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Home My WebLink AboutCO 443 DCONSERVATION ORDER 443D Docket Number: CO-20-024 Colville River Field Colville River Unit Alpine Oil Pool 1. November 5, 2020 CPAI's request to amend pool rules for Alpine Oil Pool (confidential pages 37 — 43 held in secure storage) 2. November 20, 2020 Notice of public hearing, affidavit of publication, email distribution, mailings ORDERS STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION 333 West Seventh Avenue Anchorage, Alaska 99501 Re: THE APPLICATION OF ConocoPhillips Alaska, Inc. for amendments to Conservation Order No. 443C to expand the areal and vertical limits of the Colville River Unit, Alpine Oil Pool and to incorporate the existing Fiord Oil Pool into the Alpine Oil Pool. IT APPEARING THAT: Conservation Order No. 443D Docket Number: CO-20-024 Colville River Field Colville River Unit Alpine Oil Pool February 3, 2021 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 the 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 Arctic Slope Regional Corporation. 2. Surface owners of the proposed AOP expansion area are Kuukpik Corporation, the State of Alaska, BLM, 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. CO 443D February 3, 2021 Page 2 of 6 6. Geology a. Stratigraphy The vertically expanded AOP, 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, 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 within the expanded AOP 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 High -Radiation Zone (HRZ) and Kalubik formation varying from 100 to over 230 feet in thickness within 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 established 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.) 8. The gas offtake rate for the Colville River Field (CRF) is set via CO 443C.001 as "[t]he cumulative gas offtake rate from the CRF must not exceed 7 MMCFPD." This is different language than the AOGCC has used in its other orders to establish gas offtake rates, which have been stated as a maximum allowable annual average gas offtake rate. CO 443D February 3, 2021 Page 3 of 6 6920' MD 7559' MD Alpine 3 e,�aa �s5o 7000 7050 7100 7150 7250 7300 7350 7400 74M 75M Sn at Top. Top Kuparuk Kuparuk C ---) Top Alpine Top Nuiqsut Top Nechelik Base Nechelik Forrnotror) Kalubik Fm. Kuparuk River Fm. t-- ILCu . . 1 Miluveach Fm. Kingak Fm. Figure 1 Alpine No. 3 Type Log As currently written the CRF offtake rate lacks the flexibility to accommodate offtake rates which temporarily exceed the defined limit, but would not exceed the annual allowable offtake rate. CONCLUSIONS: 1. Amending CO 443C to expand the geographic boundaries of the AOP and FOP is consistent with the provisions of AS 31.05. AOP expansion will not promote waste, jeopardize correlative rights, or compromise ultimate recovery and is based on sound engineering principles. CO 443D February 3, 2021 Page 4 of 6 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 between these reservoirs through faults and natural fractures demonstrate that these reservoirs are not completely separate and should be considered a single pool. 3. The proposed areal expansion area is reasonable based upon the geologic information contained in the operator's application, exploratory wells drilled in the area, and the records of previous Conservation Orders governing oil pools within the CRU. 4. Revising the gas offtake rate rule to be consistent those established for other fields will provide operational flexibility in the CRF while at the same time ensuring that waste will not occur. NOW, THEREFORE, IT IS ORDERED: This Conservation Order supersedes CO 443C. The findings, conclusions, and administrative records for CO 443C are adopted by reference and incorporated in this decision, except where inconsistent with this Conservation Order. Additionally, CO 569 and its related administrative approvals are rescinded. The