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AIO 043
AIO 43 Greater Mooses Tooth Field 1. April 12, 2021 CPAI Application for Rendezvous Oil Pool Injection Order (confidential, held in secure storage: Appendix 1) 2. April 16, 2021 Notice of Hearing, bulk mailing, email list 3. May 25, 2021 Transcript, sign-in sheet, CPAI presentation (confidential, held in secure storage: CPAI Presentation) 4. May 27, 2021 CPA Supplemental Filing Clarifying Pool Area 5. August 2, 2021 CPAI Request for Reconsideration for Rendezvous Oil Pool Findings 1 and 2 6. August 10, 2021 AOGCC grants permission to Request for Reconsideration in part 7. November 19, 2021 Email between AOGCC and CPAI 8. May 26, 2021 CPAI request to reinstate AIO 18A with modifications (AIO 43.001) 9. January 15, 2025 AIO 7 Proposed language change (AIO 43.003) ORDERS STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION 333 West 7th Avenue Anchorage, Alaska 99501 Re: THE APPLICATION OF ConocoPhillips ) Docket Number: AIO-21-004 Alaska, Inc. for an order authorizing underground ) Area Injection Order No. 43 injection of fluids for enhanced oil recovery in the ) Greater Moose's Tooth Unit Greater Moose's Tooth and Bear Tooth Units, ) Bear Tooth Unit Greater Moose's Tooth Field, Rendezvous Oil Pool ) Greater Moose's Tooth Field Greater Moose's Tooth -Rendezvous Oil Pool North Slope Borough, Alaska July 13, 2021 IT APPEARING THAT: 1. By application received April 12, 2021, ConocoPhillips Alaska, Inc. (CPAI), as operator of the Greater Moose's Tooth Unit (GMTU) and the Bear Tooth Unit (BTU), requested an order authorizing underground injection of fluids for enhanced oil recovery purposes in the proposed Rendezvous Oil Pool (ROP). 2. Pursuant to 20 AAC 25.540, the Alaska Oil and Gas Conservation Commission (AOGCC) scheduled a public hearing for May 25, 2021. On April 16, 2021, the AOGCC published notice of that hearing on the State of Alaska's Online Public Notice website and on the AOGCC's website, electronically transmitted the notice to all persons on the AOGCC's email distribution list, and mailed printed copies of the notice to all persons on the AOGCC's mailing distribution list. On April 18, 2021, the notice was also published in the Anchorage Daily News, 3. No public comments on the application were received. 4. The hearing commenced at 10:00 a.m. on May 25, 2021. Testimony was received from representatives of CPAI. The record was closed at the end of the hearing. FINDINGS: Owners and Landowners Surface owners of the ROP are Kuukpik Corporation and the Bureau of Land Management (BLM). Subsurface owners of the ROP are Arctic Slope Regional Corporation and BLM. CPAI is the sole working interest owner of the leased acreage within the proposed Affected Area, as defined below. 2. Operator: CPAI is operator of all the leased acreage in the proposed Affected Area. Affected Area: As currently mapped, the planned Affected Area lies onshore, North Slope, Alaska, within the existing GMTU, BTU, and lands outside of those units (Figure 1, below). The Affected Area for CPAI's proposed ROP lies southwest of the Colville River Unit (CRU). ROP will be the second development entirely within the National Petroleum Reserve —Alaska (NPR -A) to the west and south of the initial development area for the Greater Moose's Tooth -Lookout Oil Pool. 5. A10 43 July 13, 2021 Page 2 of 12 4. Exploration and Delineation History: The ROP was first penetrated in 2000 by CPAI's Rendezvous A exploratory well in Section 24, Township 10 North, Range 1 East, Umiat Meridian (U.M.). Five additional exploratory wells were drilled by CPAI over the next few years. Rendezvous 2, Spark 1 A, and Moose's Tooth C were drilled in 2001. Spark 4 and Carbon 1 were drilled in 2004. In addition, the Altamura 1 exploratory well was drilled by Anadarko Petroleum Corporation in 2002. Rendezvous 2 and Altamura 1 encountered black oil while Rendezvous A, Spark 1 A, Spark 4, and Carbon 1 encountered gas columns with condensate in the gas. ■ ConocoPhillips' , a�Eti r °■ d GMT • m i—_nse �. Rendezvous Oil Pool `v e••;e•ar— Development Plan ° �41 na . > ei! ■ {a' I,., .r.. rR nln , I mine -NI •dOeF= I Colville . I:4W {r1Pl. x!E NA rWnIC I'I {. f11N Rk.I91, Rivet �[ ` ¢I nen R£. C4� UOIf . � nlNuon ■ Goatee IYIY4 ] NbN01E�•iteOSf{ a Tooth Urd{ _ �• am : 4 tooth unit ■I ■i1 r•e•. xnv uu Ian. u.vv a \7 `� I � �� L ■ N,I r' zy P{AWak ■ i•Rn I r \ • •e s•I\��i(• I r.a.a. nded �N n NNUOM=NI 1 R1e, UN !! BuspWelk , •a \ Ezis"WtlIPaN . �� �� •uunii�. -CNr2We11Pbn6 ■ I : —GAR2H WeH Plans �.. { \. No•asls a Proposed Rendezvous Oil Pod -- , n ■ m ". ■ ` ' ❑ now one Reurvor Bamdary- e]RvakpA SudaceASRC SAsuna;e { 11E: ■ .. i r[WA BoA T0441.411.10.11 mnuRi Unkased_ Intlusby UaN n Ina , • .:. x:E.uu IIPRA e Padlopelme "4V� Road A Figure 1. Proposed Affected Area (Source: ConocoPhillips Alaska, Inc.) Pool Identification: As proposed, the ROP encompasses the late Jurassic -aged, shallow marine, Alpine C and D intervals, in ascending stratigraphic order. These intervals unconformably overlie Jurassic -aged Kingak Shale and underlie Cretaceous -aged Miluveach Shale. CPAI proposes the ROP be defined as the accumulation of hydrocarbons common to, and correlating with, the interval in Rendezvous 2 from the measured depth (MD) of 8,229 to 8,393 feet, which is equivalent to -8,104 to -8,268 feet true vertical depth subsea (TVDss). A type log is shown in Figure 2, below. AIO 43 July 13, 2021 Page 3 of 12 6. Geology: a. Stratigraphy: CPAI's proposed ROP consists of late Jurassic -aged sediments that are subdivided into the Alpine C and D intervals. The Alpine C consists of transgressive, shallow marine, lower shoreface sandstone deposits that infilled accommodation space atop the paleo-topographic surface created by incision of the widespread Upper Jurassic Unconformity. Within the proposed development area, the proposed ROP ranges in gross thickness from 164 feet in the Rendezvous 2 well to approximately 35 feet in the Spark 4 well. Reservoir -quality Alpine C sandstones are the current development target. Figure 2. Proposed Rendezvous Oil Pool (Source: ConocoPhillips Alaska, Inc.) AIO 43 July 13, 2021 Page 4 of 12 b. Structure: The overall structure of the proposed pool dips gently to the south. Two sets of early Cretaceous -aged, normal faults have been mapped within the Affected Area using seismic data. Faults of the first set trend west-northwest, are downthrown to the south, and display vertical displacement ranging from 5 to 30 feet. These faults lie near the center of the proposed pool, and they occur north of most of the proposed production and injection wells. The second set of faults trends north-northeast through a portion of the eastern development area. These faults are downthrown to the west and to the east, and they have 30 to 50 feet of vertical displacement. On seismic lines, both sets of faults appear to end in the overlying Miluveach shale and in the underlying Kingak shale. The vertical displacements of all identified faults are less than the thickness of the proposed ROP within the planned development area, so they are not expected to create separate reservoir compartments. c. Trap Configuration and Seals: Well log and seismic information indicate that the proposed pool accumulation is trapped stratigraphically. Deep marine shales of the HRZ, Kalubik, and Miluveach intervals for the upper confining zone, total thickness varies from 680 feet to over 1,600 feet. The Kingak shale provides the lower confining interval, which is approximately 1,700 feet thick in the pool area. d. Reservoir Compartmentalization: Reservoir compartmentalization is not expected in the proposed ROP. e. Permafrost Base: The base of permafrost is approximately -800 to -1,200 feet TVDss in the development area. Reservoir Fluid Contacts: Gas and water contacts have been directly encountered within the ROP. The gas oil contact is estimated to be at -8,108 ft TVDss based on modular formation dynamics testing (MDT) data obtained in the Rendezvous A and Rendezvous 3 wells. Altamura 1 established oil down to -8,450 ft TVDss. None of the exploratory or development wells drilled within the CRU to the east or within the GMTU have encountered an oil -water contact in the Jurassic -aged reservoir. 8. Water Salinity Calculations: In the GMTU, several wells have been logged from surface through the reservoir zone. Calculated water salinity ranges from 13,000 to 31,000 parts per million total dissolved solids throughout the Cretaceous and older stratigraphic sequences. 9. Reservoir Fluid Properties (-8,140 feet TVDss Datum): Initial reservoir pressure Reservoir temperature Gas -oil ratio API gravity Bubble point pressure Oil formation volume factor Oil viscosity Gas formation volume factor 3,802 psia 2070 F 1,270 scf/bbl 37.20 3,815 psia 1.77 rb/stbo 0.232 cp 0.8 bbl/mscf (at saturation pressure) AIO 43 July 13, 2021 Page 5 of 12 10. In -Place and Recoverable Oil Volumes: CPAI's reservoir simulation yields the following ranges for estimated volumes. Oil Rim Hydrocarbon Resources Original Oil in Place (OOIP) Primary Recovery (20% OOIP) Primary + Waterflood + enriched OOIP) Gas Cap Resources Original Gas in Place (OGIP) Condensate Yield Condensate in Place Estimated Volume (MMSTB) 300-460 60-92 gas (35-60% 105-276 1.7to2.8TCF 30-60 STB/MMSCF 51-168 MMSTB Project screening data and costs estimates indicated that a standalone processing facility for the ROP is not feasible and that the only viable option for development at this time is to send unprocessed production from the ROP to the Alpine Central Facility (ACF) in the CRU for processing and sales conditioning. The ACF has no free -gas handling capacity so it is not feasible to attempt to produce the gas cap to recover the condensate reserves. CPAI's plan to maintain a voidage replacement ratio of 1:1 while developing the ROP oil rim should preserve the gas cap and the condensate contained therein for potential future development. II. Reservoir Development Drilling Plan: CPAI currently plans to develop the ROP from MT7 Drill Site (also known as GMT2) utilizing 36 horizontal wells split evenly between producers and injectors. Pilot holes may be drilled before drilling the horizontal laterals. There is potential for an additional 12 extended reach drilling (ERD) wells, again split roughly evenly between producers and injectors. Potential ERD wells would depend, in part, on the drilling results and performance of the initial wells. ERD wells would extend the core development to the east and west. All wells will trend northwest, along the maximum principal stress direction, to improve water flood performance. In the western part of the development area there will be two rows of wells: a northern bank of 14 wells drilled from southeast to northwest and a southern bank of 13 wells drilled northwest to southeast. Producers will alternate with injectors to form a line -drive enhanced oil recovery (EOR) project. In the eastern portion of the development area there will be a single row of 9 currently planned wells drilled from northwest to southeast. Well spacing will be approximately 1,200 feet. The horizontal wellbore length within the reservoir is planned to range from 10,000 to 18,000 feet. Production wells may be hydraulically fractured. Northern wells beneath the ROP gas cap will be drilled near the base of the reservoir to minimize the risk of gas coning. Hydraulic fracturing operations in these wells will be designed to avoid fracking into the gas cap. Development drilling commenced in the second quarter of 2021 and primary drilling is expected to continue through the end of 2024. ERD drilling may occur later. 12. Reservoir Management: CPAI plans to develop the reservoir as a water- and water -alternating -enriched -gas -injection enhanced oil recovery project. Production and injection voidage will be balanced to maintain reservoir pressure at or near the original measured pressure. AIO 43 July 13, 2021 Page 6 of 12 Development will target a 1.0 voidage replacement ratio. Injection water will consist of produced water and water from the Kuparuk seawater treatment plant. 13. Wellbore Construction: Within the planned development area, the base of permafrost is interpreted to be between -800 and -1,200 feet TVDss. Surface casing will be set below the C-5 marker in the Colville Group and cemented to the surface. Wells will be of three or four casing -string designs. Three string wells will have the intermediate casing set near the top of the Alpine C Sand. Four string wells will have intermediate casing set at the top of the HRZ and an intermediate liner set near the top of the Alpine C. The intermediate liner in the four string wells may be drilled conventionally or with steerable drilling liners. Formation integrity tests will be conducted after drilling out of the casing shoes. CPA] expects to develop the reservoir using horizontal wells. Production wells will be competed with uncemented solid liners including pre -perforated pups and fracture sleeves while injectors will be unlined barefoot completions. External swell packers may be used on the producers to isolate out -of -pay excursions and/or fault crossings and to allow for future well intervention optionality. Both injection and production wells will likely be completed with 4'/z inch tubing to minimize hydraulic friction. Artificial lift is planned to be provided by gas lift; other methods may be implemented as the field matures. To facilitate wireline operations, packers in injection wells may be located more than 200 feet MD above the top of the injection interval provided they are not located above the confining zone and have outer casing cement a minimum of 300 feet MD above the planned packer depth. 14. Proposed Injection Fluids: CPA] proposes that the following fluids be authorized for injection into the ROP for FOR purposes: a. Source water from the Kuparuk seawater treatment plant; b. Produced water from all present and yet -to -be -defined oil pools within the GMTU and CRU; c. Enriched hydrocarbon gas (blend of CRU and GMTU lean gas enriched with indigenous heavy gas components); d. Lean gas from the Alpine Central Facility; e. Fluids used during hydraulic stimulation; f. Tracer survey fluids to monitor reservoir performance (chemical, radioactive, etc.); g. Fluids used to improve near wellbore injectivity, (acid or similar treatment); h. Fluids used to seal wellbore intervals that negatively impact recovery efficiency (cement, resin, etc.); i. Fluids associated with freeze protection (diesel, crude, glycol, methanol, etc.); j. Standard oilfield chemicals (corrosion inhibitor, scale inhibitor, etc.); and k. Small amounts of Class II fluids, which will be mixed with the source or produced water including sump fluid, hydrotest fluid, rinsate generated from washing trucks, excess well work fluids, meltwater collected from well cellars. A10 43 July 13, 2021 Page 7 of 12 15. Fluid Compatibility: The primary and miscellaneous fluids listed above are expected to be compatible with the ROP as has been shown by performance in the adjacent and analogous Alpine and Lookout Oil Pools. 16. Scale Deposition: At CRU and GMTU, mixing of seawater and connate formation water in production wells has caused moderate degrees of barium sulfate scale formation. Similar scale formation is possible in ROP producers. Scale inhibition treatments will be performed as necessary. 