelik The FN reservoir in the FW development area is the westward continuation of the Upper Jurassic FN reservoir within the existing FOP, penetrated in the FW area by the Iapetus 2, Char 1, and Temptation 1 and 1A wells. Other than minor faulting within the Nigliq fault system, the reservoir is interpreted to be continuous throughout the expanded pool area (Figures 7 & 8). Alpine The southwestern limit of Alpine A sand has been determined by three wells, the producer CD5- 24, the injector CD5-25, and the producer CD5-26. All three wells reached the limits of drilling capacity before reaching the edge of the sand. Thickness is determined with crosscuts through the section and deep resistivity steering tools that help image the boundaries. The producer CD5- 26, the southwestern most well, performed several crosscuts while drilling to determine actual thickness. Near the toe of the well the reservoir thinned but then thickened suggesting the sand extends further south than previously thought (See Appendix 1, Figures 16-18). Westward extension of the Alpine reservoir is anticipated based on well control and seismic data currently available. The Alpine A and C sand were found with two penetrations in the CD5-21 exploration well drilled in 2016 and the toe up test of the producer CD5-96 drilled in 2020. The data indicate the presence of an accumulation of Alpine C sand that thickens to the west of the current CD5 development. There have not been any production tests of the Alpine C sand in this area yet. Alpine C reservoir quality will continue to be analyzed in conjunction with the planned westward development of Alpine A wells. The Alpine A net pay in this area has been proven to extend west and north of the current development (See Appendix 1, Figures 16-18). CPA] Application for Pool Rules November 5, 2020 Page 19 of 43 3. RESERVOIR Introduction The proposed expanded AOP is shown in Figure 3, and consists of the following reservoirs described in the Geology section above and in Appendix 1 - Confidential information: • Alpine • Fiord Nechelik (FN) • Fiord Kuparuk (FK) • Nanuq Kuparuk (NK) • Fiord West Kuparuk (FWK) The table below summarizes fluid properties for each of the reservoirs included in the proposed expanded AOP. More specific to the new additions of the proposed expanded AOP, the data for the FWK reservoir is based on a PVT study of a bottom hole reservoir fluid sample and API gravity measurements from FWK delineation wells. The FN reservoir in the FW development area is a western extension of the existing FN reservoir from the FOP and fluid properties are expected to be the same as from FN wells produced to date. The FWK and FN reservoirs, like all the reservoirs within the proposed expanded AOP, have low oil viscosities which yields favorable mobilities for water injection and efficient reservoir sweep. The similar fluid properties in common to each of the reservoirs also will allow for the recoveries to be maximized with an enriched water alternating gas ("EWAG") flood to partially offset existing field decline. Fiord Nechelik Fiord Kuparuk Alpine Nanuq Kuparuk Fiord West Kuparuk _ Initial Reservoir Pressure 3210 3200 3200 3200 3200 _ psig Reservoir temperature _ 165 _ 165 160 158 158 degrees F GOR 520 565 812 750 750 scf/bbi PI gravity 30 28-30 36 39-40 37-40 degrees API Bubble point pressure 2184 1 2395 2356 2051 _ 2051 M psig Oil formation volume factor 1.26 1.31 1.43 1.41 1.41 _ b/stbo Oil viscosity 0.89 0.83 0.48 0.69 0.69 cp Gas formation volume factor (at saturation pressure) 0.81 0.81 1.06 0.79 0.79 bbl/mscf Fiord West Original Oil -in -Place ("OOIP") The pre -development stock tank OOIP volumetric estimates for the FWK reservoir range from 28 to 116 MMSTBO. The OOIP estimates for the undeveloped extension to the west of the existing FN reservoir range from 98 to 167 MMSTBO. The estimates are based off well control, core data analysis, 3D seismic, and production data to date. These OOIP number are based on current information and are subject to change as additional reservoir data from the potential development wells at FWK and FN become available and enhance the understanding of sand distributions. Net pay maps for most likely OOIP scenarios are shown in Figures 14 and 15 in Appendix 1 - Confidential information. Alpine CD5 Development Original Oil -in -Place ("OOIP") Within the Alpine reservoir, there are two primary potential development areas as part of this application (the "northwestern CD5" and the "southwestern CD5' areas). The stock tank OOIP volumetric estimates CPAI Application for Pool Rules November 5, 2020 Page 20 of 43 for the northwestern CD5 area ranges from 20 to 47 MMSTBO. The stock tank OOIP volumetric estimates for the southwestern