administrative record of CO 569 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 TION R3E 1-3: All T10N ME 1-6: All 8-12: All TION R5E 5: NI/2NW1/4, SWIANWIA, & NWIASWIA 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: NW1/4NW1/4 15: W1/2, NEIA, N1/2SE1/4, & SW1/4SE1/4 16-21: All 22: NW1/4 & NW1/4SW1A 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: N W 1 /4N W 1 /4, S 1 /2N W 1 /4, S W 1 /4, & W 1 /2SE 1 /4 CO 443D February 3, 2021 Page 5 of 6 27-35: All 36: SW1/4SW1/4 T13N R4E 25: All 33-36: All T13N R5E 15-22: All 26-36: All Rule 1 Field and Pool Name (Source: CO 443) The field is the Colville River Field. The pool is the Alpine Oil Pool (AOP) Rule 2 Pool Definition (Revised This Order) 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. Rule 3 Well Spacing (Source: CO 443B) Development wells may not be completed closer than 500 feet to an external property line where ownership or land ownership changes. Rule 4 Drilling and Completion Practices (Revised This Order) 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 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 Commission 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 Commission 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 Applications and Reporting Requirements Sundry Matrix. Rule 5 Well Safety Valve Systems (Source: Other Order No. 66) Injection wells (excluding disposal injectors) must be equipped with; a. a double check valve arrangement, or b. a single check valve and a surface safety valve. A subsurface -controlled injection valve or surface controlled subsurface safety valve satisfies the requirements of a single check valve. Rule 6 Reservoir Pressure Monitoring (Source: CO 443A) 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. CO 443D February 3, 2021 Page 6 of 6 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 Commission 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. Rule 7 Gas -Oil Ratio Exemption (Source: C0443A) 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. Rule 8 Reservoir Surveillance Report (Revised This Order) A surveillance report is required by April 1" of each year. 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 Rule 9 Well Testing (Source: CO 443) 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. Rule 10 Sustained Casing Pressure (Source: C0443A) 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 CO 443D February 3, 2021 Page 7 of 6 if prevented by extreme weather conditions, emergency situations, or similar unavoidable circumstances. Monitoring results shall be made available for AOGCC inspection. 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 prig. 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. Rule 11 Administrative Action (Source: C0443B) Upon proper application or its own motion, unless notice and a public hearing are otherwise required the Commission 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. CO 443D February 3, 2021 Page 8 of 6 Rule 12 Gas Offtake Rate (Revised This Order) a. The gas offtake rate from the Colville River Field (CRF) must not exceed 7 MMCFPD on a cumulative annual 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. Done at Anchorage, Alaska and dated February 3, 2021. Digitally signed Jeremy by JeremyW Price M. Price Date: 2021.02.03 15:54:28-09'00' Jeremy M. Price Chair, Commissioner DigltaIly Migned by Daniel T. Daniel T. Seamount, Jr. Seamount, Jr. Date: 2021.02.03 14:48:00-09'00' Daniel T. Seamount, Jr. Commissioner Digitally signed by Jessie L. Jessie L. Chmielowski Chmielowski Date:2021.02.03 15:12:41-09100' Jessie L. Chmielowski Commissioner AND APPEAL NOTICE As provided in AS 31.05.080(a), within 20 days after written notice of the entry of this order or decision, or such 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] co443D Attachments: co443 D.pdf Categories: Yellow Category Please see attached. Jody J. Colombie AOGCC Special Assistant Alaska Oil and Gas Conservation Commission State of Alaska 333 West 7th 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:Hlist.