17. Injection Volumes: ROP injection volume will be managed to maintain the voidage-replacement ratio at approximately 1:1. Fluid -injection rates are anticipated to range between 20 and 50 thousand barrels of water per day and 20 to 70 million cubic feet of gas per day. 18. Injection Pressures: Injection pressure will be managed to prevent the injection -pressure gradient from exceeding 0.81 psi/ft to ensure fractures are not initiated or propagated in the confining intervals. Due to pump and compressor limitations at the ACF and frictional losses within pipelines, the maximum surface injection pressure is anticipated not to exceed 2,650 psi for water and 4,000 psi for gas. 19. Fracture modelling: Fracture -gradient analysis calibrated with rock mechanical properties from core data and leak -off tests indicates the fracture gradient in the Alpine C interval is 0.65 psi/ft. In the upper and lower confining intervals the fracture gradient exceeds 0.85 psi/ft. 20. Formation Water Quality To date, formation water has not been encountered within the ROP. 21. Confinement in Offset Wells: Two exploration wells penetrate the proposed ROP. Rendezvous 2 was drilled in 2001, suspended, re-entered in 2008, fracture stimulated, flow tested, and plugged and abandoned. Rendezvous 3 was drilled in 2014, fracture stimulated, and flow tested. After testing, the well was secured with a downhole tubing plug and kill weight fluid, with freeze protect in the tubing and production casing. Tubing and inner annulus pressure was tested, a back -pressure valve was installed in the tubing hanger, and valve -removal plugs were placed in the wellhead casing valves. This well is currently suspended. 22. Waivers: CPAI requested a waiver of the injection well packer setting depth requirements of 20 AAC 25.412(b), which requires a packer be set within 200 feet MD of the top of the perforated/open injection interval. Due to the highly deviated nature of the proposed injection wells complying with the packer setting depth regulation would preclude accessing the packer/isolation equipment with wire line tools. CPAI requests a waiver to allow the packer/isolation equipment to be set more than 200 feet MD above the injection interval but not above the overlying confining interval and that the outer casing would be cemented with a sufficient volume of cement to ensure a minimum of 300 feet MD of cement is above the packer/isolation equipment setting depth. CONCLUSIONS: An Area Injection Order is necessary for the proposed development of the ROP to allow for enhanced oil recovery injection operations. 2. Reservoir simulation results show that an enriched water -alternating -gas injection project will significantly improve reserves recovery from the pool vs. primary and secondary recovery. AIO 43 July 13,2021 Page 8 of ] 2 3. A waiver of the requirements of 20 AAC 25.412(b) to allow the packer/isolation equipment to be installed more than 200 feet MD above the perforated injection interval will provide for improved wellbore operations and not increase the risk of a loss of containment in the injection wells. 4. Reservoir voidage will be maintained at a replacement ratio of approximately 1:1. 5. Maintaining the sandface injection pressure gradient at or below 0.81 psi/ft will prevent fractures from forming or propagating in the confining intervals. 6. There are no freshwater aquifers in the Affected Area of the LOP. 7. Because the 2018 amendments to 20 AAC 25.556 allow administrative approvals, CPAI's proposed Administrative Action rule is superfluous. NOW THEREFORE IT IS ORDERED: The underground injection of fluids for pressure maintenance and enhanced recovery is authorized in the following area, subject to the following rules and 20 AAC 25, to the extent not superseded by these rules: Affected Area: Umiat Meridian (See Figure 1) Township 8 North, Range 1 East Sections 1-5 - All Section 8 - NEI/4 Section 9 - NI/2 Sections 10-12 - Nl/2 Township 8 North, Range 2 East Section 4 - W1/2 Sections 5-6 - All Section 7 - N 1 /2 Section 8- NW 1 A Township 9 North, Range 1 East Sections 1-3 - All Section 4 - Nl/2, SE1/4 Section 10 - Nl/2, SE1A Sections 11-14 - All Section 15 - NEl/4, Sl/2 Section 21-NE1/4, Sl/2 Sections 22-28 - All Section 29-NEl/4, S1/2 Sections 32-36 - All AIO 43 July 13, 2021 Page 9 of 12 Township 9 North, Range 2 East Sections 1-10 -All Section 11 -N1/2 Section 12-N1/2 Section 15 - WI/2 Sections 16-21 - All Section 22 - W 1/2 Sections 29-31 - All Township 9 North, Range 3 East Section 5 — WI/2 Section 6 — All Section 7 — N 1 /2 Section 8 — NW IA Township 10 North, Range 1 West Sections 1-4—All Section 5 — El/2 Section 8—NEIA Sections 9-12 — All Section 13—N1/2 Section 14—N1/2 Section 15—NI/2 Section 16—NE1/4 Township 10 North, Range 1 East Sections 1-17—A11 Section 18—N1/2 Section 20 — El/2 Sections 21-28 — All Section 29 — E 1 /2 Section 32 — El/2 Sections 33-36 - All Township 10 North, Range 2 East Section 3 —NW 1A, Sl/2 Sections 4-10 — All Section 11—NWl/4, S1/2 Section 12-51/2 Sections 13-36 — All AIO 43 July 13, 2021 Page 10 of 12 Township 10 North, Range 3 East Section 18 — W 1/2 Section 19 — W 1 /2 Section 30 — NW 1 /4, S 1 /2 Section 31 —All Section 32 — S W 1 /4 Township 11 North, Range 1 West Section 25 — S1/2 Section 33 — S 1 /2 Sections 34-36 - All Township 11 North, Range I East Section 9 — SE1/4 Section 10 - S1/2 Section 11 — S W 1 /4 Section 13 — S1/2 Sections 14-16—All Section 17—SE1A Section 19—SE1A Sections 20-29 — All Section 30—NEIA, Sl/2 Sections 31-36 - All Township 11 North, Range 2 East Section 18 — Sl/2 Sections 19-20 — All Section 21 — SW 1/4 Section 27 — SW 1 /4 Sections 28-33 — All Section 34 — W 1 /2 Rule 1 Authorized Injection Strata for Enhanced Recovery Fluids authorized under Rule 3, below, may be injected for the purposes of pressure maintenance and enhanced hydrocarbon recovery within the Affected Area defined above into strata that are common to, and correlate with, the interval between 8,229 feet MD and 8,393 feet MD on the resistivity log recorded in the Rendezvous 2 well. (See Figure 2, above.) Rule 2 Well Construction In lieu of the packer depth requirements under 20 AAC 25.412(b), the packer/isolation equipment depth for injection wells may be located above 200 feet MD from above the top of the perforations/open interval, but shall not be located above the confining zone and shall have outer casing cement volume sufficient to place a minimum of 300 feet MD above the planned packer depth. AIO 43 July 13, 2021 Page I 1 of 12 Rule 3 Authorized Fluids for Iniection for Enhanced Recove Fluids authorized for injection are: a. Source water from the Kuparuk seawater treatment plant; b. Produced water from the Alpine Central Facility (ACF); c. Enriched hydrocarbon gas from the ACF; d. Lean gas from the ACF; e. Tracer survey fluids to monitor reservoir performance; f. Fluids used to improve near wellbore injectivity; g. Fluids used to seal wellbore intervals which negatively impact recovery efficiency; h. Fluids associated with freeze protection; i. Standard oilfield chemicals; and j. Small amounts of Class II fluids, which will be mixed with the source or produced water including sump fluid, hydrotest fluid, rinsate generated from washing trucks, excess well work fluids, and meltwater collected from well cellars. Rule 4 Authorized Iniection Pressure for Enhanced Recove Injection pressures will be managed as not to exceed the maximum injection gradient of 0.81 psi/ft to ensure containment of injected fluids within the defined affected area and injection interval. Rule 5 Monitoring Tubing -Casing Annulus Pressure Inner annulus, outer annulus, and tubing pressure shall be monitored and recorded at least daily, except if prevented by extreme weather condition, emergency situation, or similar unavoidable circumstances for all injection and production wells. The outer annulus pressures of all wells that are not cemented across the ROP and are located within a quarter -mile radius of a ROP injector shall be monitored daily. All monitoring results shall be documented and available for AOGCC inspection. Rule 6 Demonstration of Tubing/Casing Annulus Mechanical Integrity The mechanical integrity of each injection well must be demonstrated before injection begins and before returning a well to service following any workover affecting mechanical integrity. An AOGCC-witnessed mechanical integrity test (MIT) must be performed after injection is commenced for the first time in a well, to be scheduled when injection conditions (temperature, pressure, rate, etc.) have stabilized. Subsequent tests must be performed at least once every four years thereafter. The AOGCC must be notified at least 72 hours in advance to enable a representative to witness an MIT. Unless an alternate means is approved by the AOGCC, mechanical integrity must be demonstrated by a tubing/casing annulus pressure test using a surface pressure of 1,500 psi or 0.25 psi/ft multiplied by the vertical depth of the packer, whichever is greater, that shows stabilizing pressure and does not change more than 10 percent during a 30-minute period. Results of MITs must be readily available for AOGCC inspection. AIO 43 July 13, 2021 Page 12 of 12 Rule 7 Well Interrity and Confinement Whenever any pressure communication, leakage or lack of injection zone isolation is indicated by an injection rate, operating pressure observation, test, survey, log, or any other evidence (including outer annulus pressure monitoring of all wells within a one -quarter mile radius of where the ROP is not cemented), the operator shall notify the AOGCC by the next business day and submit a plan of corrective action on a Form 10-403 for AOGCC approval. The operator shall immediately shut in the well if continued operation would be unsafe or would threaten contamination of freshwater. A monthly report of daily tubing and casing annuli pressures and injection rates must be provided to the AOGCC for all injection wells for which well integrity failure or lack of injection zone isolation is indicated. Rule 8 Notification of Improper Class II Infection Injection of fluids other than those listed in Rule 3 without prior authorization is considered improper Class II injection. Upon discovery of such an event, the operator must immediately notify the AOGCC, provide details of the operation, and propose actions to prevent recurrence. This requirement is in addition to, and does not relieve the operator of any other obligations under, the notification requirements of any other State or Federal agency, regulation, or law. Rule 9 Other Conditions If fluids are found to be fracturing the confining zone or migrating out of the approved injection stratum, the operator must immediately shut in the injection wells and immediately notify the AOGCC. Injection may not be restarted unless approved by the AOGCC. DONE at Anchorage, Alaska and dated July 13, 2021. Jeremy Digitally signed by Jeremy Price Price Date: 2021.07.13 1651:47-08'00' Jeremy M. Price Chair, Commissioner Daniel Digitally signed by Daniel Seamount Seamount 11:2021.07.13 14:34:15-08'00' Daniel T. Seamount, Jr Commissioner Jessie IL. Digitallysignedby Jessie L Chmlelosyskl Chmielowski D01e 2021.07.13 14:41:47-08'00' 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 fime 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. Salazar, Grace (CED) From: Salazar, Grace (CED) <grace.salazar@alaska.gov> Sent: Tuesday, July 13, 2021 5:09 PM To: AOGCC Public Notices Subject: [AOGCC-Public-Notices] AOGCC Area Injection Order No. 43 Attachments: AIO 43.pdf Please see attached. Re: THE APPLICATION OF ConocoPhillips Alaska, Inc. for an order authorizing underground injection of fluids for enhanced oil recovery in the Greater Moose's Tooth and Bear Tooth Units, Greater Moose's Tooth Field, Rendezvous Oil Pool Respectfully, M. Grace Salazar, Special Assistant Alaska Oil and Gas Conservation Commission 333 West 72h Avenue Anchorage, AK 99501 Direct: (907) 793-1221 Email: grace.salazar@alaska.gov https://www.commerce.alaska.gov/web/aogcc/ Docket Number: AIO-21-004 Area Injection Order No. 43 Greater Moose's Tooth Unit Bear Tooth Unit Greater Moose's Tooth Field Greater Moose's Tooth -Rendezvous Oil Pool North Slope Borough, Alaska July 13, 2021 List Name: AOGCC_Public_Notices@list.state.ak.us You subscribed as: grace.salazar@alaska.gov Unsubscribe at: http://list.state.ak.us/mailman/options/aogcc_public_notices/grace.salazar%40alaska.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 �` I�I 2 tq Richard Wagner P.O. Box 60868 Fairbanks, AK 99706 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION 333 West 7th Avenue Anchorage, Alaska 99501 Re: THE APPLICATION OF ConocoPhillips ) Docket Number: AIO-21-004 Alaska, Inc. for an order authorizing underground ) Area Injection Order No. 43 Amended injection of fluids for enhanced oil recovery in the ) Greater Moose's Tooth Unit Greater Moose's Tooth and Bear Tooth Units, ) Bear Tooth Unit Greater Moose's Tooth Field, Rendezvous Oil Pool ) Greater Moose's Tooth Field Greater Moose's Tooth -Rendezvous Oil Pool North Slope Borough, Alaska August 10, 2021 IT APPEARING THAT: 1. By application received April 12, 2021, ConocoPhillips Alaska, Inc. (CPAI), as operator of the Greater Moose's Tooth Unit (GMTU) and the Bear Tooth Unit (BTU), requested an order authorizing underground injection of fluids for enhanced oil recovery purposes in the proposed Rendezvous Oil Pool (ROP). 2. Pursuant to 20 AAC 25.540, the Alaska Oil and Gas Conservation Commission (AOGCC) scheduled a public hearing for May 25, 2021. On April 16, 2021, the AOGCC published notice of that hearing on the State of Alaska's Online Public Notice website and on the AOGCC's website, electronically transmitted the notice to all persons on the AOGCC's email distribution list, and mailed printed copies of the notice to all persons on the AOGCC's mailing distribution list. On April 18, 2021, the notice was also published in the Anchorage Daily News. 3. No public comments on the application were received. 4. The hearing commenced at 10:00 a.m. on May 25, 2021. Testimony was received from representatives of CPAI. 5. The record was closed at the end of the hearing. 6. On July 13, 2021, AOGCC issued Area Injection Order 43. 7. On August 2, 2021, CPAI requested reconsideration. This amended order is entered in response to CPAI's request. FINDINGS: Owners and Landowners Surface owners of the ROP area are Kuukpik Corporation and the Bureau of Land Management (BLM). Subsurface owners of the ROP area are Arctic Slope Regional Corporation and BLM. CPAI is the 100% working interest owner of the leased acreage within the BMTU and Bear Tooth Unit (BTU). There are leases included in the ROP Affected Area that are currently unleased or owned by other operators. Operator. CPAI is operator of the oil and gas leases within the GMTU and BTU. There are leases included in the ROP Affected Area that are currently unleased or operated by others. AIO 43 Amended August 10, 2021 Page 2 of 12 3. Affected Area: As currently mapped, the planned Affected Area lies onshore, North Slope, Alaska, within the existing GMTU, BTU, and lands outside of those units (Figure 1, below). The Affected Area for CPAI's proposed ROP lies southwest of the Colville River Unit (CRU). ROP will be the second development entirely within the National Petroleum Reserve —Alaska (NPR -A) to the west and south of the initial development area for the Greater Moose's Tooth -Lookout Oil Pool. 4. Exploration and Delineation History: The ROP was first penetrated in 2000 by CPAI's Rendezvous A exploratory well in Section 24, Township 10 North, Range 1 East, Umiat Meridian (U.M.). Five additional exploratory wells were drilled by CPAI over the next few years. Rendezvous 2, Spark IA, and Moose's Tooth C were drilled in 2001. Spark 4 and Carbon 1 were drilled in 2004. In addition, the Altamura 1 exploratory well was drilled by Anadarko Petroleum Corporation in 2002. Rendezvous 2 and Ahamura 1 encountered black oil while Rendezvous A, Spark IA, Spark 4, and Carbon 1 encountered gas columns with condensate in the gas. ConowPhillips ■ A4tba GMT e �1. •.. I -__—-+'1{nFu■un.ullr— Rendezvous Oil Pool r Development Plan 5t P +auaa n% Sa1a071 ■ ! come f �, INM1,HIF. UIf mom- � :■IMV.PfEW V1011C' 4 an e{I {./ eflk PY.W! Wea # I a e nla u Uek— le IV■INpe eel ■ . �1eYUa IS ■ W' I.l■I.l ■ Gwen, - . �y 11M1 V1 ' IIWWI RbleY lr�_..TaaM NM_ fl r f PNHW■! - � I I:e':.Nnv uv ;iM1f u.fal ■ �.f v ��:\ �� ■ ifei •r.E it = ! '+' P{AWeBs .H N" _ • l , - l.a I- il;1i1 uwu �(' I ICF,UN .d Suspended Welk • s'Nl! \a\\ ( , �l , : E.WgWNIPatlf __. W171Nd Poens a I \\ Maul G%IT2x Viol Plans r: W _ , • u []NoposM RendexvuusOilPool a a , —_ --_ ¢a MSN'Ipl Boundary :. i j ®%uukp&$0am ASK SaMudge �' I ..f .....one; Q UM Bawdary Udeased Tom' Md.sby Lease ,u ,. ❑CPAI Lease L lax r.11 IIPR-A Pad ppeLru Road Figure 1. Proposed Affected Area (Source: ConocoPhillips Alaska, Inc.) AIO 43 Amended August 10, 2021 Page 3 of 12 Pool Identification: As proposed, the ROP encompasses the late Jurassic -aged, shallow marine, Alpine C and D intervals, in ascending stratigraphic order. These intervals unconformably overlie Jurassic -aged Kingak shale and underlie Cretaceous -aged Miluveach Shale. CPAI proposes the ROP be defined as the accumulation of hydrocarbons common to, and correlating with, the interval in Rendezvous 2 from the measured depth (MD) of 8,229 to 8,393 feet, which is equivalent to -8,104 to -8,268 feet true vertical depth subsea (TVDss). A type log is shown in Figure 2, below. 