CD5 area ranges from 11 to 26 MMSTBO. The estimates are based off well control, geomodelling, 3D seismic, and production/injection data to date from nearby wells. These OOIP number are based on current information and are subject to change as additional reservoir data from the potential development wells Alpine CD5 become available and enhance the understanding of sand distributions. Net pay maps for most likely OOIP scenarios are shown in Figures 16 and 18 in Appendix 1 - Confidential information. CPAI Application for Pool Rules November 5, 2020 Page 21 of 43 4. RESERVOIR DEVELOPMENT Development Plan The AOP is currently being developed from four drillsites in the CRU: CD1, CD2, CD4, and CD5. The FOP is currently developed from CD3. The FW reservoirs will be developed from CD2. All wells will be connected to the Alpine Central Facility ("ACF"). The AOP and FOP have been developed with vertical, slant, and horizontal production and injection wells in line drive patterns, oriented with the maximum principal geomechanical stress, that range in length from 3,000 feet to 23,000 feet within the reservoir. Well spacing for the existing Alpine, FN and FK reservoirs range from 1500 feet to 2100 feet while spacing for the NK is 5500 feet. Multilateral completions and stimulation are considered on a well by well basis depending on vertical separation and when reduced rock quality is encountered. Pilot holes are also utilized as needed to provide reservoir data to assist with optimization of horizontal well placement. Pressure support will be maintained with water and gas injection targeting a voidage replacement ratio of 1.0. An EWAG flood will be continued to improve ultimate recovery. Although the gas flood is not miscible with current injection composition, EWAG will yield incremental recovery with condensing components that will result in improved oil mobility due to oil swelling and reduced interfacial tension. Long horizontal injection and production wells are expected to yield efficient areal and vertical sweep due to the low oil viscosity which yields favorable waterflood mobility. EWAG will enhance displacement efficiency and assist with reservoir throughput as the waterflood matures. The future development plan includes continued horizontal drilling at CD5 in the Alpine A and C sands to the west, Alpine A sand to the southwest, and initiation of the FW development. There are currently four western and four southwestern potential wells to target the Alpine sands. The FW development will be the first application of extended reach drilling ("ERD") at Alpine. The FWK and FN targets will be drilled from the CD2 drillsite. There are currently seven FWK and 29 FN potential wells using ERD technology (Figure 11). Recovery Mechanisms Pressure support in the reservoir with water injection is necessary due to the expected high voidage rates and relatively low recovery without voidage replacement. In addition, the full incremental benefit of the proposed EWAG gas flood will not be realized without water injection. The historical success of the secondary and tertiary recovery mechanisms in the Alpine A&C, NK, FN, and FK provides an analog for the expected performance of future development in the AOP. The favorable rock properties and waterflood mobility throughout the proposed AOP reservoirs are expected to yield an ultimate EWAG recovery that will be in the range of 50 to 70% of OOIP for Alpine, NK, and FWK. For FK and FN, the EWAG recovery will be in the range of 30 to 35% of OOIP. Uncertainty factors that may impact the recovery estimate include facies distribution, net pay, voidage replacement, well productivity, and OOIP. Although the gas flood is not miscible with current injection composition, EWAG will result in oil swelling and yield incremental recovery. Reservoir simulation and analytical analysis indicate that primary recovery alone is expected to yield recovery of up to 20% of OOIP. The remainder of the ultimate recovery is expected through secondary and tertiary mechanisms with EWAG injection. The low viscosity oil of the AOP reservoirs is conducive to high recovery efficiency. Reservoir pressure needs to be maintained above the bubble point to preserve this favorable condition for high ultimate recovery. CPAI Application for Pool Rules November 5, 2020 Page 22 of 43 Producing Gas -Oil Ratio ("GOR") Expectations CPAI requests that the requirements described in 20 AAC 25.240 be waived for the proposed AOP since the pool plans are to implement enhanced recovery techniques. Since gas will be injected into the AOP during the life of the pool, the GOR is expected to rise above solution GOR in some wells. The breakthrough of re -injected gas will cause GORs of some producing