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 S C� INDEXES 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 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 71h 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 ANCHORAGE DAILY NEWS j� C' FIDAVIT OF PUBLICATION `E C 4 0227 ST OF AK/AK OIL AND GAS CONSERVATION COMMISSION NOV 16 2020 333 W. 7TH AVE STE 100, ANCHORAGE, AK 99501 AOGCC 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 individuals. Signed V '�- y `- - I Subscribed and sworn to before me this 13th day of November 2020. o N Notary Public in and for J Tlle'State of Alaska. :D 3 w Third Division } LL a. Anchorage, Alaska O z �aw� MY COMMISSION YXPIRES Q Q 71 2r�'a z0 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 TheapplicationofConocoPhillipsAlaska, 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 A10-20-024 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 7th Avenue Anchorage, AK 99501 (907) 793-1223 ALASKANS SfANU IVGtIHtK 6 FT APART CONFIDENTIALITY NOTICE. This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Conunission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Samantha Carlisle at (907) 793-1223 or Samantha.Carlisle@alaska.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 AFFIDAVIT OF PUBLICATION WITH ATTACHED COPY OF ADVERTISMENT. ADVERTISING ORDER NUMBER A O_oAO_� 1�0�� A FROM: Alaska Oil and Gas Conservation Commission AGENCY CONTACT: Jody Colombie/Samantha Carlisle DATE OF A.O. 11/9/2020 �(907) AGENCY PHONE: 279-1433 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 i DISPLAY i CLASSIFIED i.�- OTHER (Specify below) DESCRIPTION PRICE CO-20-021 and AIO-20-024 Initials of who prepared AO: Alaska Non -Taxable 92-600185 SUBMITtNVOICE SHOWING ADVERTISING ORDER NO., CERTIFIED AFFIDAVIT OF PUBLICATION WITH ATTACHED COPY OF. ADVERTISMENTTO: AOGCC 333 West 7th Avenue Anchorage, Alaska 99501 Page 1 of 1 Total of All Pages $ - 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 gaud 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: Divisions Fiscal/Original AO Copies: Publisher (faxed), Division Fiscal, Receiving Form:02-901 Revised: 11 /9/2020 From: ANC Legal Ads To: Carlisle. Samantha l (CEDy Subject: Re: Please publish AO-08-21-012 Date: Monday, November 9, 2020 12:50:27 PM Attachments: imaae.ona Please see below for the ad confirmation and let me know before 4pm if this is approved to run. Thank you, OrderNumtler 'AM18919 Order Status: Subrnittr.-n CLa5sihCaUOM L.GQaalsru.Public NuziCes Package: Le as ADN Final Cost: 303.82 Referral Code: AO-08-21-012 Payment Typnc Uw 10l WWOI 45 ACCOUNT INFORMATION ST OF AK OIL AND GAS CONSERVATION COMhi1 SSiON 333W..71 yAVE5 tI E % ANCHORAGE. AK 99501 9ti7-a e zal a J* add; ntr STOFAKAKOIL AND GAS CONSERVATION COMMISSION TRANSACTION REPORT Date 12:48 PM Mo,:. N,3 9,1020 Amount: 303.82 ADDITIONAL OPTIONS Afbda it Charge - Digital .a,-5 SCHEDULE FOR AD NUMBER W00189190 Ts: Nov !a 2020 A irnorageDaity News Legals Lis! Misa Legal Advertising lenalads(aadn corn 907-257-4286 1 Anchorage Daily News adn.mm 300 W. 31st Ave. Anchorage, AK 99503 — - raumu neartris STATE OF ALASKA ALASKA. OIL AND GAS CONSERVATION COMMISSION Re:. Omkat Number: CO-20424 And AI0-20-021 Colville River unit, Ainhe and Fiord Oil Pools TheapplitodOn01 COM)COPhlldps:Alaska, Irc.(CPAI) for arrlertdmentS to ConSaf Iofl Order (CO) N0. 