6. Geoloev: a. Stratigraphy: CPAI's proposed ROP consists of late Jurassic -aged sediments that are subdivided into the Alpine C and D intervals. The Alpine C consists of transgressive, shallow marine, lower shoreface sandstone deposits that infilled accommodation space atop the paleo-topographic surface created by incision of the widespread Upper Jurassic Unconformity. Within the proposed development area, the proposed ROP ranges in gross thickness from 164 feet in the Rendezvous 2 well to approximately 35 feet in the Spark 4 well. Reservoir -quality Alpine C sandstones are the current development target. Figure 2. Proposed Rendezvous Oil Pool (Source: ConocoPhillips Alaska, Inc.) AIO 43 Amended August 10, 2021 Page 4 of 12 b. Structure: The overall structure of the proposed pool dips gently to the south. Two sets of early Cretaceous -aged, normal faults have been mapped within the Affected Area using seismic data. Faults of the first set trend west-northwest, are downthrown to the south, and display vertical displacement ranging from 5 to 30 feet. These faults lie near the center of the proposed pool, and they occur north of most of the proposed production and injection wells. The second set of faults trends north-northeast through a portion of the eastern development area. These faults are downthrown to the west and to the east, and they have 30 to 50 feet of vertical displacement. On seismic lines, both sets of faults appear to end in the overlying Miluveach shale and in the underlying Kingak shale. The vertical displacements of all identified faults are less than the thickness of the proposed ROP within the planned development area, so they are not expected to create separate reservoir compartments. c. Trap Configuration and Seals: Well log and seismic information indicate that the proposed pool accumulation is trapped stratigraphically. Deep marine shales of the HRZ, Kalubik, and Miluveach intervals for the upper confining zone, total thickness varies from 680 feet to over 1,600 feet. The Kingak shale provides the lower confining interval, which is approximately 1,700 feet thick in the pool area. d. Reservoir Compartmentalization: Reservoir compartmentalization is not expected in the proposed ROP. e. Permafrost Base: The base of permafrost is approximately -800 to -1,200 feet TVDss in the development area. Reservoir Fluid Contacts: Only a gas -oil contact has been directly encountered with the ROP. A water contact has not been encountered within the ROP. The gas oil contact is estimated to be at -8,108 ft TVDss based on modular formation dynamics testing (MDT) data obtained in the Rendezvous A and Rendezvous 3 wells. Altamura 1 established oil down to -8,450 ft TVDss. None of the exploratory or development wells drilled within the CRU to the east or within the GMTU have encountered an oil -water contact in the Jurassic -aged reservoir. 8. Water Salinity Calculations: In the GMTU, several wells have been logged from surface through the reservoir zone. Calculated water salinity ranges from 13,000 to 31,000 parts per million total dissolved solids throughout the Cretaceous and older stratigraphic sequences. 9. Reservoir Fluid Properties (-8,140 feet TVDss Datum): Initial reservoir pressure Reservoir temperature Gas -oil ratio API gravity Bubble point pressure Oil formation volume factor Oil viscosity Gas formation volume factor 3,802 psia 2070 F 1,270 scf/bbl 37.20 3,815 psia 1.77 rb/stbo 0.232 cp 0.8 bbl/mscf (at saturation pressure) AIO 43 Amended August 10, 2021 Page 5 of 12 10. In -Place and Recoverable Oil Volumes: CPAI's reservoir simulation yields the following ranges for estimated volumes. Oil Rim Hydrocarbon Resources Original Oil in Place (OOIP) Primary Recovery (20% OOIP) Primary + Waterflood + enriched gas (35-60% OOIP) Gas Cap Resources Original Gas in Place (OGIP) Condensate Yield Condensate in Place Estimated Volume (MMSTB) 300-460 60-92 105-276 1.7 to 2.8 TCF 30-60 STB/MMSCF 51-168 MMSTB Project screening data and costs estimates indicated that a standalone processing facility for the ROP is not feasible and that the only viable option for development at this time is to send unprocessed production from the ROP to the Alpine Central Facility (ACF) in the CRU for processing and sales conditioning. The ACF has no free -gas handling capacity so it is not feasible to attempt to produce the gas cap to recover the condensate reserves. CPAI's plan to maintain a voidage replacement ratio of 1:1 while developing the ROP oil rim should preserve the gas cap and the condensate contained therein for potential future development. IL Reservoir Development Drilling Plan: CPAI currently plans to develop the ROP from MT7 Drill Site (also known as GMT2) utilizing 36 horizontal wells split evenly between producers and injectors. Pilot holes may be drilled before drilling the horizontal laterals. There is potential for an additional 12 extended reach drilling (ERD) wells, again split roughly evenly between producers and injectors. Potential ERD wells would depend, in part, on the drilling results and performance of the initial wells. ERD wells would extend the core development to the east and west. All wells will trend northwest, along the maximum principal stress direction, to improve water flood performance. In the western part of the development area there will be two rows of wells: a northern bank of 14 wells drilled from southeast to northwest and a southern bank of 13 wells drilled northwest to southeast. Producers will alternate with injectors to form a line -drive enhanced oil recovery (EOR) project. In the eastern portion of the development area there will be a single row of 9 currently planned wells drilled from northwest to southeast. Well spacing will be approximately 1,200 feet. The horizontal wellbore length within the reservoir is planned to range from 10,000 to 18,000 feet. Production wells may be hydraulically fractured. Northern wells beneath the ROP gas cap will be drilled near the base of the reservoir to minimize the risk of gas coning. Hydraulic fracturing operations in these wells will be designed to avoid tracking into the gas cap. Development drilling commenced in the second quarter of 2021 and primary drilling is expected to continue through the end of 2024. ERD drilling may occur later. 12. Reservoir Management: CPAI plans to develop the reservoir as a water- and water -alternating -enriched - gas -injection enhanced oil recovery project. Production and injection voidage will be balanced to maintain reservoir pressure at or near the original measured pressure. Development will target a 1.0 voidage replacement ratio. Injection water will consist of produced water and water from the Kuparuk seawater treatment plant. AIO 43 Amended August 10, 2021 Page 6 of 12 13. Wellbore Construction: Within the planned development area, the base of permafrost is interpreted to be between -800 and -1,200 feet TVDss. Surface casing will be set below the K-3 marker in the Nanushuk Group and cemented to the surface. Wells will be of three or four casing -string designs. Three string wells will have the intermediate casing set near the top of the Alpine C Sand. Four string wells will have intermediate casing set at the top of the HRZ and an intermediate liner set near the top of the Alpine C. The intermediate liner in the four string wells may be drilled conventionally or with steerable drilling liners. Formation integrity tests will be conducted after drilling out of the casing shoes. CPAI expects to develop the reservoir using horizontal wells. Production wells will be competed with uncemented solid liners including pre -perforated pups and fracture sleeves while injectors will be unlined barefoot completions. External swell packers may be used on the producers to isolate out -of -pay excursions and/or fault crossings and to allow for future well intervention optionality. Both injection and production wells will likely be completed with 4%z inch tubing to minimize hydraulic friction. Artificial lift is planned to be provided by gas lift; other methods may be implemented as the field matures. To facilitate Mreline operations, packers in injection wells may be located more than 200 feet MD above the top of the injection interval provided they are not located above the confining zone and have outer casing cement a minimum of 300 feet MD above the planned packer depth. 14. Proposed Injection Fluids: CPAI proposes that the following fluids be authorized for injection into the ROP for FOR purposes: a. Source water from the Kuparuk seawater treatment plant; b. Produced water from all present and yet -to -be -defined oil pools within the GMTU and CRU; c. Enriched hydrocarbon gas (blend of CRU and GMTU lean gas enriched with indigenous heavy gas components); d. Lean gas from the Alpine Central Facility; e. Fluids used during hydraulic stimulation; f. Tracer survey fluids to monitor reservoir performance (chemical, radioactive, etc.); g. Fluids used to improve near wellbore injectivity (acid or similar treatment); h. Fluids used to seal wellbore intervals that negatively impact recovery efficiency (cement, resin, etc.); i. Fluids associated with freeze protection (diesel, crude, glycol, methanol, etc.); j. Standard oilfield chemicals (corrosion inhibitor, scale inhibitor, etc.); and k. Small amounts of Class II fluids, which will be mixed with the source or produced water including sump fluid, hydrotest fluid, rinsate generated from washing trucks, excess well work fluids, meltwater collected from well cellars. 15. Fluid Compatibility: The primary and miscellaneous fluids listed above are expected to be compatible with the ROP as has been shown by performance in the adjacent and analogous Alpine and Lookout Oil Pools. 16. Scale Deposition: At CRU and GMTU, mixing of seawater and connate formation water in production wells has caused moderate degrees of barium sulfate scale formation. Similar scale formation is possible in ROP producers. Scale inhibition treatments will be performed as necessary. A10 43 Amended August 10, 2021 Page 7 of 12 17. Injection Volumes: ROP injection volume will be managed to maintain the voidage-replacement ratio at approximately 1:1. Fluid -injection rates are anticipated to range between 20 and 50 thousand barrels of water per day and 20 to 70 million cubic feet of gas per day. 18. Injection Pressures: Injection pressure will be managed to prevent the injection -pressure gradient from exceeding 0.81 psi/ft to ensure fractures are not initiated or propagated in the confining intervals. Due to pump and compressor limitations at the ACF and frictional losses within pipelines, the maximum surface injection pressure is anticipated not to exceed 2,650 psi for water and 4,000 psi for gas. 19. Fracture modelling: Fracture -gradient analysis calibrated with rock mechanical properties from core data and leak -off tests indicates the fracture gradient in the Alpine C interval is 0.65 psi/ft. In the upper and lower confining intervals the fracture gradient exceeds 0.85 psi/ft. 20. Formation Water Ouality: To date, formation water has not been encountered within the ROP. 21. Confinement in Offset Wells: Two exploration wells penetrate the proposed ROP. Rendezvous 2 was drilled in 2001, suspended, re-entered in 2008, fracture stimulated, flow tested, and plugged and abandoned. Rendezvous 3 was drilled in 2014, fracture stimulated, and flow tested. After testing, the well was secured with a downhole tubing plug and kill weight fluid, with freeze protect in the tubing and production casing. Tubing and inner annulus pressure was tested, a back -pressure valve was installed in the tubing hanger, and valve -removal plugs were placed in the wellhead casing valves. This well is currently suspended. 22. Waivers: CPAI requested a waiver of the injection well packer setting depth requirements of 20 AAC 25.412(b), which requires a packer be set within 200 feet MD of the top of the perforated/open injection interval. Due to the highly deviated nature of the proposed injection wells complying with the packer setting depth regulation would preclude accessing the packer/isolation equipment with wire line tools. CPAI requests a waiver to allow the packer/isolation equipment to be set more than 200 feet MD above the injection interval but not above the overlying confining interval and that the outer casing would be cemented with a sufficient volume of cement to ensure a minimum of 300 feet MD of cement is above the packer/isolation equipment setting depth. CONCLUSIONS: 1. An Area Injection Order is necessary for the proposed development of the ROP to allow for enhanced oil recovery injection operations. 2. Reservoir simulation results show that an enriched water-altemating-gas injection project will significantly improve reserves recovery from the pool vs. primary and secondary recovery. 3. A waiver of the requirements of 20 AAC 25.412(b) to allow the packer/isolation equipment to be installed more than 200 feet MD above the perforated injection interval will provide for improved wellbore operations and not increase the risk of a loss of containment in the injection wells. 4. Reservoir voidage will be maintained at a replacement ratio of approximately 1:1. 