wells to exceed limits set forth in 20 AAC 25.240. Existing Rule 7 in the AOP and Rule 8 in the FOP currently allow for this limit to be exceeded. Additionally, the AOP average reservoir pressure will be maintained above the bubble point pressure with water injection for pressure maintenance. Current AOP and FOP allow for injection of gas as an enhanced recovery technique and gas injection is also requested for the FWK and FN development area as set forth in the proposed AIO. Allowable Gas Off Take Rate ("AGOTR") from the CRU In August 2018, the AOGCC approved an amendment to both the Alpine CO 443C and Fiord CO 569,001 to allow 7 MMSCFD of gas offtake from CRU to support the Village of Nuiqsut and GMTU development. The GMTU began production into the ACF in October 2018 from the Moose's Tooth 6 ("MT6") drillsite. Production from all the CRU and GMTU pools is commingled and processed at the ACF. All of the commingled gas is either consumed within the CRU for operational purposes, reinjected to enhance oil recovery in the CRU, returned to GMTU for operation and gas injection purposes, or provided to the Village of Nuiqsut. Any excess GMTU gas after accounting for GMTU's share of fuel and flare is injected into CRU participating areas. Production from the second drillsite in GMTU, MT7, is expected to start in December 2021. CPAI is not requesting a change to the AGOTR volume but for clarity is requesting a revision of the wording in Rule 12 to state "cumulative annualized average". CPAI Application for Pool Rules November 5, 2020 Page 23 of 43 14323019 1450000 I gmnAn 1r,9rInffi 1550000 1679346 Proposed AOP Development Map Proposed AOP Reservoir ........ O 1432309 1450DO0 141buuu I*WUUU -I.- Figure 11: CRU Map with Potential Drilling Locations within the Proposed Expanded AOP CPAI Application for Pool Rules November 5, 2020 Page 24 of 43 5. DRILLING Drilling/Well Design The AOP will continue to be accessed by wells drilled from gravel pads utilizing drilling procedures, well designs, and casing and cementing programs consistent with current practices on the North Slope. Casing programs will be designed to mitigate borehole instability problems in the shales just above the reservoir. Maintaining stability of the borehole and horizontal geo-steering in the pay zone are keys to success. Figure 12 illustrates a generic AOP producer well schematic, which is also similar to the planned injectors. For proper anchorage and to divert an uncontrolled flow, 80 feet of conductor casing will either be drilled or driven on 20 foot well centers and cemented to surface. Cement returns will be verified by visual inspection. Surface holes will be drilled and casing set below the C40 marker in the Colville Group for proper anchorage and protection from permafrost thaw and freeze back. Within the planned development area, the base of permafrost is interpreted to be approximately 800 to 1,200 feet TVDSS. No hydrocarbon bearing intervals have been encountered to this depth in exploration wells and this casing point provides sufficient depth for kick tolerance. Surface casing strings will be cemented in accordance with 20 AAC 25.030(d)(4). The blowout prevention equipment ("BOPE") will be installed and tested in accordance with 20 AAC 25.035. A Formation Integrity Test ("FIT") will be performed in accordance with 20 AAC 25.030(f) Top of cement for the casing will extend a minimum of 500 feet measured depth or 250 feet true vertical depth, whichever is greater, above the shoe or higher if any hydrocarbon bearing formations are encountered in accordance with 20 AAC 25.030(d)(5). Managed pressure drilling ("MPD") may also be used to minimize borehole pressure cycling and provide sufficient overbalance to hold back the mechanically unstable shale formations. The liner top of cement will extend a minimum of 500 feet measured depth or 250 feet true vertical depth, whichever is greater, above the formation sand in accordance with 20 AAC 25.030(d)(5) or higher based on the production packer setting depth. Based on current knowledge of reservoir characteristics, CPAI expects future CD5 development in the AOP to continue using horizontal wells with solid liners including pre -perforated pups. External swell packers may be added to isolate out of pay excursions and/or fault crossings along the lateral. Multi- lateral or other completion methods may be employed as conditions dictate. Both injection and production wells will be completed with 4-1/2 inch tubing to minimize hydraulic friction, where needed, otherwise 3-1/2 inch will be installed. The FWK and FN expansion will be developed as extended reach horizontal wells with an additional two casing strings installed to manage pore pressure and borehole