433C and Area InjeOt On Older (AIO) No. I SO to expand Ina or" and vertical limits Of the Colville Wet Unit (KIM,.Alpine Oil POd (AOP) and to inCorpOrata the extstitry Hold 41 Pool (FOP) into the AOP OPAi, by letter dated NwantbAt 5, 7020, raguesta the Alaska Oil and Gas Conswattlon Commission AOGCC) anarend CC) No. 433C andAiO No. 18D to expand the affected area of the AOP to include aC that is currently vv"In the CRU but outside of the areal ex=dtthe AOP and expand me verbtat Feints of the Abl? wtdch Would halm me effect of incorpafatitg the POP (governed by CO No. 569 and AtO No. 301 Imp thin, AOP fro AOGCC has toritaMty, Scheduled a "Ic hearing on this application for December 15, 2020, at id w a.m. at 333 wart 7th Avenue, Anchorage, Alaska 99501, to request ft it the tentatively scheduled hednrtg be hen a written request must be tied earth the AOGCC no later man 4'.30 p.m, Ori November 25, 2020. if a necluest for a hearing is not timely tiled, the AoOcc may Coreader the issuance otan CK{fet 1WirK31Ra hdaP6rlg,'T0 loam it the AOGCC end hold the hearng. Cad (907) 279-1433 after November 30, 2=. it a hearing is requested, Me COVID-19 virus may necessitate that tie hearing be hold telephonically. Those desiring to participate or be prasorn at the heading should check with AOGCC the doY before the IRtarig to ascortail Ifthe (rearing will be telophmic. if the thei nng is telapftdMe, On the day of file hearing, thaw deshing to tIQ prosent or participate s6mild call 1-aoo-31s-6338 and, when Iflstrurtild to do so, Omar me Code 14331 10I10wOA ny the a Sign. Because the hearing will start at 10:00 a.m., the phone firms will to avail eble Staring at 9A5 a . Depending On Call vokime, those Calling In may need to make relpoinod aheinpts boom getting through.. In addhOn, will Comments regarding this application may be ,tnlxnnted to the AOGGC, at 333 West 7m Avetxhi,, Anchorage. AlMical"501. Comments trust be received nolauxthan c3op.m. tx1 DoG-+mbCf 14, 2020, oxct�pR tear, if a hearing is itetd, cOnNnents must be received no later Itlion the conclusion of die December 15, 2020 bealing it bet:atse of a disandity spacial accommodations may be needed to comment or attend the hear? Contact U10 AOGCC at (907) 279-1433, n0 later their December A. 2020. ieremy M. Price glair, Commiss orw Published: November 10, 20zti "As of July 8th, we will be charging taratfida L, The standard affidavit Charge is $5, This charge will automatically be inchodei in all cosyquotes unless requested otherwise. Please keep all correspondence for legal advertising addressed IQ legalads®adn.com. to assure best service and tracking. " ATTENTION: AFFIDAVITS ARE MAILED OUT ON TUESDAY-VMDAYS "— On Mon, Nov 9, 2020 at 11:39 AM Carlisle, Samantha J (CED) <sarnantha carlisle4alaskagov> wrote: Thank you! S, mantha Carlisle alas! i ores: rc, OW, (A 11 Ih .., ;. +. ctit n -0 November 5, 2020 Jeremy Price, Chair Alaska Oil and Gas Conservation Commission 333 W. 7th Ave #100 Anchorage, Alaska, 99501-3539 Stephen Thatcher Manager, WNS Development North Slope Development ConocoPhillips Alaska, Inc. P.O. Box100360 Anchorage, AK 99510-0360 phone 907.263.4464 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 ConocoPhillips APPLICATION FOR POOL RULES OF THE ALPINE OIL IZeZeffil 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 ("FN"), 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 FN 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 7 Gas -Oil Ratio Exemption (Source: CO 443C) 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 10 Annular Pressures Yes - update to current AOP Rule 10 wording 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 NEMESIS 0 ■■■■■■■■�■■■■■■■■■■■■■■■■■■■■' ■■■1■■11■■■■■®■■■■■■■■®■`■■■■■■ I■■■®■■■�■■■■■■■■■■+a■■■■1�■Ions ■® -W®■■■■■®■■■■■■ ■ ■■■�■■■■■■■ �■■■■■■■■■!■■■■■■■■■o■■■■■■® �■■®■■■■■■■�■ ■■■■■■■!ri■■■■®■■ �■■■�■■�■■■■■ ■■i■■■■�■ MEN ■® :1■■■■■■■■■■■■■■■■■■■■■■■■■■■■= -1■■1■■■■■■■■■■■■■■■■r■■■■■■�■■■ t®■■■■■■■■■■■■■■■■■■■■■■■■■■■ 1■■ ■■■■■■■■��■■■■■■■■■■■®■■■ 1■1�■■■■■®■■■11■■■�■■■■■■■■■■■■ �■!r �■■®■■■■®■■■®®■■■■■■■�■�■0 �■rr■■■■■■■■■■1®■■■■■■r■■■�■■ _ Figure 1: Existing Alpine and Fiord Oil Pools CPA] Application for Pool Rules November 5, 2020 Page 7 of 43 11432209 145OOM 1475n(M 15nnnnn 1595nM1 155nnnn 157934E c Colville River Unit moo== MM Existing Pools .. • Pool ■■■■■■ �■■ ■■■■■ _ .. Alpine Reservoir ■■■■■■■■■�ii■i■�■ ■!