5. Maintaining the sandface injection pressure gradient at or below 0.81 psi/ft will prevent fractures from forming or propagating in the confining intervals. AIO 43 Amended August 10, 2021 Page 8 of 12 6. There are no freshwater aquifers in the Affected Area of the ROP. Because the 2018 amendments to 20 AAC 25.556 allow administrative approvals, CPAI's proposed Administrative Action rule is superfluous. NOW THEREFORE IT IS ORDERED: The underground injection of fluids for pressure maintenance and enhanced recovery is authorized in the following area, subject to the following rules and 20 AAC 25, to the extent not superseded by these rules: Affected Area: Umiat Meridian (See Figure 1) Township 8 North, Range 1 East Sections 1-5 - All Section 8 - NE 1 A Section 9 - Nl/2 Sections 10-12-N1/2 Township 8 North, Range 2 East Section 4 - W1/2 Sections 5-6 - All Section 7 - N1/2 Section 8 - NW 1A Township 9 North, Range 1 East Sections 1-3 - All Section 4 - NI/2, SETA Section 10 - Nl/2, SE1/4 Sections 11-14 - All Section 15 - NEIA, Sl/2 Section 21 - NEl/4, SI/2 Sections 22-28 - All Section 29 - NEIA, Sl/2 Sections 32-36 - All Township 9 North, Range 2 East Sections 1-10 -All Section 11 -N1/2 Section 12-N1/2 Section 15 - Wl/2 Sections 16-21 - All Section 22 - WI/2 Sections 29-32 - All AIO 43 Amended August 10, 2021 Page 9 of 12 Township 9 North, Range 3 East Section 5 — W 1/2 Section 6 — All Section 7 — N 1 /2 Section 8 — NW 1A Township 10 North, Range 1 West Sections 1-4—All Section 5 — E 1 /2 Section 8 — NE I /4 Sections 9-12 — All Section 13—N1/2 Section 14—N1/2 Section 15—N1/2 Section 16—NEIA Township 10 North, Range I East Sections 1-17 —All Section 18—N1/2 Section 20 — E 1 /2 Sections 21-28 —All Section 29 — El/2 Section 32 — El/2 Sections 33-36 - All Township 10 North, Range 2 East Section 3 —NW 1/4, S1/2 Sections 4-10 — All Section I —NW1/4, S1/2 Section 12-51/2 Sections 13-36 —All Township 10 North, Range 3 East Section 18 — W 1/2 Section 19 — W 1 /2 Section 30—NWl/4, S1/2 Section 31 — All Section 32 — SWIM Township 11 North, Range 1 West Section 25 — S 1/2 Section 33 — S1/2 Sections 34-36 - All AIO 43 Amended August 10, 2021 Page 10 of 12 Township 11 North, Range 1 East Section 9—SEIA Section 10 - SI/2 Section 11 — S W 1 /4 Section 13—S1/2 Sections 14-16—All Section 17—SE1A Section 19—SE1A Sections 20-29 —All Section 30—NEIA, S1/2 Sections 31-36 - All Township 11 North, Range 2 East Section 18 — S1/2 Sections 19-20 — All Section 21 — S W 1 /4 Section 27 — S W 1 /4 Sections 28-33 — All Section 34 — W 1/2 Rule 1 Authorized Infection Strata for Enhanced Recovery Fluids authorized under Rule 3, below, may be injected for the purposes of pressure maintenance and enhanced hydrocarbon recovery within the Affected Area defined above into strata that are common to, and correlate with, the interval between 8,229 feet MD and 8,393 feet MD on the resistivity log recorded in the Rendezvous 2 well. (See Figure 2, above.) Rule 2 Well Construction In lieu of the packer depth requirements under 20 AAC 25.412(b), the packer/isolation equipment depth for injection wells may be located above 200 feet MD from above the top of the perforations/open interval, but shall not be located above the confining zone and shall have outer casing cement volume sufficient to place a minimum of 300 feet MD above the planned packer depth. Rule 3 Authorized Fluids for Infection for Enhanced Recovery Fluids authorized for injection are: a. Source water from the Kuparuk seawater treatment plant; b. Produced water from the Alpine Central Facility (ACF); c. Enriched hydrocarbon gas from the ACF; d. Lean gas from the ACF; e. Tracer survey fluids to monitor reservoir performance; AIO 43 Amended August 10, 2021 Page 11 of 12 f. Fluids used to improve near wellbore injectivity; g. Fluids used to seal wellbore intervals which negatively impact recovery efficiency; It. Fluids associated with freeze protection; i. Standard oilfield chemicals; and j. Small amounts of Class II fluids, which will be mixed with the source or produced water including sump fluid, hydrotest fluid, rinsate generated from washing trucks, excess well work fluids, and meltwater collected from well cellars. Rule 4 Authorized Iniection Pressure for Enhanced Recove Injection pressures will be managed as not to exceed the maximum injection gradient of 0.81 psi/ft to ensure containment of injected fluids within the defined affected area and injection interval. Rule 5 Monitorine Tubine-Casine Annulus Pressure Inner annulus, outer annulus, and tubing pressure shall be monitored and recorded at least daily, except if prevented by extreme weather condition, emergency situation, or similar unavoidable circumstances for all injection and production wells. The outer annulus pressures of all wells that are not cemented across the ROP and are located within a quarter -mile radius of a ROP injector shall be monitored daily. All monitoring results shall be documented and available for AOGCC inspection. Rule 6 Demonstration of Tubine/Casine Annulus Mechanical Inteerity The mechanical integrity of each injection well must be demonstrated before injection begins and before returning a well to service following any workover affecting mechanical integrity. An AOGCC-witnessed mechanical integrity test (MIT) must be performed after injection is commenced for the first time in a well, to be scheduled when injection conditions (temperature, pressure, rate, etc.) have stabilized. Subsequent tests must be performed at least once every four years thereafter. The AOGCC must be notified at least 72 hours in advance to enable a representative to witness an MIT. Unless an alternate means is approved by the AOGCC, mechanical integrity must be demonstrated by a tubing/casing annulus pressure test using a surface pressure of 1,500 psi or 0.25 psi/ft multiplied by the vertical depth of the packer, whichever is greater, that shows stabilizing pressure and does not change more than 10 percent during a 30-minute period. Results of MITs must be readily available for AOGCC inspection. Rule 7 Well Inteerity and Confinement Whenever any pressure communication, leakage or lack of injection zone isolation is indicated by an injection rate, operating pressure observation, test, survey, log, or any other evidence (including outer annulus pressure monitoring of all wells within a one -quarter mile radius of where the ROP is not cemented), the operator shall notify the AOGCC by the next business day and submit a plan of corrective action on a Form 10-403 for AOGCC approval. The operator shall immediately shut in the well if continued operation would be unsafe or would threaten contamination of freshwater. A monthly report of daily tubing and casing annuli pressures and injection rates must be provided to the AOGCC for all injection wells for which well integrity failure or lack of injection zone isolation is indicated. AIO 43A August 10, 2021 Page 12 of 12 Rule 8 Notification of Imuroaer Class II Infection Injection of fluids other than those listed in Rule 3 without prior authorization is considered improper Class II injection. Upon discovery of such an event, the operator must immediately notify the AOGCC, provide details of the operation, and propose actions to prevent recurrence. This requirement is in addition to, and does not relieve the operator of any other obligations under, the notification requirements of any other State or Federal agency, regulation, or law. Rule 9 Other Conditions If fluids are found to be fracturing the confining zone or migrating out of the approved injection stratum, the operator must immediately shut in the injection wells and immediately notify the AOGCC. Injection may not be restarted unless approved by the AOGCC. DONE at Anchorage, Alaska and dated August 10, 2021. Jeremy Difially,igned Y byk..Price Price Date:2021.011.10 1334.14-0 -W Jeremy M. Price Chair, Commissioner Daniel Digaalbyslgned by Daniel Seamoum Seamclunt Dace' 2021.08 usa:xo-WoO'o� Daniel T. Seamount, Jr. Commissioner As provided in As 31.05.090(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 if If the notice was mailed, than 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 parr 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 ran 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. Salazar, Grace (CED) From: Salazar, Grace (CED) <grace.salazar@alaska.gov> Sent: Tuesday, August 10, 2021 2:20 PM To: AOGCC Public Notices Subject: [AOGCC_Public_Notices] AOGCC Amended Orders: Conservation Order No. 793 and Area Injection Order No. 43 Attachments: CO 793A.pdf; AIO 43A.pdf In response to ConocoPhillips Alaska, Inc.'s reconsideration letter, the Alaska Oil and Gas Conservation Commission has amended the following Orders: Conservation Order 793 (attached) Area Injection Order 43 (attached) Respectfully, M. Grace Salazar, Special Assistant Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage, AK 99501 Direct: (907) 793-1221 Email: grace.salazar@alaska.gov https://www.commerce.alaska.gov/web/aogcc/ List Name: AOGCC_Public_Notices@list.state.ak.us You subscribed as: grace.salazar@alaska.gov Unsubscribe at: http:Hlist.state.ak.us/mailman/options/aogcc_public_notices/grace.salazar%40alaska.gov Bernie Karl Gordon Severson Richard Wagner K&K Recycling Inc. 3201 Westmar Cir. P.O. Box 60868 P.O. Box 58055 Anchorage, AK 99508-4336 Fairbanks, AK 99706 Fairbanks, AK 99711 George Vaught, Jr. P.O. Box 13557 Denver, CO 80201-3557 Darwin Waldsmith P.O. Box 39309 Ninilchik, AK 99639 Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.alaska.gov ADMINISTRATIVE APPROVAL AREA INJECTION ORDER NO. 18E.001 AREA INJECTION ORDER NO. 28.009 AREA INJECTION ORDER NO. 35.004 AREA INJECTION ORDER NO. 40.003 AREA INJECTION ORDER NO. 43.001 January 27, 2022 Mr. Stephen Thatcher, Manager North Slope Development ConocoPhillips Alaska, Inc. P.O. Box 100360 Anchorage, AK 99510-0360 Re: Docket Number: AIO-21-010 Request to Reinstate Area Injection Order No. 18.001with Modifications Colville River Unit, Alpine Oil Pool Dear Mr. Thatcher: By letter dated May 26, 2021, ConocoPhillips Alaska, Inc. (CPAI) requested reinstatement of Area Injection Order (AIO) No. 18A.001, which allowed for the mixing of treated effluent with Class II enhanced oil recovery (EOR) fluids for injection into the Alpine Oil Pool (AOP) when the Class I disposal well was unavailable. AIO 18A.001 was rescinded when AIO 18E was issued on March 4, 2021. The Alaska Oil and Gas Conservation Commission (AOGCC) does not reinstate rescinded orders. However, the substance of CPAI’s request is for administrative approval to authorize an additional fluid to be for injection, and AOGCC will treat it as such. Since AIO 18A.001 was issued, four additional pools have been tied into the EOR injection system that serves the AOP. These pools and the AIOs that govern their injection operations are: Pool Governing AIO Nanuq Oil Pool (NOP) AIO 28 Qannik Oil Pool (QOP) AIO 35 Lookout Oil Pool (LOP) AIO 40 Rendezvous Oil Pool (ROP) AIO 43 The NOP and QOP are in the Colville River Unit (CRU), and the LOP and ROP are in the Greater Moose’s Tooth Unit (GMTU). AIO 18E.001, AIO 28.009, AIO 35.004, AIO 40.003, & AIO 43.001 January 27, 2022 Page 2 of 2 There are currently two usable Class I disposal wells (a third Class I well was suspended in 2013) in the CRU, and there are none in the GMTU. Well CRU WD-02 (PTD 198-258) is used for disposal of treated effluent, and CRU CD1-01A (PTD 212-099) is the primary drilling waste disposal well. Having the ability to mix small amounts of treated effluent into the EOR injection stream when using a Class I well is not possible due to required mechanical integrity testing, well damage, well workover operations, or any other incident that may make a well temporarily unusable provides operational flexibility for the remote CRU and GMTU developments. Under the authorization of AIO 18A.001, CPAI has periodically mixed treated effluent with the EOR injection water with no indication of fluid incompatibilities or formation damage that reduces injectivity. In accordance with 20 AAC 25.556(d), the AOGCC hereby amends AIO numbers 18E, 28, 35, 40, and 43 to include the following in the list of authorized fluids in Rule 1 of AIO 18E, Rule 4 of AIO 28, and Rule 3 of AIO 35, 40, and 43: - Treated effluent, subject to the following conditions: o Treated effluent injection may occur when the Class I disposal well for effluent disposal is unavailable; o Treated effluent will be mixed with other EOR injection fluids (seawater or produced water); and o Injection of treated effluent may not exceed 1% by volume of the total annualized average water injection at the Colville River Unit and Greater Moose’s Tooth Unit. DONE at Anchorage, Alaska and dated January 27, 2022. Jeremy M. Price Daniel T. Seamount, Jr. Jessie L. Chmielowski Commissioner, Chair Commissioner Commissioner RECONSIDERATION AND APPEAL NOTICE As provided in AS 31.05.080(a), within 20 days after written notice of the entry of this order or decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration of the matter determined by it. If the notice was mailed, then the period of time shall be 23 days. An application for reconsideration must set out the respect in which the order or decision is believed to be erroneous. The AOGCC shall grant or refuse the application for reconsideration in whole or in part within 10 days after it is filed. Failure to act on it within 10 days is a denial of reconsideration. If the AOGCC denies reconsideration, upon denial, this order or decision and the denial of reconsideration are FINAL and may be appealed to superior court. The appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision denying reconsideration, UNLESS the denial is by inaction, in which case the appeal MUST be filed within 40 days after the date on which the application for reconsideration was filed. If the AOGCC grants an application for reconsideration, this order or decision does not become final. Rather, the order or decision on reconsideration will be the FINAL order or decision of the AOGCC, and it may be appealed to superior court. That appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision on reconsideration. In computing a period of time above, the date of the event or default after which the designated period begins to run is not included in the period; the last day of the period is included, unless it falls on a weekend or state holiday, in which event the period runs until 5:00 p.m. on the next day that does not fall on a weekend or state holiday. Dan Seamount Digitally signed by Dan Seamount Date: 2022.01.27 08:48:32 -09'00' Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2022.01.27 09:05:42 -09'00' Jeremy Price Digitally signed by Jeremy Price Date: 2022.01.27 13:57:28 -09'00' From:Salazar, Grace (OGC) To:AOGCC_Public_Notices Subject:[AOGCC_Public_Notices] Area Injection Order Nos. 18E.001, 28.009, 35.004, 40.003 and 43.001 (ConocoPhillips, Alpine Pool) Date:Thursday, January 27, 2022 2:53:56 PM Attachments:AIO 18E.001_ AIO 28.009_ AIO 35.004_ AIO 40.003_AIO 43.001.pdf The Alaska Oil and Gas Conservation Commission has issued the attached administrative approval amending a number of Area Injection Orders for ConocoPhillips Alaska, Inc.’s Colville River Unit, Alpine Oil Pool. Grace ____________________________________ Respectfully, M. Grace Salazar, Special Assistant Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage, AK 99501 Direct: (907) 793-1221 Email: grace.salazar@alaska.gov https://www.commerce.alaska.gov/web/aogcc/ __________________________________ List Name: AOGCC_Public_Notices@list.state.ak.us You subscribed as: grace.salazar@alaska.gov Unsubscribe at: https://list.state.ak.us/mailman/options/aogcc_public_notices/grace.salazar%40alaska.gov AOGCC 333 W 7th Avenue, Anchorage, AK 99501 TO: BERNIE KARL K&K RECLYCLING, INC. PO BOX 58055 FAIRBANKS, AK 99711 Mailed 1/28/22gs Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.alaska.gov ADMINISTRATIVE APPROVALS AREA INJECTION ORDER 18E.007 AREA INJECTION ORDER 28.010 AREA INJECTION ORDER 35A.001 AREA INJECTION ORDER 40.004 AREA INJECTION ORDER 43.002 Mr. Michael Driscoll WNS Development Supervisor North Slope Development ConocoPhillips Alaska, Inc. P.O Box 100360 Anchorage, AK 99510-0360 Re: Docket Number: AIO-25-013 Making mechanical integrity testing notification requirements consistent across Colville River Unit and Greater Moose’s Tooth Unit pools Colville River Unit, Alpine Oil Pool, Qannik Oil Pool, and Nanuq Oil Pool Greater Moose’s Tooth Unit Lookout Oil Pool and Rendezvous Oil Pool Dear Mr. Driscoll: By letter dated March 17, 2025, ConocoPhillips Alaska, Inc. (CPAI) asked the Alaska Oil and Gas Conservation Commission (AOGCC) to reconsider a portion of Rule 5 of Enhanced Recovery Injection Order No. 9 (ERIO 9) which stated that CPAI was required to provide a minimum of 72- hour notice prior to conducting a required mechanical integrity test. CPAI pointed out that other pools the in Colville River Unit (CRU) and Greater Moose’s Tooth Unit (GMTU) have different minimum notification requirements and that the pools should be consistent and proposed changing the requirement in Rule 5 of ERIO 9 from 72 to 24 hours. The AOGCC agrees the notification requirement should be consistent across all pools in these two units. However, the CRU and GMTU are remote locations in the context of Industry Guidance Bulletins (IGB) 10-01A (Test Witness Notification) and IGB 10-02B (Mechanical Integrity Testing) because the fields do not have a permanent road connection to Alaska’s road system and therefore 48 hours’ notice is appropriate for these fields. On its own motion and in accordance with 20 AAC 25.556(d), the AOGCC hereby amends the Demonstration of Tubing/Casing Annulus Mechanical Integrity rules in the injection orders for the CRU and GMTU fields. AIO 18E.007, 28.010, 35A.001, 40.004, and 43.002 April 24, 2025 Page 2 of 4 Now Therefore it is Ordered: Rule 6 of AIO 18E is amended to read as follows: Rule 6 Demonstration of Tubing/Casing Annulus Mechanical Integrity (Source: Revised This Order for Clarification) The mechanical integrity of each injection well must be demonstrated before injection begins and before returning a well to service following any workover affecting mechanical integrity. An AOGCC-witnessed MIT must be