instability above the reservoir (Figure 13). The FWK wells will be completed with 5 inch by 4-1/2 inch tubing to overcome overpull while running the completion in hole and also minimize hydraulic friction while producing or injecting. The FN expansion wells will be completed with 4-1/2 inch or 3-1/2 inch tubing based on expected flowrates. Drilling Fluids The drilling fluid program designed for wells within the AOP will be prepared and implemented in accordance with 20 AAC 25.033. Formation pressures for the strata to be penetrated will be estimated based on data gathered from existing wells and exploration wells drilled into the AOP. Water based muds will be primarily used. CPAI Application for Pool Rules November 5, 2020 Page 25 of 43 Annular Disposal Disposal of drilling wastes will be proposed in accordance with 20 AAC 25.080 in annuli of wells with surface casing set below the permafrost. Based on the extensive development in the AOP area over the last twenty plus years, no freshwater sands have been encountered and there are no freshwater aquifers present in the proposed expanded AOP area as further described below. Historical AOGCC findings state that there are no freshwater aquifers present in the CRU. Those prior findings and conclusions remain valid. CPAI requests a finding that no freshwater aquifers are present in the expanded AOP area. An internal study conducted by CPAI found no shallow fresh water bearing sands containing less than 10,000 ppm TDS in the proposed FW development area. In the FW development area several wells have been logged from surface through the reservoir zone. No clean, porous sands with calculated salinities of less than 10,000 ppm TDS were present below the permafrost zone. The C30 zone is the only shallow clean, porous sands for analysis, presented below. The methodology used and results obtained from salinity calculations are as follows. The calculations use the standard Archie correlation and log derived data to obtain a resistivity of water, Rwa, value using the following formula: OmxR, RWa— Rwa Resistivity of water necessary to make a zone 100% water bearing 0 Porosity in decimal from logs Rt Formation resistivity from logs m Cementation exponent a Tortuosity (assumed to be 1.0 per Archie correlation) There is no cementation exponent information from the wells used for this study but such data does exist in the CD2-11 Qannik well. This Qannik well is the analog for the wells used for this study. Formation data from the CD2-11 shows m to be 1.8, hence range of 1.8-2.0 was used for the analysis that follows. Well: Iapetus 2 Formation: C30 (2727-3102ft, MD) Calculation: Rt and RHOB are both LWD curves. Rt = 2.3ohm-m, RHOB = 2.08g/cc, m = 2. Porosity = (2.65-2.08)/ (2.65-1) = 0.345 The calculation yields a Rwa equal to 0.27, using chart Gen-1 from Schlumberger chart books with a formation temperature of 65 degrees Fahrenheit, gives a salinity of 27,800 ppm, NaCl equivalent, hence no freshwater aquifers. Well: Char 1 Formation: C30 (2435-2745ft MD) Calculation: Rt and RHOB are both LWD curves. Rt = 2.53ohm-m, RHOB = 2.09g/cc, m = 2. Porosity = (2.65-2.09)/ (2.65-1) = 0.34 The calculation yields a Rwa equal to 0.29, using chart Gen-1 from Schlumberger chart books with a formation temperature of 65 degrees Fahrenheit, gives a salinity of 23,600 ppm, NaCl equivalent, hence no freshwater aquifers. Well: Temptation 1 Formation: C30 (2430-2749ft, MD) Calculation: Rt and RHOB are both LWD curves. Rt = 2.39ohm-m, RHOB = 2.10g/cc, m = 2. Porosity = (2.65-2.10)/ (2.65-1) = 0.33 CPAI Application for Pool Rules November 5, 2020 Page 26 of 43 The calculation yields a Rwa equal to 0.27, using chart Gen-1 from Schlumberger chart books with a formation temperature of 65 degrees Fahrenheit, gives a salinity of 27,700 ppm, NaCl equivalent, hence no freshwater aquifers. Blowout Prevention General well control for drilling and completion operations will be performed in accordance with 20 AAC 25.035. Directional Drilling (Proposed Rule 4) CPAI requests that the requirements described in 20 AAC 25.050(b) be waived for the proposed AOP to relieve administrative burden. CPAI proposes that the Conservation Order require the following in each Application for a permit to drill instead of the information required by 20 AAC 25.050(b): 1) plan view 2) vertical section 3) close approach data 4) directional data Well Spacing (Proposed Rule 3) CPAI requests that the requirements described in 20 AAC 25.055 be waived for the proposed AOP because the proposed horizontal well development, via line -drive flood pattern, will yield greater recovery than a conventional vertical/slant well development plan with a minimum spacing rule. In lieu of the requirements under 20 AAC 25.055, CPAI proposes that there shall be no restrictions as to well spacing except that no pay shall be opened to a well within 500 feet of an external CRU boundary line where the owners and landowners are not the same on both sides of the line. CPAI Application for Pool Rules November 5, 2020 Page 27 of 43 20" 00 H-40 Welded Conductor to 1 W 10-514" 45.SY L-90 Hydrii 563 6 OTC Surface Casing 2.504' MO t 2,350` TVD @ 42` cemented to surface 3.1W 9.30 L-80 EUE Upper completion: 1) 4-Y,' 12.61M IBT.M Tubing (2 its) XQ to 3-Y.