®SIB■101110 ■■■■■ I■■■■■■■■■! ■■■■■® 11■■■®®■■� �■ � �i�l� �■�'��■®■■■■ 1■■O®■■■■ ■ ■ ■■1■©■!■®■■■■® 1■■■■■■■ ■!■■■■■■■■!■,■`i■■■■■■■ 1■■■�■®■� ■�■■■il■■�i®■■■®■■ 1■■■■■®■■■M■■'i■■■i■i�J■■®■■■■■ ■■■■■■■■■®■®®■■■■1®s��■��11 ■■II■■■■■■■■■■■■■■�■■■i�' .®®®e 1432309 140VVVu 141*000 15000UU 1525uuu 155000U 15193481 Figure 2: Existing Alpine and Fiord Pools with Reservoir Outlines CPAI Application for Pool Rules November 5, 2020 Page 8 of 43 Proposed AOP Overview Map 0 � Proposed AOP Reservoir ...-...._...-...."...__.._.... CRU Dnllsites.................................... CoW111eRiver Unit .................._.........._........_..... - — - — - Proposed AOP Boundary ................................. Existing Pools Alpine Oil Pool - .............................. .......... Added Lands AOP Expansion ....................... LL —I I a f CDi t } �yyT �fl1��s. n f Ri { I TI R4E .. - R L — w 4 e� i n �� ( —4 .. , 1 2 n Miles 3 W2309 1450000 1475000 1500000 159S000 155AAAA 1993aA v eawru �—.rol a—uwu ,ornscc !I m Figure 3: Proposed Expanded Alpine Pool Area CPAI Application for Pool Rules November 5, 2020 Page 9 of 43 144VUVV 19i111VW 19/ODUU 10UV000 7UC0000 m o Reservoe Outlines o n tz ; a a ,a o � KupaNK .................................. . pneAandC,,,_ _.,__. _. _._....... •l-___�_,_ a Colville River Al .. ....-L BounOary -- - ProDoseO A()P Resenok OWlne ...._._..........— ProPoseoAOP Boundary ....................._.. x as ]: 1 ,! za �' - PotentlaiWeik 1 AIVoe PotentlatWell-._..........._._....._._.....- McnilikPotentlaiWeB......................_-....._ ]a ]C 1s a KVD PoterDlal Wei ............e .... i —4-- Fiord W"t'W"Paruk t1 SJ s i 1 • _ as 1a ], I t w _ 1 (j Gf&aWr Moos -Tooth i T s 1 I 1 + it t rni 1440000 14500DO 1475000 1500000 i m f s+ is 2e 7 } 0 � ter,, 3G R3 Alpine a lI f 1 1 a 06 ka- TZ r �t s c.E N Figure 4: Individual Reservoirs of the Proposed Expanded Alpine Oil Pool CPAI Application for Pool Rules November 5, 2020 Page 10 of 43 6920' MD 7559' MD Alpine 3 6900 6950 7000 7050 7100 7150 7250 7300 7350 7400 7450 7500 Strot Tops. Formation Kalubik Fm. Top Kuparuk ............_.____.._.__.__ Kuparuk River Fm. Kuparuk C tct� Miluveach Fm. Top Alpine Top Nuiqsut Top Nechelik Base Nechelik Kingak Fm. Figure 5: Defining well, Alpine No. 3, highlighting Pool interval CPAI Application for Pool Rules November 5, 2020 Page 11 of 43 f w O C 7C' t i I T1 O 11 Q. Ln Figure 6: Representative Wells, Alpine No. 1 and Fiord No. 5 CPAI Application for Pool Rules November 5, 2020 Page 12 of 43 c IZ 0 s Figure 7: 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. (Vote 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 r- n C 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 44313). 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 FN 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 INK at CD4 drillsite through faults as evidenced by pressure observations within the Kuparuk at those locations. • Similarly, communication between the FWK and western FN 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 Paoe 16 of 43 a Colville River Unit ............ — - — • — 1O Exploration/ Test Mir ......... .... ...... .... ._._.. Kuparuk Reservoir Oultine .... — — — — Kuparuk C Formation Top ........................... Nechelik Formation Top ............................... e Existing Pools Alpine Oil Pool ............................................. c Fiord Oit Pool ............................................... I � 5 a Fiord Wes Kuparuk WW JCJ✓VU IJ3WUV 1JJblJa HCM5 1 o CD3-118 Fiord Kuparuk CD3-127 \I NE&iEUK 1 RHEA 1 .�, \� CD3-128 3 1 it W E 6 s ` t 1501002 1505000 1510000 1. 1. 