performed after injection is commenced for the first time in a well, to be scheduled when injection conditions (e.g., temperature, pressure, rate, etc.) have stabilized. Subsequent tests must be performed at least once every four years thereafter. For slurry injection wells, the tubing/casing annulus must be tested for mechanical integrity every two years. The AOGCC must be notified at least 48 hours in advance to enable a representative to witness an MIT. Unless an alternate means is approved by the AOGCC, mechanical integrity must be demonstrated by a tubing/casing annulus pressure test using a surface pressure of 1,500 psi or 0.25 psi/ft multiplied by the vertical depth of the packer, whichever is greater, that shows stabilizing pressure and does not change more than 10 percent during a 30-minute period. Results of MITs must be readily available for AOGCC inspection. Rule 6 of AIO 28 is amended to read as follows: Rule 6 Demonstration of Tubing/Casing Annulus Mechanical Integrity A Commission-witnessed mechanical integrity test must be performed after injection is commenced for the first time in a well, to be scheduled when injection conditions (temperature, pressure, rate, etc.) have stabilized. Subsequent tests must be performed at least once every four years thereafter, except at least once every two years in the case of a slurry injection well. The Commission must be notified at least 48 hours in advance to enable a representative to witness mechanical integrity tests. Unless an alternate means is approved by the Commission, mechanical integrity must be demonstrated by a tubing/casing annulus pressure test using a surface pressure of 1,500 psi or 0.25 psi/ft multiplied by the vertical depth of the packer, whichever is greater, that shows stabilizing pressure and does not change more than 10 percent during a 30-minute period. Results of mechanical integrity tests must be readily available for Commission inspection. Rule 6 of AIO 35A is amended to read as follows: Rule 6. Demonstration of Tubing/Casing Annulus Mechanical Integrity (Source: AIO 35) The mechanical integrity of an injection well must be demonstrated before injection begins, and before returning a well to service following a workover affecting mechanical integrity. An AOGCC-witnessed mechanical integrity test must be performed after injection is commenced for the first time in a well, to be scheduled when injection conditions (temperature, pressure, rate, etc.) have stabilized. Subsequent tests must be performed at least once every four years thereafter (except at least once every two years in the case of a slurry injection well). The AOGCC must be notified at least 48 hours in advance to enable a representative to witness mechanical integrity tests. Unless an alternate means is AIO 18E.007, 28.010, 35A.001, 40.004, and 43.002 April 24, 2025 Page 3 of 4 approved by the AOGCC, mechanical integrity must be demonstrated by a tubing/casing annulus pressure test using a surface pressure of 1500 psi or 0.25 psi/ft multiplied by the vertical depth of the packer, whichever is greater, that shows stabilizing pressure and does not change more than 10 percent during a 30-minute period. Results of mechanical integrity tests must be readily available for AOGCC inspection. Rule 6 of AIO 40 is amended to read as follows: Rule 6 Demonstration of Tubing/Casing Annulus Mechanical Integrity The mechanical integrity of each injection well must be demonstrated before injection begins and before returning a well to service following any workover affecting mechanical integrity. An AOGCC-witnessed MIT must be performed after injection is commenced for the first time in a well, to be scheduled when injection conditions (temperature, pressure, rate, etc.) have stabilized. Subsequent tests must be performed at least once every four years thereafter. The AOGCC must be notified at least 48 hours in advance to enable a representative to witness an MIT. Unless an alternate means is approved by the AOGCC, mechanical integrity must be demonstrated by a tubing/casing annulus pressure test using a surface pressure of 1,500 psi or 0.25 psi/ft multiplied by the vertical depth of the packer, whichever is greater, that shows stabilizing pressure and does not change more than 10 percent during a 30-minute period. Results of MITs must be readily available for AOGCC inspection. Rule 6 of AIO 43 is amended to read as follows: Rule 6 Demonstration of Tubing/Casing Annulus Mechanical Integrity The mechanical integrity of each injection well must be demonstrated before injection begins and before returning a well to service following any workover affecting mechanical integrity. An AOGCC-witnessed mechanical integrity test (MIT) must be performed after injection is commenced for the first time in a well, to be scheduled when injection conditions (temperature, pressure, rate, etc.) have stabilized. Subsequent tests must be performed at least once every four years thereafter. The AOGCC must be notified at least 48 hours in advance to enable a representative to witness an MIT. Unless an alternate means is approved by the AOGCC, mechanical integrity must be demonstrated by a tubing/casing annulus pressure test using a surface pressure of 1,500 psi or 0.25 psi/ft multiplied by the vertical depth of the packer, whichever is greater, that shows stabilizing pressure and does not change more than 10 percent during a 30-minute period. Results of MITs must be readily available for AOGCC inspection. DONE at Anchorage, Alaska and dated April 24, 2025. Jessie L. Chmielowski Gregory C. Wilson Commissioner Commissioner Gregory C. Wilson Digitally signed by Gregory C. Wilson Date: 2025.04.23 15:47:29 -08'00' Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2025.04.23 16:29:43 -08'00' AIO 18E.007, 28.010, 35A.001, 40.004, and 43.002 April 24, 2025 Page 4 of 4 RECONSIDERATION AND APPEAL NOTICE As provided in AS 31.05.080(a), within 20 days after written notice of the entry of this order or decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration of the matter determined by it. If the notice was mailed, then the period of time shall be 23 days. An application for reconsideration must set out the respect in which the order or decision is believed to be erroneous. The AOGCC shall grant or refuse the application for reconsideration in whole or in part within 10 days after it is filed. Failure to act on it within 10 days is a denial of reconsideration. If the AOGCC denies reconsideration, upon denial, this order or decision and the denial of reconsideration are FINAL and may be appealed to superior court. The appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision denying reconsideration, UNLESS the denial is by inaction, in which case the appeal MUST be filed within 40 days after the date on which the application for reconsideration was filed. If the AOGCC grants an application for reconsideration, this order or decision does not become final. Rather, the order or decision on reconsideration will be the FINAL order or decision of the AOGCC, and it may be appealed to superior court. That appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision on reconsideration. In computing a period of time above, the date of the event or default after which the designated period begins to run is not included in the period; the last day of the period is included, unless it falls on a weekend or state holiday, in which event the period runs until 5:00 p.m. on the next day that does not fall on a weekend or state holiday. From:Coldiron, Samantha J (OGC) To:AOGCC_Public_Notices Subject:Area Injection Orders 18E.007, 28.010, 35A.001, 40.004, 43.002 (CPAI) Date:Thursday, April 24, 2025 9:25:00 AM Attachments:AIO18E.007_AIO28.010_AIO35A.001_AIO40.004_AIO43.002.pdf Docket Number: AIO-25-013 Making mechanical integrity testing notification requirements consistent across Colville River Unit and Greater Moose’s Tooth Unit pools Colville River Unit, Alpine Oil Pool, Qannik Oil Pool, and Nanuq Oil Pool Greater Moose’s Tooth Unit Lookout Oil Pool and Rendezvous Oil Pool Samantha Coldiron AOGCC Special Assistant Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage, AK 99501 (907) 793-1223 Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.alaska.gov ADMINISTRATIVE APPROVALS AREA INJECTION ORDER NO. 2C.096 AREA INJECTION ORDER NO. 16.009 AREA INJECTION ORDER NO. 18E.008 AREA INJECTION ORDER NO. 28.011 AREA INJECTION ORDER NO. 35A.002 AREA INJECTION ORDER NO. 39A.001 AREA INJECTION ORDER NO. 40.005 AREA INJECTION ORDER NO. 43.003 Greg Hobbs, Regulatory Engineer ConocoPhillips Alaska, Inc. P.O. Box 100360 Anchorage, AK 99510-0360 Re: Docket Number: AIO-25-001 Request to change language of Area Injection Order Rule 7 Well Integrity and Confinement Dear Mr. Hobbs: By letter dated January 15, 2025, ConocoPhillips Alaska, Inc. (CPAI) requested the amendment to Rule 7 of the Area Injection Orders listed below: •AIO 18E: Colville River Field, Colville River Unit, Alpine Oil Pool • AIO 28: Colville River Field, Colville River Unit, Nanuq Oil Pool • AIO 35A: Colville River Field, Colville River Unit, Qannik Oil Pool • AIO 39A: Kuparuk River Field, Kuparuk River Unit, Torok Oil Pool • AIO 40: Greater Moose's Tooth Field, Greater Moose's Tooth Unit, Lookout Oil Pool • AIO 43: Greater Moose's Tooth Field, Greater Moose's Tooth and Bear Tooth Units, Rendezvous Oil Pool The purpose of the amendment is to clarify the appropriate process and current practice when pressure communication, leakage or lack of injection zone isolation is indicated by certain data observed by the operator. CPAIproposed adopting the Rule 7 language from the recently approved AIO 45 Coyote Oil Pool. AIO 2C.096, AIO 16.009, AIO 18E.008, AIO 28.011, AIO 35A.002, AIO 39A.001, AIO 40.005, and AIO 43.003 May 12, 2025 Page 2 of 3 In accordance with 20 AAC 25.556(d), the Alaska Oil and Gas Conservation Commission (AOGCC) hereby GRANTS CPAI’s request to amend Rule 7 of the AIOs listed above. Additionally, on its own motion, and in accordance with 20 AAC 25.556(d), the AOGCC has determined that Rule 7 of the CPAI AIO’s listed below should also be amended for the same reasons. • AIO 2C: Kuparuk River Field, Kuparuk River Unit, Kuparuk River, West Sak, and Tabasco Oil Pools • AIO 16: Kuparuk River Field, Kuparuk River Unit, Tarn Oil Pool Now Therefore it is Ordered: Rule 7 of each of the AIO’s listed is amended to read as follows: Rule 7 Well Integrity and Confinement Whenever an indication of pressure communication, leakage, or lack of injection zone isolation occurs, the operator must notify the AOGCC by the next business day. Such indication may arise from information including but not limited to injection rate, operating pressure observation, test, survey, log, or outer anulus pressure monitoring in wells within one-quarter mile radius of where the applicable defined oil pool is not cemented. If the operator's investigation supports a conclusion of pressure communication, leaking, or lack of injection zone isolation, the operator must submit a corrective action plan to the AOGCC, following the applicable unit sundry matrix order. The operator must shut in any well for which: (a) continued operation would be unsafe, (b) continued operation would threaten contamination of freshwater; or (c) the AOGCC directs the operator to shut in the well. The operator must submit a monthly report of daily tubing and casing annuli pressures and injection rate for injection wells that (a) are subject to administrative approval (AA) to operate; or (b) lack injection zone isolation. DONE at Anchorage, Alaska and dated May 12, 2025. Jessie L. Chmielowski Gregory C. Wilson. Commissioner, Chair Commissioner Gregory C. Wilson Digitally signed by Gregory C. Wilson Date: 2025.05.12 12:12:38 -08'00' Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2025.05.12 13:42:57 -08'00' AIO 2C.096, AIO 16.009, AIO 18E.008, AIO 28.011, AIO 35A.002, AIO 39A.001, AIO 40.005, and AIO 43.003 May 12, 2025 Page 3 of 3 RECONSIDERATION AND APPEAL NOTICE As provided in AS 31.05.080(a), within 20 days after written notice of the entry of this order or decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration of the matter determined by it. If the notice was mailed, then the period of time shall be 23 days. An application for reconsideration must set out the respect in which the order or decision is believed to be erroneous. The AOGCC shall grant or refuse the application for reconsideration in whole or in part within 10 days after it is filed. Failure to act on it within 10 days is a denial of reconsideration. If the AOGCC denies reconsideration, upon denial, this order or decision and the denial of reconsideration are FINAL and may be appealed to superior court. The appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision denying reconsideration, UNLESS the denial is by inaction, in which case the appeal MUST be filed within 40 days after the date on which the application for reconsideration was filed. If the AOGCC grants an application for reconsideration, this order or decision does not become final. Rather, the order or decision on reconsideration will be the FINAL order or decision of the AOGCC, and it may be appealed to superior court. That appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision on reconsideration. In computing a period of time above, the date of the event or default after which the designated period begins to run is not included in the period; the last day of the period is included, unless it falls on a weekend or state holiday, in which event the period runs until 5:00 p.m. on the next day that does not fall on a weekend or state holiday. From:Coldiron, Samantha J (OGC) To:AOGCC_Public_Notices Subject:[AOGCC_Public_Notices] Area Injection Orders Admin Approvals (CPAI) Date:Monday, May 12, 2025 1:54:34 PM Attachments:AIO2C.096, AIO16.009, AIO18E.008, AIO28.011, AIO35A.002, AIO39A.001, AIO40.005, and AIO43.003.pdf Docket Number: AIO-25-001 Request to change language of Area Injection Order Rule 7 Well Integrity and Confinement Samantha Coldiron AOGCC Special Assistant Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage, AK 99501 (907) 793-1223 __________________________________ List Name: AOGCC_Public_Notices@list.state.ak.us You subscribed as: samantha.coldiron@alaska.gov Unsubscribe at: https://list.state.ak.us/mailman/options/aogcc_public_notices/samantha.coldiron%40alaska.go v INDEXES 9 January 15, 2025 VIA E-MAIL DELIVERY Victoria Loepp Senior Petroleum Engineer Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue, Suite 100 Anchorage, Alaska 99501-3572 Subject: Area Injection Order Rule 7 Proposed Language Change Dear Ms. Loepp, ConocoPhillips Alaska Inc. (CPAI) makes this application to amend the Area Injection Orders listed below to clarify the appropriate process and current practice when pressure communication, leakage or lack of injection zone isolation is indicated by certain data observed by the operator. An example of the current area injection order language from the Alpine Area Injection Order (AIO 18E) is as follows: Whenever any pressure communication, leakage or lack of injection zone isolation is indicated by an injection rate, operating pressure observation, test, survey, log, or other evidence, the operator shall, by the next business day, notify the Commission and submit a plan of corrective action on a Form 10-403 for Commission approval. The Operator shall immediately shut in the well if continued operation would be unsafe or would threaten contamination of freshwater, or if so directed by the AOGCC. A monthly report of daily tubing and casing annuli pressures and injection rates must be provided to the AOGCC for all injection wells indicating well integrity failure or lack of injection zone isolation. There are two concerns with the current language. First, the rule requires the filing of a form 10-403 report with the AOGCC on the next business day. This does not represent current practice. Instead, the rule should require the Operator to notify the AOGCC by the next business day and file a report following the applicable AOGCC Sundry matrix only if the