` ELIE tubing 3) Shallow hippie prorde 2) 3.11V x 1' Cameo K8MG GLM (xx') wl DV 3) 3-57' x 1' Camco KSMG GLM (xx`) wl OV 4) 3•'/.' x 1 ` Camco KBMG GLM (xx`) w1DCK2 pinned for 2500 psi casing to tbg shear 5) SLB SHP Gauge, Encapsulated I -Wee wtcannon clamps on every joint 6) D hippie 2812' IO 7) WLEG Lower Complebon. 8) UP liner Top Packer 8 Flexlock Lfer Hanger XO 5'" 521 Box X 4 'fi ISTM pin S) D nipple 2.750' ID 10) 4 h., 12.641k L-80 IST-M Liner wi ball actuated frac ports every -750' 11► Perforated pup 7 Sf6" 290 L40 Myd 563 S STC-M Intermediate Cog to 11.277` MD I7,453` TVD @ 86' Top ltesenro+r at ......... Perforated pup AlpineASaW t ___..__..___>_-.________..r_`_..___..______- 74"' TVD i o a a a o a a a o • i ------------------------------------- i { .........`.` 4-1/s" 12.60 L40 Lineir 6 W4' Hole TO wl bail drop free sleeves 18,30r MD f 7,547 TVD Figure 12: Alpine Producer Well Schematic CP IApplication for Pool Rules November %220 Page 2 of 4 ,ems%i-,5=a 4�§«»�\,•£%2.5�� - 0_ISO 9; }Cr (\\(k� )10 0 ; 2#/> �vv §§k �,,,a@�■�a_R� k 4tli ! m^^ `©\ Figure 13: Alpine -Fiord West Producer Well Schematic CPAI Application for Pool Rules November 5, 2020 Page 29 of 43 6. WELL OPERATIONS Well Design and Completions Production and injection wells will primarily use 4-1/2 inch tubing to minimize friction associated with the high rate potential of the reservoir and the horizontal completions. Based on expected well performance, tubing size is subject to change. Producing wells will be equipped with gas lift mandrels. When needed, a single packer will provide pressure isolation for the tubing -casing annulus. Wells with liners placed in the horizontal segments may utilize combination liner hanger/packers and slotted liners or perforated pups. Artificial Lift Artificial lift will be via gas lift; however, CPAI may employ other techniques (jet pump, electrical submersible pumps, etc.) to optimize reservoir pressure drawdown as the reservoir matures. Dry gas will be delivered to the drillsite at approximately 4000 psi and the pressure will be dropped down to approximately 2000 psi for the purposes of gas lift. Reservoir Surveillance CPAI requests that the AOGCC approve the reservoir pressure monitoring plan set forth in Section 8, Rule 6 of this application. The pool common datum for reporting should be 7,000 ft. TVDSS. Well Work Operations Well work operations in the AOP will include routine mechanical integrity tests of each wellbore and artificial lift maintenance. Operations will also include remedial management of scale, paraffins and other well issues with slickline, a -line, coil tubing, inhibitor, or hot diesel treatments. Stimulation Stimulation techniques in the AOP, including hydraulic fracturing, may be used to enhance well rates. Wellbore trajectories, cementing programs, and tubulars will be designed to accommodate hydraulic fracture stimulation techniques. Hydraulic stimulation operations will be performed in accordance with 20 AAC 25.283. Surface Safety Valves (Proposed Rule 5) Most AOP wells will be equipped with horizontal trees. With this configuration, the surface safety valve and master valve are in the horizontal run of the well's tree. This configuration is employed in CRU wells and improves rig/well interventions while not presenting any significant increase in risk. Otherwise 20 AAC 25.265(c)(1) will be followed. Required periodic inspections and testing will be conducted following notification of the AOGCC consistent with the requirements of 20 AAC 25.265. FW development wells will implement vertical trees due to the casing design. Well Instrumentation and Monitoring (Proposed Rule 10) Wells will be equipped with instrumentation and monitored in real-time at the ACF. CPAI plans to install the following instrumentation: ® Tubing pressure and temperature • Inner annulus pressure 0 Outer annulus pressure CPAI Application for Pool Rules November 5, 2020 Page 30 of 43 Bottomhole pressure (producers) Gas lift rate (producers) ® Water and enriched gas injection rate (injectors) CPAI Application for Pool Rules November 5, 2020 Page 31 of 43 7. FACILITIES Drill Site Facilities and Flowlines The AOP is currently being developed from four