0 1520000 0 1Q Miles R1n0 15?ri:id 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 _ I 11� i I 11 7 i •11 i 3 i Y 1 : 4t I ii it Figure 10: Proposed Alpine Pool and Confining Intervals at Nechelik No. 1 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 FIN reservoir in the FW development area is the westward continuation of the Upper Jurassic FIN 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). CPAI 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/bbl PI gravity 30 28-30 36 39-40 37-40 degrees AN Bubble point pressure 2184 1 2395 1 2356 2051 2051 1psig Oil formation volume factor 1.26 1.31 1.43 1.41 1.41 sb/stbo Oil viscosity 0.89 0.83 0.48 0.69 0.69 JCp 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 CPA] 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, FIN and FK reservoirs range from 1500 feet to 2100 feet while spacing for the INK 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 FIN 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, INK, FIN, 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 FIN, 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 FIN 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 14l JUW m Proposed AOP Development Map Proposed AOP Reservoir ........................ _.......... CRUNllsdes...... ................................................. Colville River Unit ....._ ................_...................... _ . _ . _ . 0 oProposedAOP Boundary ................................... Existing Wells NethelikIAlpine/ KuparukWells ... ---- Potential Wells Alpine / Kuparuk Potential Wells ................... Nedlelik Potential Wells .................... .... .... _..._. o- o i \ ! --r ,rib a y a� r :i IJuuvw iJCJvw xJJuvw �orosau . . I — x y Ni $Rll �z l -m _ it R3E it n46 i1'v' n ., —i 3 'h les n •• f1 N>� n a •• —gyp_- i v 1_� J I 14'{7'in9 1dSnntlrl id75nM1 I' Mnnn 1575MM v;rnnnn /574'!dA 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: 0'XRt RWa— Rwa Resistivity of water necessary to make a zone 100% water bearing p 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" %# H-40 Welded Conductor to 114' 10-3t4' 45.60 L-80 Hydril $63 8 OTC Surface Casing 2,504' MD 12,350' TVD @ 42` cemented to surface Mir 9.30 L-80 EUE Upper Compiew: 1) 4-'t:' 12.6 M IST-M Tubing (2 its) XG to 3-•l,` EUE tubing 3) Shallow nipple profile 2) 3-%' x 1' Camco KBMG GLM (xx') wl DV 3) 3-W x 1" Camco KBMG GLM (xx') wi DV 1 4) 3-%* x V Camco KBMG GLM (xx') w4)CK2 pinned for 2500 psi casing to tbg shear 5) SLB BHP Gauge, Encapsulated I -Wire wleannon damps on every joint 6) D nipple 2.81 Z' ID 7) WLEG Lower Comp4e0on. 8) ZXP Liner Top Packer 3 Flexiock Liner Hanger XO 5' Hydril 521 Box X 4-1/1' IBTM pin 9) D ripple 2.75(' )D 10) 4 t!,', 12,60A L-80IST-M Liner w/ bail actuated frac pats every -750' 11) Perforated pup Lfinstt) r 7° 7' 1.5' 1.5' 1.5' 37' 1.5' 7 518" 290 L-60 Hyd 563 3 BTC-M Intermediate Csg to 11,277 MD 17,453' TVD 86" .t • Top Reservoir at.t. - --------- Perforated Perforated pup APQiinaASand ____________________..__________.___.-._-.-t 7446' No i O O O E? O O O O O • i _ _ _ _ _ - _ ..` 4-%" 12.68 L40 Liner 6 314' Hole M wl ball drop free sleeves 18,30T MD 17,542 TVD Figure 12: Alpine Producer Well Schematic CPAI Application for Pool Rules November 5, 2020 Page 28 of 43 � A 3 pO. �N O+W�,qq N x i Oo N x N q n! V N WIA x w C C i � ? a' n 3 3 0 vJ1 �T Q' C� s89} Of O� W 4F � 44[V�� aV pV q0�1 yN 0 N n tt "' A 4" '^ R n Q 9 3 4 Sn 'a m p n W D 0 0 0 2 Z n w Gt S W A m 0 O kki N N e�"py � 8 ��yy x gqitpp (p�(p--pp pLpp � A[ '4 � t.. � n M p7rrtpp L d O' QwQ r �i g1 a _ C 3 v a.i14a,p+a;� 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. CPAI 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 T1ON, R3E Section 1-3 all T1ON, 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, R3E 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. CPA] 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 ("FIN") 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 ("INK") Original Oil -in -Place ("OOIP") Remote electrical interface module ("REIM") Trans Alaska Pipeline System ("TAPS")