Operator’s investigation supports a conclusion of pressure communication, leaking, or lack of injection zone isolation. Second, the current rule requires the submission of daily tubing and casing annuli pressure for all injection wells indicating well integrity failure or lack of injection zone isolation. The current practice is not to submit this information for wells that are shut in. The shut in wells are separately tracked in the annual long-term shut-in wells report to the AOGCC. Greg Hobbs Principal Regulatory Engineer 700 G Street, ATO 1562 Anchorage, AK 99510 (907) 263-4749 (office) Greg.S.Hobbs@conocophillips.com By Samantha Coldiron at 12:09 pm, Jan 15, 2025 2 CPAI proposes the following language from the recent Coyote Oil Pool area injection order to resolve both issues: Whenever an indication of pressure communication, leakage, or lack of injection zone isolation occurs, the operator must notify the AOGCC by the next business day. Such indication may arise from information including but not limited to injection rate, operating pressure observation, test, survey, log, or outer anulus pressure monitoring in wells within one-quarter mile radius of where the COP is not cemented. If the operator’s investigation supports a conclusion of pressure communication, leaking, or lack of injection zone isolation, the operator must submit a corrective action plan to the AOGCC, following the [KRU, CRU or GMTU sundry matrix order as applicable]. The operator must shut in any well for which: (a) continued operation would be unsafe, (b) continued operation would threaten contamination of freshwater; or (c) the AOGCC directs the operator to shut in the well. The operator must submit a monthly report of daily tubing and casing annuli pressures and injection rate for injection wells that (a) are subject to administrative approval (AA) to operate; or (b) lack injection zone isolation. If acceptable, CPAI requests that the rule be modified in the following orders with appropriate reference to the applicable sundry matrix order: x AIO 18E: Colville River Field, Colville River Unit, Alpine Oil Pool x AIO 28: Colville River Field, Colville River Unit, Nanuq Oil Pool x AIO 35A: Colville River Field, Colville River Unit, Qannik Oil Pool x AIO 39A: Kuparuk River Field, Kuparuk River Unit, Torok Oil Pool x AIO 40: Greater Moose’s Tooth Field, Greater Moose’s Tooth Unit, Lookout Oil Pool x AIO 43: Greater Moose’s Tooth Field, Greater Moose’s Tooth and Bear Tooth Units, Rendezvous Oil Pool CPAI appreciates your consideration of this request. Feel free to contact me at 907-263-4749 or greg.s.hobbs@conocophillips.com with any questions. Sincerely, Greg Hobbs Regulatory Engineer ConocoPhillips Alaska, Inc. Digitally signed by Greg Hobbs DN: OU=Regulatory Engineer, O= ConocoPhillips Alaska Wells, CN=Greg Hobbs, E=greg.s.hobbs@ conocophillips.com Reason: I am the author of this document Location: Date: 2025.01.15 10:49:29-09'00' Foxit PDF Editor Version: 13.0.0 Greg Hobbs By Grace Salazar at 1:21 pm, May 26, 2021 7 1 Bell, Abby E (CED) From:Glessner, Dana <Dana.Glessner@conocophillips.com> Sent:Friday, November 19, 2021 10:23 AM To:Roby, David S (OGC) Subject:MT7 commencement of injection operations Dave, we discussed the requirements of 20 AAC 25.420 a few months ago now, is there a specific form that I should complete and submit? We anticipate that MT7 water injection could start as early as 11/29/2021. Thank you, Dana Glessner ConocoPhillips Staff Production Engineer Office: 907‐265‐6478 Dana.Glessner@conocophillips.com THE STATE °fALASKA GOVERNOR h11K1'. DUNL EAVY August 10, 2021 Mr. Stephen Thatcher Manager, WNS Development North Slope Operations and Development ConocoPhillips Alaska, Inc. PO Box 100360 Anchorage, AK 99510 Alaska Oil and Gas Conservation Commission Re: Docket Numbers: CO-21-005 and AIO-21-004 Request for Reconsideration Conservation Order No. 793 and Area Injection Order No. 43 Dear Mr. Tatcher: 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.alaska.gov By letter dated July 29, 2021, ConocoPhillips Alaska, Inc. (CPAI) requested that the Alaska Oil and Gas Conservation Commission (AOGCC) reconsider the recently issued orders referenced above covering operations in the Rendezvous Oil Pool (ROP) in the Greater Moose's Tooth Unit and Bear Tooth Unit. CPAI's request is granted in part. The only rejected proposed change is CPAI's request to remove the requirement to commence enhanced recovery operations withing 12 months of the issuance of the order and instead make the commencement of enhanced recovery operations contingent on "good reservoir management practices." During the hearing, CPAI testified that injection will simultaneously commence with production at facility startup. Since the plan is to begin injection at startup and startup is anticipated to occur later this year, the AOGCC sees no reason to make the change that CPAI has requested. Of course, if conditions change between now and first oil the AOGCC will work with CPAI to revise this requirement if necessary. As such, the AOGCC is rejecting CPAI's proposed change to Rule 7 of Conservation Order No. 793. As stated earlier all other recommendations in CPAI's letter will be adopted and amended orders issued. Sincerely, Jeremy Price Jeremy M. Price Chair. Commissioner Mr. Stephen Tatcher August 10, 2021 Page 2 of 2 RECONSIDERATION AND APPEAL NOTICE As provided in AS 31.05.080(a), within 20 days after written notice of the entry of this order or decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration of the matter determined by it. If the notice was mailed, then the period of time shall be 23 days. An application for reconsideration must set out the respect in which the order or decision is believed to be erroneous. The AOGCC shall grant or refuse the application for reconsideration in whole or in part within 10 days after it is filed. Failure to act on it within 10-days is a denial of reconsideration. If the AOGCC denies reconsideration, upon denial, this order or decision and the denial of reconsideration are FINAL and may be appealed to superior court. The appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision denying reconsideration, UNLESS the denial is by inaction, in which case the appeal MUST be filed within 40 days after the date on which the application for reconsideration was filed. If the AOGCC grants an application for reconsideration, this order or decision does not become final. Rather, the order or decision on reconsideration will be the FINAL order or decision of the AOGCC, and it may be appealed to superior court. That appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision on reconsideration. In computing a period of time above, the date of the event or default after which the designated period begins to not 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. Stephen Thatcher Manager, WNS Development North Slope Development ConocoPhillips Alaska, Inc. P.O. Box 100360 Anchorage, AK 99510-0360 Conocophil I i ps phone 907.263.4464 July 29, 2021 RECEIVED �By Grace Salazar at 1:49 pm, Aug 02, 2021 Alaska Oil and Gas Conservation Commission 333 W. 7th Ave #100 Anchorage, Alaska, 99501-3539 RE: Request for Reconsideration Conservation Order No. 793, Rendezvous Oil Pool, North Slope, AK Area Injection Order No. 43, Rendezvous Oil Pool, North Slope, AK Dear Commissioners: ConocoPhillips Alaska, Inc. ("CPAI") appreciates the Commission's timely issuance of the Rendezvous Oil Pool ("ROP") Conservation Order ("CO") and Area Injection Order ("AIO"). CPAI respectfully requests reconsideration of the following items: • Findings 1 and 2 In the CO and AID state that CPAI is the sole working interest owner and operator of the oil and gas leases within the proposed Affected Area. CPAI is the sole working interest owner in the Greater Moose's Tooth Unit ("GMTU"). However, the area added by the Commission outside of the GMTU includes both unleased acreage and acreage owned by Oil Search. Consequently, CPAI requests that Findings 1 and 2 of both the CO and AIO be revised to the following: Finding 1: Owners and Landowners Surface owners of the ROP area are Kuukpik Corporation and the Bureau of Land Management ("BLM"). Subsurface owners of the ROP area are the Arctic Slope Regional Corporation and BLM. CPAI is the 100% working interest owner of the leased acreage within the GMTU and Bear Tooth Unit ("BTU"). There are leases included in the ROP Affected Area that are currently unleased or owned by other operators. Finding 2: Operator: CPAI is the operator of the oil and gas leases within the GMTU and BTU. There are leases included in the ROP Affected Area that are currently unleased or operated by others. • Finding 7 in both the CO and AIO incorrectly state that both a gas and water contact have been directly encountered within the FOR CPAI requests that Finding 7 be revised consistent with its CO and AIO applications to the following: o Finding 7: Reservoir Fluid Contacts: Only a gas -oil contact has been directly encountered within the ROP. A water contact has not been encountered within the ROP. The gas -oil contact is estimated to be at -8,108 fit TVDss based on modular formation dynamics testing (MDT) data obtained in the Rendezvous A and Rendezvous 3 wells. Altamura 1 established oil down to -8,450 ft TVDss. None of the exploratory or development wells Request for Reconsideration of Conservation Order No. 793 and Area Injection Order No. 43 Page 2 of 3 drilled within the CRU to the east or within the GMTU have encountered oil -water contact in the Jurassic -aged reservoirs. (italicized language added) • Finding 14 of the CO and Finding 13 of the AID, Wellbore Construction, The Orders state that "Surface casing will be set below the C-5 marker in the Colville Group and cemented to surface" which is what was stated in CPAI's original applications. However, during testimony CPAI presented revised information that the "Surface casing will be set below the K-3 marker in the Nanushuk Group and cemented to surface". CPAI requests that Finding 14 of the CO and Finding 13 of the AID be revised to provide: o "Surface casing will beset below the K-3 marker in the Nanushuk Group." (italicized language added) • Page 8 of the CO incorrectly refers to the Lookout Oil Pool ("LOP"). CPAI requests the sentence be revised to state the following: o "Development and operation of the GMTU and BTU Rendezvous Oil Pool..." (italicized language added). • Conclusion 6 in the AID incorrectly refers to the LOP. CPAI requests the sentence be revised to state the following: o There are no freshwater aquifers in the Affected Area of the ROP. (italicized language added). CO Rule 5 requires that a gamma ray and resistivity curve be recorded from base of conductor to total depth. This is a significant departure from regulation 20 AAC 25.071 which only requires that a gamma ray or a resistivity log. Past pool rules have similarly only required gamma ray or resistivity logs. See LOP CO 747 corrected July 24, 2018 Rule 5. Accordingly, CPAI requests that Rule 5 be revised to be consistent with 20 AAC 25.071 and past conservation order decisions allowing for gamma ray or resistivity logs. Although CPAI often runs both logs, some situations only call for one log which results in cost savings with no practical loss in necessary information. • CO Rule 7 requires that "An enhanced recovery operation must be initiated within 12 months of the issuance of this order". CPAI requests reconsideration of the 12 month timeframe, and requests that enhanced recovery operations be tied to good reservoir management practices and operational feasibility. Consequently, CPAI requests the following revised language for Rule 7: o Following sustained production from the ROP, to the extent operationally feasible, an enhanced recovery operation will be initiated once good reservoir management practices dictate the commencement of enhanced recovery operations. • In both the CO and AID, the land description appears to be incomplete. Consistent with CPAI's applications, CPAI requests the addition of the following lands inside the GMTU into the ROP in both the CO and AID: Township Range Sections T9N R2E 32: All Request for Reconsideration of Conservation Order No. 793 and Area Injection Order No. 43 Page 3 of 3 Please contact Dana Glessner (265-6478, glessd@conocophillips.com) if you have questions or would like to discuss this request for reconsideration. Regards, ^ , `U Stephen Thatcher Manager, WNS Development North Slope Operations and Development Conocu►Phillips May 27, 2021 Alaska Oil and Gas Conservation Commission 333 W. 7th Ave #100 Anchorage, Alaska, 99501-3539 Stephen Thatcher Manager, WNS Development North Slope Development ConocoPhiliips Alaska, Inc. P.O. Box 100360 Anchorage, AK 99510-0360 phone 907.263.4464 RE: Supplement to Clarify Potential Expanded Pool Area For the Rendezvous Conservation Order and Area Injection Order Applications North Slope, AK Dear Commissioners: This letter is provided to clarify the scope of the Rendezvous Oil Pool (ROP) boundary if the Commission elects to extend the ROP to lands not leased by ConocoPhillips Alaska, Inc. (CPAI) as suggested by questions from the Commissioners at the hearing on May 25, 2021. As CPAI stated at the hearing, CPAI does not object to the ROP boundary being extend to the south. The legal description of the additional lands to the south is as follows: Township Range Sections 1-3: All T8N R1E 10-12: 141/2 4: W1/2 5-6: All 7: N1/2 T8N R2E 8: NW1/4 27: NW1/4 28: W1/2, NE1/4 T911 R2E 33: W1/2 Supplement to Rendezvous Conservation Order and Area Injection Order Applications Page 2 of 3 Attachment 1 to this letter is a map showing the pool boundary expanded to the south. Please contact Dana Glessner (265-6478, glessd@conocophillips.com) if you have questions or would like to discuss this request. Regards, Tw-LL Stephen Thatcher Manager, WNS Development North Slope Development Supplement to Rendezvous Conservation Order and Area Injection Order Applications Page 3 of 3 Attachment t ConocoPhillips—d��,,'" " •'"' IfFSS <•N GMT 2 Rendezvous Oil Pool -' t (� % /-• - �Lns<x! 'J YLWiI �rYA1R �YTin/ Development Plan W712021 t ! °0101�F -' coi d WF>PY caiville it Irt !11 !11 kVt'.. �. �tfl I W�j•,l W ! '■ unit N001, . < : it •i ..1� a« i111Y"ea � • •I rvwY z , nmr'FS✓e—�' y '�i .mooses Tooth Unit Bear i �`/� Hall Tooth Unit • • _ r a a - un ura4 , ,. ux1 I u6. w AZ WENW i h Ti y} fit},✓ Y1 �� j e Vu •—t...i. 4 �. ) "1 1"1.Y.ILY�•u"F• '�- PAA We6z '�tat' i{t i. Yea uu j%la % nuuUee�Xl RE Ed Uta t t Pr Suspended Weih • I tt�•' tl a uun� ENIsboi Well Polh t I ... W12Well Plans • WIFE.1 — GMT2K Wei Plans Ropo:•d W nd•zvous Oil Pool Q Reaenaireountlwy a , • \ ... YiY. " F ©K"ukpa Surfau ASRG Subawtau • Y+4.. •uF"u l a,�!Unil Bounds? Unleased .� Ind VFM Los" [� CPAI t<az< V\I ID I K, VV 1 �LE,u" Iit'UA - , 5-, • Pad •� _ .__I . Road AOGCCPUBLICHEARING 5/25/2021 ITMO: APPLICATION OF CONOCOPHILLIPS AK, INC. DocketNo. CO-21-005 ALASKA OIL AND GAS CONSERVATION COMMISSION In the Matter of The application of ConocoPhillips Alaska, Inc., (CPAI) for order establishing pool rules and an area injection order for the proposed Rendezvous Oil Pool in the Greater Moose's Tooth Unit. Docket No. CO-21-005; AIO-21-004 PUBLIC HEARING May 25, 2021 10:00 a.m. BEFORE: Jeremy Price, Chairman Jessie Chmielowski, Commissioner Daniel T. Seamount, Commissioner Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2, Anch. AK 99501 Fax 907-243-1473 Email: sahile@gci.net AOGCC PUBLIC HEARING 5125/2021 ITMO: APPLICATION OF CONOCOPHILLIPS AK, INC. DocketNo.CO-21-005 Page 2 1 1 TABLE OF CONTENTS 2 Opening remarks by Chairman Price 03 3 Testimony by Ms. Glessner 08 4 Testimony by Mr. Timmerman 1.4 5 Testimony by Ms. Anderson 28 6 Testimony by Mr. Versteeg 29 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email: sahtle@gci.net AOGCCPUBLICHEARING 5/25/2021 ITMO: APPLICATION OF CONOCOPHILLIPS AK, INC. DocketNo. CO-21-005 Page 3 1 P R O C E E D I N G S 2 (On record - 10:00 a.m.) 3 CHAIRMAN PRICE: Good morning, we're now on 4 record. It's approximately 10:00 a.m., Tuesday, May 5 25th, 2021. Today's hearing is being held by Cisco 6 WebEx telephonically and in person here at the AOGCC 7 offices located at 333 West Seventh Avenue, Anchorage, 8 Alaska. Due to technical reasons we are not using the 9 call in number that was provided in the original public 10 notice. A revised public notice with the correct call 11 in number was posted on the AOGCC website and was sent 12 out via email to those who subscribe to AOGCC public 13 notices listserve. For those on the phone, you can 14 press star six to unmute if you need to speak -- I'm 15 getting a little echo there -- for those on Cisco WebEx 16 Video toggle over to the microphone icon to unmute. 