drillsites in the CRU: CD1, CD2, CD4, and CD5. The FOP is currently developed from CD3. The FW reservoirs will be developed from CD2. All wells will be connected to the ACF. The following facilities are located at each drillsite: • 2-Phase test separator with gas metering, liquid metering and Phase -Dynamics metering for oil and water fractions of the liquid • Production Heater • Pipe Racks for wells on 10 or 20 feet center spacing • Modules for emergency shutdown ("ESD"), pigging, fuel gas, chemical injection, remote electrical interface module ("REIM") and switchgear Production wells selectively flow to either the production common pipeline via the production header or to the test separator via the test header. Test separator fluids flow out to the production header. Injection wells selectively connect to either the water injection header or the enriched gas injection header. Average estimated surface water and gas injection pressures are 2650 psia and 4000 psia, respectively. These are the expected pressures at the drillsite header accounting for pressure drop in the pipeline system. Production Processing The AOP oil, gas, and water production will be commingled with production from other CRU pools and Greater Moose's Tooth Unit ("GMTU") prior to processing at ACF. Stabilized oil production will be delivered to the Alpine Pipeline and then on to Trans Alaska Pipeline System ("TAPS"). Water production, after delivery to ACF and commingling from other CRU pools and GMTU pools will be injected into CRU pools or GMTU pools for enhanced recovery purposes. Produced gas will be returned to the AOP in the form of either dry gas for gas lift and drillsite fuel or enriched gas for enhanced recovery purposes. All wells connected to the ACF will be managed and prioritized to maximize oil production rate in conformance with any facility limits. AOP production is expected to be fully compatible with production from other CRU pools and GMTU pools from both a production processing and injection perspective. Production Allocation Production allocation to individual production wells in the AOP will be performed in the same manner as other North Slope fields. Wells will be tested at least twice monthly and the well tests will be used to create performance curves to determine the daily theoretical production from each well. An allocation factor comparing actual total daily AOP production sales to the sum of individual well theoretical rates will be used to adjust theoretical well production to allocated well production. CPA] Application for Pool Rules November 5, 2020 Page 32 of 43 8. PROPOSED ALPINE OIL POOL RULES The rules set forth apply to the following area referred to in this order: Umiat Meridian T10N, R3E Section 1-3 all T10N, R4E Section 1-6 all Section 8-12 all T1ON, R5E Section 5 N1/2NW1/4, SW1/4NW1/4, NW1/4SW1/4 Section 6-7 all T11N, R3E Section 1-3 all Section 10-14 all Section 22-27 all Section 34-36 all T11N, R4E Section 1-36 all T11N, R5E Section 1 W1/2W1/2 Section 2-11 all Section 14 NW1/4NW1/4 Section 15 W1/2, NE1/4, N1/2SE1/4, SW1/4SE1/4 Section 16-21 all Section 22 NW1/4, NW1/4SW1/4 Section 28-33 all T12N, RK Section 1 S1/2 Section 2 S1/2 Section 11-14 all Section 23-27 all Section 34-36 all T12N, R4E Section 1-36 all T12N, R5E Section 1-23 all Section 26 NW1/4NW1/4, S1/2NW1/4, SW1/4, W1/2SE1/4 Section 27-35 all Section 36 SW1/4SW1/4 T13N, R4E Section 25 all Section 33-36 all T13N, R5E Section 15-22 all Section 26-36 all Rule 1. Field and Pool Name (no change from AOP, FOP Rule 1 revision) The field is the Colville River Unit. The pool is the Alpine Oil Pool (AOP). Rule 2. Pool Definition (AOP Rule 2 and FOP Rule 2 revisions) The AOP is defined as the accumulation of hydrocarbons common to and correlating with the interval between the measured depths of 6,920 feet and 7,559 feet in the Alpine No. 3 well. CPAI Application for Pool Rules November 5, 2020 Page 33 of 43 Rule 3. Well Spacing (AOP Rule 3 and FOP Rule 3 revisions) Development wells may not be completed closer than 500 feet to an external CRU boundary line where ownership or land ownership changes. Rule 4. Drilling and Completion Practices (no change from AOP, FOP Rule 4 conformed to match AOP) a. After drilling no more than 50 feet below a casing shoe set in the AOP, a formation integrity test must be conducted. The test pressure need not exceed a predetermined pressure. b. Casing and completion designs may be approved by the AOGCC Commission upon application and presentation of data that demonstrate the designs are appropriate and based upon sound engineering principles. c. Permit(s) to Drill deviated wells within the AOP shall include a plat with a plan view, vertical section, close approach data and a