17 Please be mindful of any background noise and make sure 18 you are muted when you're not testifying or addressing 19 the Commission. 20 Computer Matrix will be recording the hearing. 21 Upon completion and preparation of the transcripts, 22 persons desiring a copy will be able to obtain by 23 contacting Computer Matrix. 24 If you require any special accommodation, 25 please contact Grace Salazar sitting in the room with Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net AOGCCPUBLIC HEARING 5/25/2021 ITMO: APPLICATION OF CONOCOPHILLIPS AK, INC. DocketNo. CO-21-005 Page 4 1 us. She can be reached at 793-1221. For those of you 2 who don't know, she is the new Jodie Columbie. 3 At this time I'll start introducing the bench. 4 To my left is Commissioner Dan Seamount and to my right 5 is Commissioner Jessie Chmielowski. 6 This is a public hearing on Docket No.'s CO-21- 7 005 and AIO-21-004. ConocoPhillips application for an 8 order establishing pool rules and an area injection 9 order for the proposed Rendezvous Oil Pool in the 10 Greater Moose's Tooth Unit. 11 This hearing is being held in accordance with 12 Alaska Statute 44.62 and 20 AAC 25.540 of the Alaska 13 Administrative Code. The notice of this hearing was 14 published in the Anchorage Daily News on April 16th, 15 2021. It was also posted on the state of Alaska online 16 notices website and the AOGCC's website. The AOGCC did 17 not receive any written comment on this matter prior to 18 this hearing. If there is anyone on the phone that 19 would like to make a public comment at the hearing 20 today, please make it known now. I believe the phones 21 are muted so if we can't hear you, try dialing star 22 six, and make it known if you'd like to make a public 23 comment at this hearing. Please let us know now. 24 (No comments) 25 CHAIRMAN PRICE: Hearing none. I'll ask Computer Matrix, LLC Phone: 907-243-0669 135 Christensen Dr., Ste. 2, Anch. AK 99501 Fax: 907-243-1473 Email: sahileegci.net AOGCC PUBLIC HEARING 5/25/2021 ITMO: APPLICATION OF CONOCOPHILLIPS AK, INC. DocketNo.CO-21-005 Page 5 1 Commissioner Seamount, any comments. 2 COMMISSIONER SEAMOUNT: I have none at this 3 time. 4 CHAIRMAN PRICE: Commissioner Chmielowski, any 5 comments. 6 COMMISSIONER CHMIELOWSKI: No. Thank you. 7 CHAIRMAN PRICE: Okay. Folks, are we going to 8 have all four of you testifying today. Okay. Can we 9 fist have you raise your right arms, right hands and 10 we'll swear you in. 11 (Oath administered) 12 IN UNISON: Yes. 13 CHAIRMAN PRICE: Okay. Let's put yourselves 14 all on the record for the record. Who are we going to 15 start with with the presentation? 16 MS. GLESSNER: Good morning. I'm Dana 17 Glessner. If we could go to Slide 2 for our 18 introductions is what I would like to start with. 19 CHAIRMAN PRICE: Sure. Okay. Go ahead to 20 Slide 2, Grace. 21 MS. GLESSNER: Okay. Good morning. I am Dana 22 Glessner. I am a production engineer with 23 ConocoPhillips Alaska. I have a bachelors of Petroleum 24 Engineering from West Virginia University. I have 20 25 years of industry experience. Previously worked for Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr, Ste. 2., Arch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net AOGCC PUBLIC HEARING 5/25/2021 ITMO: APPLICATION OF CONOCOPHILLIPS AK, INC. DocketNo.CO-21-005 Page 6 1 Chevron in California and Alaska. And I've spent the 2 last 12 years with ConocoPhillips working Kuparuk and 3 Alpine fields on the Slope. And I wish to be accepted 4 as an expert witness in production engineering for 5 today's hearing. 6 CHAIRMAN PRICE: Understood. We'll recognize 7 that. 8 MR. TIMMERMAN: Good morning. My name's 9 Garrett Timmerman. I'm a development geologist with 10 ConocoPhillips Alaska. I have a bachelors in Science 11 from Michigan Technological University. Masters in 12 Science from the University of Montana. I've got 15 13 years of industry experience, one of those here working 14 the Alpine fields in Alaska. I wish to be recognized 15 as an expert witness in geology. 16 CHAIRMAN PRICE: Okay. 17 MS. ANDERSON: My name is Anderson. I have a 18 bachelors degree from the University of Missouri, Rolla 19 in Chemical Engineering. I have 22 years experience 20 with ConocoPhillips, primarily in the Alpine field. I 21 wish to be -- request to be a witness. 22 MR. VERSTEEG: Good morning. My name's Joe 23 Versteeg. I'm a reservoir engineer for ConocoPhillips. 24 I have a BS in Petroleum Engineering from the 25 University of Alaska -Fairbanks. I have 24 years of Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax 907-243-1473 Email: sahile@gci.net AOGCC PUBLIC HEARING 5/25/2021 ITMO: APPLICATION OF CONOCOPHILLIPS AK, INC. DocketNo. CO-21-005 Page 7 1 industry experience and 21 years in Alaska working 2 Prudhoe, Alpine and Kuparuk fields. And I'd like to be 3 acknowledged as an expert witness. 4 CHAIRMAN PRICE: Any questions for the 5 witnesses, any objections to the recognition of the 6 four witnesses to being expert? 7 COMMISSIONER SEAMOUNT: I have a question for 8 Ms. Glessner, and it has nothing to do with the outcome 9 of this hearing. But where did you work for Chevron in 10 California? 11 MS. GLESSNER: I worked in Bakersfield. 12 COMMISSIONER SEAMOUNT: Oh, so did I, eight 13 years. 14 MS. GLESSNER: Yep, Steam -- heavy oil, 15 steamflood, yep. 16 COMMISSIONER SEAMOUNT: Really tight well 17 spacing there. 18 MS. GLESSNER: Very small, tight, yes. 19 COMMISSIONER SEAMOUNT: I have no objections to 20 any of them. 21 COMMISSIONER CHMIELOWSKI: No questions. No 22 objections. Thanks. 23 CHAIRMAN PRICE: Folks, I will kind of 24 foreshadow this hearing. I think we -- after the 25 conclusion of the public presentation, we do expect at Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2, Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net AOGCC PUBLIC HEARING 5/252021 ITMO: APPLICATION OF CONOCOPHILLIPS AK, INC. DocketNo. CO-21-005 Page 8 1 that point we may go into a confidential portion of the 2 hearing and we'll talk more at that point. But I 3 wanted to flag it for you, for that possibility at that 4 time, we would like one of you to kind of explain on 5 the record for the public why you'd like this 6 information that was submitted to be kept confidential, 7 to the extent that you can, without saying anything 8 that you shouldn't. So please be prepared for that at 9 the end of the public presentation. 10 Who would like to go first. Okay. 11 MS. GLESSNER: Good morning. This is Dana 12 Glessner again. I'm currently on Slide 3. First I 13 would like to thank the Commissioners today for helping 14 us establish these orders, so thank you for that. And 15 on Slide 3 I am showing our planned testimony and 16 outline of today's presentation. We would like to 17 cover, or will cover the conservation and area 18 injection orders together in this presentation. I will 19 mention on the geology side, we do have a non- 20 confidential overview in the main presentation and then 21 we are ready to show confidential at the end, so we do 22 have that section when we get there. 23 So first I'll move on to Slide No. 4 to talk 24 about the location and history. So over here on the 25 righthand of the slide I have a map of the Alpine field Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax 907-243-1473 Email: sahile@gci.net AOGCCPUBLICHEARING 525/2021 ITMO: APPLICATION OF CONOCOPHILLIPS AK, INC. DocketNo. CO-21-005 Page 9 1 area and the orange dots indicate drill sites. The 2 brown lines are roads. The blue lines are outlining 3 the units. And the red dotted line indicates the NPR -A 4 boundary. The Rendezvous Pool is ConocoPhillips second 5 development in the Greater Moose's Tooth Unit and we 6 refer to the project as GMT2. It is 8 miles southwest 7 of GMT1, which is Lookout Oil Pool Like the existing 8 six drill sites at Alpine, GMT2 will use the existing 9 infrastructure and production will be routed back to 10 the Alpine Central Facility for final production 11 processing. One difference in the Greater Moose's 12 Tooth, for GMT2 and 1, we will measure production, oil 13 and gas, at the drill site for custody transfer 14 purposes before it leaves the unit and be -- before it 15 leaves the drill site. On the bottom lefthand slide I 16 have a brief history of the project. Exploration 17 seismic began from 1998 to 2000 with exploration 18 drilling following from 2000 through 2004. Most 19 notably to the GMT2 project, the Rendezvous 2 well was 20 drilled and flow tested in 2008, which confirmed the 21 oil discovery for the GMT2 project. In 2014 a second 22 exploration well, Rendezvous 3 was also drilled and 23 flow tested in the development area. From 2017 to 2020 24 Conoco worked to acquire, process and interpret new 25 seismic data. In 2018 GMT2 was internally sanctioned Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email: sahileegci.net AOGCC PUBLIC HEARING 5/2512021 ITMO: APPLICATION OF CONOCOPHILLIPS AK, INC. DocketNo. CO-21-005 Page 10 1 for execution by ConocoPhillips and we started our 2 first two construction seasons in 2019 and 2020 3 building roads, drill site, pipelines. And this year 4 we are working to finalize the installation of the 5 facilities and commission the pipelines. We do expect 6 first production and injection in the fourth quarter of 7 this year and we actually just did spud our first well 8 on April 27th. 9 Next I'll move on to Slide No. 5 to talk about 10 the ownership and pool boundary. ConocoPhillips is a 11 100 percent owner and operator of the Rendezvous Pool. 12 The surface owners are BLM and Kuukpik, both whom were 13 notified per the area injection order requirements. 14 The subsurface owners are the ASRC and BLM. And for 15 the proposed pool boundary, this is from our 16 application, that I have the map on the following 17 slide, that the proposed boundary is approximately one 18 full quarter section beyond the largest estimate of the 19 Alpine sand presence to ensure appropriate coverage of 20 the reservoir held by the GMT2 working interest owners. 21 And the pool boundary does terminate in the south and 22 southeast at the GMTU boundary and it does include 23 sections not currently held by the working interest 24 owners. 25 So next on to Slide 6. This is a map showing Computer Matrix, LLC Phone: 907-243-0669 135 Christensen Dr., Ste. 2., Anch, AK 99501 Fax: 907-243-1473 Email: sahile@gci.net gci.net AOGCCPUBLICHEARING 5/25/2021 ITMO: APPLICATION OF CONOCOPHILLIPS AK, INC. DocketNo. CO-21-005 Page 11 1 the proposed pool boundary. The lightly shaded purple 2 section, also outlined with a dark purple line indicate 3 the extent of the proposed pool boundary. The outline 4 of the reservoir is also a light purple line inside the 5 edge of the pool boundary. Here, again, orange dots 6 indicate drill sites. Brown is a road. Green indicate 7 pipelines. You can see the unit boundaries as the 8 dotted black lines. Bear Tooth Unit is on the west of 9 the Greater Moose's Tooth Unit and Colville River Unit 10 is on the east. You can also see exploration wells in 11 the area and also Lookout Development, which is to the 12 east of the pool. Our development wells are the 13 orange. You can see the well sticks in the southern 14 part here of the pool. The orange wells are our 15 initial planned 36 development -- 36 well development. 16 And then we have an additional 12 wells which are 17 extended reach drilling targets that are indicated by 18 brown here. And you will notice that our development 19 is focused in the southern area of the pool. This is 20 because Rendezvous does have a gas cap that is more 21 commonly known as Spark. And currently we are just 22 focused on oil rim development and production for GMT2 23 so that is why the wells are near the southern part of 24 the pool. 25 Okay, next on to Slide 7. Overview of the Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2, Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net AOGCCPUBLICHEARING 5/2512021 ITMO: APPLICATION OF CONOCOPHILLIPS AK, INC. DocketNo. CO-21-005 Page 12 1 mechanical condition of the existing wells in the pool. 2 We do have nine wells that are plugged and abandoned 3 and there are two that are suspended. Of the two, 4 Rendezvous 3 is the only well that would be within one 5 fourth quarter mile of any development well. 6 COMMISSIONER CHMIELOWSKI: Ms. Glessner, what 7 is the status of Tinmiaq 6, Tinmiaq 15, and Fish Creek 8 Test 1? Those are on your map in the previous slide. 9 MS. GLESSNER: Tinmiaq 6 and 15 here on the 10 west and then Fish Creek Test 1. And, Garrett, please 11 correct me if I'm wrong. The Tinmiaq 6 and 15 wells do 12 not penetrate the pool. 13 MR. TIMMERMAN: Yeah, correct. Those are for 14 the Brooking targets and they don't go to the Jurassic. 15 COMMISSIONER CHMIELOWSKI: And are they 16 suspended? 17 MS. GLESSNER: I am not sure of that answer. 18 COMMISSIONER CHMIELOWSKI: Okay. 19 MS. GLESSNER: And then the Fish Creek Test 1 20 is actually a BLM well. 21 COMMISSIONER CHMIELOWSKI: Right, it was a 22 Legacy well. Was that plugged and abandoned recently? 23 MS. GLESSNER: I do not believe it was. 24 COMMISSIONER CHMIELOWSKI: No. So it's still 25 there? Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax 907-243-1473 Email: sahilecgci.net AOGCC PUBLIC HEARING 5252021 ITMO: APPLICATION OF CONOCOPHILLIPS AK, INC. DocketNo.CO-21-005 Page 13 1 MS. GLESSNER: Yes. 2 CHAIRMAN PRICE: On the -- it looks like the 3 grey -- the grey color is your extended reach drill, 4 are you going to use extended reach on these grey 5 wells? I see they're on the -- kind of the outer edges 6 of the pool. I'm curious what rigs, drill rigs, you 7 anticipate using for drilling these wells if you are 8 aware at this time? 9 MS. GLESSNER: On just the extended reach 10 targets? 11 CHAIRMAN PRICE: All of them, but particularly 12 those. 13 MS. GLESSNER: Okay. For the first 36 well 14 program, the orange wells, we would be using Doyon 25 15 that is currently drilling at GMT2. And for the brown 16 extended reach targets that would be Doyon 26 is our 17 extended reach drilling rig. 18 CHAIRMAN PRICE: Thank you. 19 MS. GLESSNER: Okay. I will move on to Slide 20 8, which is showing our oil rim development plan in a 21 bit more detail. Our initial development plan is 36 22 wells. That includes 18 producers and 18 injectors. 23 And on this map, on the bottom part of the slide, is 24 the subsurface well pads of the wells shown. The blue 25 indicates injectors, green would be producers. The Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net AOGCC PUBLIC HEARING 525/2021 ITMO: APPLICATION OF CONOCOPHILLIPS AK, INC. DocketNo. CO-21-005 Page 14 1 well names are also in blue and green along the bottom 2 of the well. And then the actual order of -- our 3 drilling order for the first 10 wells is shown in the 4 grey boxes. There is -- also there are three brown -- 5 not brown, these are grey circles that show the three 6 exploration wells that are closest to our development. 7 We will use an enriched water alternating gas plug as 8 we do at other Alpine reservoirs to -- for enhanced 9 recovery. The horizontal lateral length in the 10 reservoir will range from 10 to 18,000 feet. The 11 northern wells will drill under the gas cap but they 12 are shorter due to the presence of the gas cap. And 13 the producers will also be hydraulically fractured and, 14 again, we won't be fracturing under or near the gas cap 15 as to avoid that. 16 MR. TIMMERMAN: All right, this is Garrett 17 Timmerman and I'll pick up at Slide 9 to give a 18 geologic overview. 