directional program description in lieu of the requirements of 20 AAC 25.050(b). d. A complete petrophysical log suite acceptable to the AOGCC is required from below the conductor to TD for at least one well on each drilling pad in lieu of the requirements of 20 AAC 25.071(a). The AOGCC may, in its discretion, require additional wells on a pad to be logged using a complete petrophysical log suite. e. Reference CO 735.001 for Well Work Operations, Sundry Application and Reporting Requirements, Sundry Matrix. FOP Rule 4. Drilling Waivers (Rule 4 from FOP becomes Rule 4 of AOP) Rule 5. Well Safety Valve Systems (Source: Other Order No. 66, no change from AOP and FOP) Injection wells (excluding disposal injectors) must be equipped with.. a. a double check valve arrangement, or b. a single check valve and a SSV. A subsurface -controlled injection valve or SCSSV satisfies the requirements of a single check valve. Rule 6. Reservoir Pressure Monitoring (no change from AOP, FOP Rule 7 conformed to match AOP) a. Prior to regular injection, an initial pressure survey shall be taken in each injection well. b. A minimum of six bottom -hole pressure surveys shall be measured annually. Bottom -hole pressure surveys in paragraph (a) may fulfill the minimum requirement. c. The reservoir pressure datum shall be 7,000 feet TVD subsea. d. Pressure surveys may consist of stabilized static pressure measurements at bottom -hole or extrapolated from surface, pressure fall -off, pressure buildup, multi -rate tests, drill stem tests, and open - hole formation tests. e. Data and results from pressure surveys shall be reported annually on Form 10-412, Reservoir Pressure Report. All data necessary for analysis of each survey need not be submitted with the Form 10-412 but shall be made available to the AOGCC upon request. f. Results and data from special reservoir pressure monitoring tests or surveys shall also be submitted in accordance with part (e) of this rule. CPAI Application for Pool Rules November 5, 2020 Page 34 of 43 FOP Rule 6. Common Production Facilities and Surface Commingling (Rule 6 from FOP becomes Rule 9 of AOP) Rule 7. Gas -Oil Ratio Exemption (no change from AOP, FOP Rule 8 conformed to match AOP) Wells producing from the AOP are exempt from the gas -oil -ratio limits of 20 AAC 25.240(a) so long as the provisions of 20 AAC 25.240(b) apply. FOP Rule 7. Reservoir Pressure Monitoring (Rule 7 from FOP becomes Rule 6 in AOP) Rule 8. Reservoir Surveillance Report (no change from AOP, FOP Rule 9 conformed to match AOP) A surveillance report is required after one year of regular production and annually thereafter. The report shall include but is not limited to the following: a. Progress of enhanced recovery project(s) implementation and reservoir management summary including engineering and geotechnical parameters. b. Voidage balance by month of produced fluids and injected fluids. c. Analysis of reservoir pressure surveys within the pool. d. Results and where appropriate, analysis of production log surveys, tracer surveys, and observation well surveys. e. Future development plans FOP Rule 8. Gas -Oil Ratio Exemption (Rule 8 from FOP becomes Rule 7 in AOP) Rule 9. Well Testing (no change from AOP, FOP Rule 6 conformed to match AOP) a. All wells must be tested at least twice per month. b. The operator shall optimize stabilization and test duration of each test to obtain a representative test. c. The operator shall record well and field -operating conditions appropriate for maintaining an accurate field production history. d. The operator shall install and maintain test separator meters and gas system meters in conformance with the API Manual of Petroleum Measurement Standards. e. The operator shall maintain records to allow verification of approved production allocation methodologies FOP Rule 9. Annual Reservoir Review (Rule 9 from FOP becomes Rule 8 in AOP) Rule 10. Sustained Casing Pressure (no change from AOP, FOP Rule 10 conformed to match AOP) a. The operator shall conduct and document a pressure test of tubulars and completion equipment in each development well at the time of installation or replacement that is sufficient to demonstrate that planned well operations will not result in failure of well integrity, uncontrolled release of fluid or pressure, or threat to human safety. b. The operator shall monitor each development well daily to check for sustained pressure, except if prevented by extreme weather conditions, emergency situations, or similar unavoidable circumstances. Monitoring results shall be made available for AOGCC inspection. CPAI Application for Pool Rules November 5, 2020 Page 35 of 43 c. The operator shall notify the AOGCC within three working days after the operator identifies a well as having (a) sustained inner annulus pressure that exceeds 2000 psig or (b) sustained outer annulus pressure that exceeds 1000 psig. d. The AOGCC may require the operator to submit in an Application for Sundry Approvals (Form 10-403) a proposal for corrective action or increased surveillance for any development well having sustained pressure that exceeds a limit set out in paragraph c of this rule. The AOGCC may approve the operator's proposal or may require other corrective action or surveillance. The AOGCC may require that corrective action be verified by mechanical integrity testing or other AOGCC approved diagnostic tests. The operator shall give AOGCC sufficient notice of the testing schedule to allow AOGCC to witness the tests. e. If the operator identifies sustained pressure in the inner annulus of a development well that exceeds 45% of the burst pressure rating of the well's production casing for inner annulus pressure, or sustained pressure in the outer annulus that exceeds 45% of the burst pressure rating of the well's surface casing for outer annulus pressure, the operator shall notify the AOGCC within three working days and take corrective action. Unless well conditions require the operator to take emergency corrective action before AOGCC approval can be obtained, the operator shall submit in an Application for Sundry Approvals (Form 10-403) a proposal for corrective action. The AOGCC may approve the operator's proposal or may require other corrective action. The AOGCC may also require that corrective action be verified by mechanical integrity testing or other AOGCC approved diagnostic tests. The operator shall give AOGCC sufficient notice of the testing schedule to allow AOGCC to witness the tests. f. Except as otherwise approved by the AOGCC under paragraph d or e of these rules, before a shut-in well is placed in service, any annulus pressure must be relieved to a sufficient degree (a) that the inner annulus pressure at operating temperature will be below 2000 psig and (b) that the outer annulus pressure at operating temperature will be below 1000 psig. However, a well that is subject to paragraph 3 but not paragraph 5 of these rules may reach an annulus pressure at operating temperature that is described in the operator's notification to the AOGCC under paragraph 3, unless the AOGCC prescribes a different limit. g. For purposes of these rules, "inner annulus" means the space in a well between tubing and production casing; "outer annulus" means the space in a well between production casing and surface casing; "sustained pressure" means pressure that (a) is measurable at the casing head of an annulus, (b) is not caused solely by temperature fluctuations, and (c) is not pressure that has been applied intentionally. FOP Rule 10. Annular Pressures (Rule 10 from FOP becomes Rule 10 of AOP) Rule 11. Administrative Action (no change from AOP, FOP Rule 11 conformed to match AOP) Upon proper application or its own motion, unless notice and a public hearing are otherwise required the AOGCC may administratively waive the requirements of any rule stated above or administratively amend this order as long as the change does not promote waste, jeopardize correlative rights, or compromise ultimate recovery and is based on sound engineering principles. Rule 12. Gas Offtake Rate a. The gas offtake from the Colville River Field ("CRF") must not exceed 7 MMCFPD on a cumulative annualized average basis. b. Natural gas may not be severed from the CRF for any other purpose than to meet ConocoPhillips' contractual obligations of providing the Village of Nuiqsut with natural gas and to support the development in the Greater Moose's Tooth Unit. c. Any new pools that process production at the Alpine Central Facility will be subject to the terms of this rule. CPAI Application for Pool Rules November 5, 2020 Page 36 of 43 List of Acronyms Alaska Oil and Gas Conservation Commission ("AOGCC") Allowable Gas Off Take Rate ("AGOTR") Alpine Central Facility ("ACF") Alpine Oil Pool ("AOP") Blowout prevention equipment ("BOPE") ConocoPhillips Alaska, Inc. ("CPAI") Colville River Unit ("CRU") Colville River Field ("CRF") Colville Delta ("CD") Conservation Order ("CO") Emergency shutdown ("ESD") Enriched water alternating gas ("EWAG") Extended reach drilling ("ERD") Formation Integrity Test ("FIT") Fiord Oil Pool ("FOP") Fiord Nechelik ("FN") Fiord Kuparuk ("FK") Fiord West ("FW') Gas -Oil Ratio ("GOR") Greater Moose's Tooth Unit ("GMTU") Highly radioactive zone ("HRZ") Lower Cretaceous Unconformity ("LCU") Managed pressure drilling ("MPD") Nanuq-Kuparuk ("NK") Original Oil -in -Place ("OOIP") Remote electrical interface module ("REIM") Trans Alaska Pipeline System ("TAPS")