19 Starting on the right side of the slide we have 20 a cross section or a -- excuse me, a stratigraphic 21 column of North Slope geology and our target is the 22 Alpine C sandstone for the Rendezvous pool. That's 23 highlighted on the strat column by the gold star. This 24 Alpine C sands sits on top of the regional extensive 25 Upper Jurassic unconformity, which has created local Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste, 2., Anch. AK 99501 Fax: 907-243-1473 Email sahilecgci.net AOGCC PUBLIC HEARING 5/25/2021 ITMO: APPLICATION OF CONOCOPHILLIPS AK, INC. DocketNo. CO-21-005 Page 15 1 accommodation for the deposition of the Alpine C sand. 2 Below this we have a deep marine shale, the Kingak 3 formation, and above us we have an extensive sequence 4 of shales that include the Miluveach shale, the Kingak 5 shale -- or excuse me, the Miluveach shale, Kalubik 6 shale and the HRZ. The geologic setting of the Alpine 7 C sand, again, deposited on the regionally extensive 8 Upper Jurassic Unconformity that created local 9 accommodation for the deposition of the C sand. It is 10 interpreted to be a transgressive marine sand, so 11 middle to lower shoreface transgressive deposit. And 12 fine to very fine grain sandstone. Based on 13 ichnological analysis of trace fossils we've 14 interpreted it to be an open marine shallow environment 15 deposited in a -- kind of a restricted bay type 16 environment. Regarding the petroleum system, the trap 17 is a stratigraphic trap with the Kignak shale below us 18 and the Miluveach shale above us. And our charge is 19 the lower Kignak. Fluid is at 37.2 degree API gravity 20 and a .232 cP oil. We have a gas oil ratio of 1279 SCF 21 per barrel with a Bo 1.7. We do have, as Dana 22 mentioned a gas oil contact and that's at negative-8108 23 TFDss. In the next slide I'll show a structure of our 24 reservoir base, the Upper Jurassic Unconformity and 25 I'll highlight where that gas oil contact intersects or Computer Matrix, LLC Phone: 907-243-0665 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email: sahileQagci.net AOGCCPUBLIC HEARING 5/25/2021 ITMO: APPLICATION OF CONOCOPHILLIPS AK, INC. DocketNo. CO-21-005 Page 16 1 correlates with our development. We do just have the 2 gas oil contact, we have no known oil water contact in 3 this pool. We have oil down to the base of the 4 Altamura 1 well, which is five miles to the south of 5 our Rendezvous 2 and 3 wells, and that -- that based 6 listed on the bottom of this slide, the oil down to 7 8450 is the bottom of the Alpine C sand in the Altamura 8 1 well. 9 Moving to Slide 10. What I'm showing here is a 10 depth structure of our reservoir base, again, the Upper 11 Jurassic Unconformity. This contour map has a 10 foot 12 contour interval. And to highlight a couple features 13 on the map, a pool boundary -- our proposed pool 14 boundary is shown by the purple outline. Our largest 15 reservoir boundary extends, it is shown by the orange 16 polygon. And as you see I've got several exploration 17 wells shown in there, as well as our core 36 well 18 development shown by the black lines. Additionally 19 shown on this map in the solid black lines are the 20 faults we have been able to seismically identify. You 21 see we have two type -- or kind of two sequences of 22 faults, or groups of faults, if you will. One to the 23 north of our development, that strikes west/northwest, 24 east/southeast. These are normal down to the south 25 faults with five to 35 feet of throw. The fault Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax 907-243-1473 Email: sahile@gci.net AOGCC PUBLIC HEARING 525/2021 ITMO: APPLICATION OF CONOCOPHILLIPS AK, INC. DocketNo. CO-21-005 Page 17 1 grouping on the east side of the development striking 2 north/northwest to south/south -- excuse me, 3 north/northeast to south/southwest are normal faults as 4 well. They have throw both to the west and to the east 5 and those have estimated offsets of 30 to 50 feet. 6 Both of those sets of throws on both sets of faults are 7 less than the estimated sand thickness at their 8 position so we don't estimate any kind of isolation due 9 to the faults themselves. Talking about the structural 10 dip, again, 10 foot contours so that looking north to 11 south we've got about one degree of structural dip to 12 the south/southeast with local variances from zero to 13 two degrees, depending on the density of those 14 contours. So a relatively gradual southward dip. 15 Another thing I'll highlight is the gas oil contact 16 position. Again, at negative-8108, if you look at 17 Rendezvous A right where the R is you can see the 8,000 18 foot contour goes through that. And then if we go 19 south two contours that'll be negative-8100 feet 20 contour which is good representation of that gas oil 21 contact presence, or -- or position, excuse me. As you 22 can see that contour wraps around the northern tip of 23 our development wells and that is by design as we would 24 drill these wells underneath the gas cap and terminate 25 before we intercept a gas column. Computer Matrix, LLC Phone: 907-243-0669 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net AOGCCPUBLIC HEARING 5/25/2021 ITMO: APPLICATION OF CONOCOPHILLIPS AK, INC. DocketNo. CO-21-005 Page 18 1 COMMISSIONER CHMIELOWSKI: One quick question 2 regarding the faults. So you expect that they are non- 3 ceiling faults, is that correct? 4 MR. TIMMERMAN: That is our expectation, yeah. 5 COMMISSIONER CHMIELOWSKI: Okay. 6 MR. TIMMERMAN: Yeah. And then tracing them up 7 through the package they appear to die in the Miluveach 8 shale above us and the Kignak shale below us. 9 COMMISSIONER CHMIELOWSKI: Thank you. 10 MR. TIMMERMAN: Moving to Slide 11. We'll move 11 from kind of that aerial depth domain to look at a type 12 well. This is the Rendezvous 2 well. It's kind of 13 right in the core of our development area and it's kind 14 of the type well that I will refer to throughout this 15 presentation today. What I've zoomed in here on is the 16 Alpine C sandstone. Highlighted in that log, so, 17 again, to go through this log, it's a triple combo log. 18 Gamma Ray on the left, resistivity is shown in the 19 central column and then neutron density and sonic on 20 the right. Additionally, I've shown core points, 21 permeability in the middle with porosity on the right 22 column to show where we have core coverage. 23 Stratographically we have the Kignak shale below us, 24 and then the Upper Jurassic Unconformity is shown by 25 that green line. As you can see it's a sharp erosive Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net AGGCCPUBLICHEARING 5/25/2021 1TMO: APPLICATION OF CONOCOPHILLIPS AK, INC. DocketNo. CO-21-005 Page 19 1 1 surface and then grating into that transgressive 2 sandstone, again, a massive fine, a very fine grain 3 sandstone, extensively bioturbated. We see minor 4 influences that you can pick out in the Gamma Ray. 5 Those are interpreted to be variable glauconite 6 content, not actual like shale intervals that we can 7 correlate across the pool, but just variable glauconite 8 content within the pool. We would like both the Alpine 9 C and Alpine D to be considered for the pool because 10 the gradation between the Alpine C and D is a 11 transgressive sequence and it's more of a local or an 12 operating distinction between where the C ends and the 13 D begins versus a lithologic distinction as you can see 14 in the log, that that's kind of a gradational sequence. 15 But on the top of the Alpine C we do transgress into 16 the Miluveach shale. We've got about 600 feet of 17 Miluveach shale around us at this point. Some average 18 sand properties, Alpine C sand properties are shown on 19 this slide. Average porosity is about 15 percent 20 ranging from 12 to 22 percent. Permeability average is 21 .64 mD, ranging from .09 to 4.57 mD with a water 22 saturation of averaging .49 with a range of 30 to 80 23 percent. 24 COMMISSIONER SEAMOUNT: Are there trends in the 25 porosity going across the accumulation or is it kind of Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste, 2., Anch. AK 99501 Fax: 907-243-1473 Email: sahileegci net AOGCC PUBLIC HEARING 1 sporadic? 5/25/2021 ITMO: APPLICATION OF CONOCOPHILLIPS AK, INC. DocketNo. CO-21-005 Page 201 2 MR. TIMMERMAN: That's a great question. There 3 are. There's two trends. One that's hard to make out 4 with the logs shown here but there's an upward 5 degradation reservoir quality so we see better 6 reservoir quality or better porosity at the base that 7 degrades upward through the deposit. And then to the 8 south using that Altamura 1 well as our one point to 9 the south, we see a southern reservoir degradation as 10 well. 11 COMMISSIONER SEAMOUNT: Okay. So laterally the 12 reservoir gets better to the north? 13 MR. TIMMERMAN: Correct, yeah. 14 COMMISSIONER SEAMOUNT: And you'll probably get 15 into this but is this continuous one sand throughout 16 that entire huge area in..... 17 MR. TIMMERMAN: That's our -- yes, that's our 18 interpretation. 19 COMMISSIONER SEAMOUNT: .....in communication? 20 MR. TIMMERMAN: Yes. 21 COMMISSIONER SEAMOUNT: Wow. Okay. Thank 22 you. 23 MR. TIMMERMAN: Yeah. 24 COMMISSIONER CHMIELOWSKI: Excuse me. How do 25 the sand properties in Rendezvous compare to, say, the Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net AOGCC PUBLIC HEARING 5/25/2021 ITMO: APPLICATION OF CONOCOPHILLIPS AK, INC. Docket No.CO-21-005 Page 21 1 1 Alpine oil pool? 2 MR. TIMMERMAN: That's a good question. They 3 tend to be a little tighter out here. So a little bit 4 lower permeability and a little bit lower porosity as 5 well. 6 So if we go to Slide 12, Commissioner Seamount, 7 I'll answer a bit of your question on the regional 8 extent here. So what I'm showing here on Slide 12 is a 9 cross section that goes from the north of the pool up 10 in our -- excuse me, hard to read on the slide, but 11 from the Spark 4 well down south through the Carbon 1 12 well. For Rendezvous A -- so Rendezvous 2 all the way 13 down to Altamura so a cross section all the way from 14 north to south. What you can see in the Spark 4 and 15 the Carbon 1 well is a thinner Alpine C sand sequence. 16 And this is kind of a -- relates to there is a 17 depositional interpretation break between what we term 18 the Rendezvous accumulation and the Spark accumulation. 19 The Spark accumulation tends to be a bit thinner 20 interpreted to be on a kind of a shelf, if you will, on 21 the Upper Jurassic Unconformity whereas the Rendezvous 22 tends to be considerably thicker. You can see over 100 23 feet of Alpine C sand thickness there. This is, again, 24 when you look at kind of the Gamma Ray characters we 25 see no internal definition or things that we can Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email: while@gci.net AOGCC PUBLIC HEARING 5/25/2021 ITMO: APPLICATION OF CONOCOPHILLIPS AK, INC. DocketNo. CO-21-005 Page 22 1 correlate and when we look at core it is extensively 2 bioturbated so if there were depositional transgressive 3 sequences we could map that bioturbation, as completely 4 erase them. 5 To kind of maybe circle back to your question, 6 Commissioner Seamount, north to south we do tend to get 7 better rock quality to the north, up in Spark and then 8 the Rendezvous A and 2 area. And then we see a 9 degradation down to the south and Altamura. 10 Going to Slide 13 to take kind more of a pulled 11 out approach to the Alpine in regards to injection 12 containment. What I'm showing here is, again, a triple 13 combo log from the Rendezvous 2 well but at a smaller 14 scale to highlight the underlying Kignak shale below 15 us. We are estimating to have approximately 1,700 16 Kignak shale below us. This is estimated from, or 17 extrapolated from the West Fish Creek 1 well. As you 18 can see the Rendezvous 2 well terminated in the Kignak 19 shale so we don't know the true depth but extrapolating 20 from seismic isopaks we think it's about 1,700 feet 21 thick here. Above us we have, again, the Miluveach 22 shale, Kalubik, and HRZ. The Miluveach shale in this 23 area tends to be five to 600 feet thick with about 100 24 to 150 feet thick of Kalubik and HRZ shale as well. So 25 with these deep marine shales these are kind of a -- Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr, Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net YKfl11L'3AIN:1.X17Will 5/25/2021 ITMO: APPLICATION OF CONOCOPHILLIPS AK, INC. DockmNo. CO-21-005 Page 23 1 play into our containment story very similar to the 2 containment story at Alpine and GMT1. And as we go to 3 the west here out into NPR -A, the Miluveach shale has 4 actually increased in thickness for us. In Alpine main 5 field the Miluveach is a bit thinner, two to 300 feet 6 thick. Where here we're at five to 600 feet thick. 7 MS. GLESSNER: Okay, this is Dana Glessner 8 again. I'm on Slide 14 just continuing to talk about 9 injection containment. As far as Rendezvous goes we 10 are requesting the same rule as the Alpine and Lookout 11 oil pools already do have for allowable injection 12 gradient of -- maximum allowable injection gradient of 13 .81 psi per foot. As Garrett mentioned we have the 14 same overburden and underburden combining intervals 15 that we have at Alpine and Lookout. And the analog 16 Alpine historical performance does indicate that we 17 have contained the injected fluids in the pools. At 18 the maximum facility discharge pressure, I did want to 19 point out, and I will -- I have two figures below that 20 I will talk about some more. The injection gradients 21 do remain below the .81 psi per foot. And our modeling 22 that we have done also indicates that injected fluids 23 will be contained in the Rendezvous pool interval. The 24 table I'm showing, labeled injection pressures here, is 25 just to point out our maximum facility discharge Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2, Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net AOGCC PUBLIC HEARING 5/25/2021 ITMO: APPLICATION OF CONOCOPHILLIPS AK, INC. DocketNo. CO-21-005 Page 24 1 pressure on seawater and gas. For seawater it's 2,850 2 psi and for gas it is 4,200 psi. And what the expected 3 injection pressure at bottomhole would be based on 4 those facility discharge pressures. So at seawater we 5 would expect to be almost 6,500, which correlates to a 6 gradient of .78 and for gas we expect to be just over 7 5,000 which correlates to a .63 gradient. So those are 8 our maximum discharge pressures and what we would 9 expect to see downhole. And on the bottom of the slide 10 I am showing one example of modeling that we did. We 11 used an industry software called GOPHER to model our 12 fractures and we've used that model and incorporating 13 the well data from the exploration wells to simulate 14 water injection. And so on the left here is a Gamma 15 Ray examp -- showing a Gamma Ray from one of the 16 exploration wells and measure depth on the right and 17 perforations here indicated by these black dots. And 18 what I wanted to show with this model, we injected 19 water into the model until we were able to achieve a 20 .82 psi per foot at bottomhole pressure and we did 21 initiate a fracture in the pool, which is shown by this 22 purple color here. So that is what we expected. But I 23 did want to show the .82 one of the models that we did 24 run, that even above the .81 that we were still 25 contained within the pool so we feel that the .81 is Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci net AOGCCPUBLICHEARING 5/25/2021 ITMO: APPLICATION OF CONOCOPHILLIPS AK, INC. DocketNo. CO-21-005 Page 251 1 appropriate to also be applied to Rendezvous. 2 COMMISSIONER CHMIELOWSKI: Do you plan to 3 inject produced water into the reservoir or just 4 seawater? 5 MS. GLESSNER: Currently we are planning to 6 start with seawater injection. 7 COMMISSIONER CHMIELOWSKI: Okay. And what 8 would be the discharged pressure of produced water 9 should you move over to that injection scenario? 10 MS. GLESSNER: So the discharge pressure would 11 be the same. It would just be a bit of a heavier 12 fluid. So at -- at the same depth, with the same 13 discharge pressure with produced water, the gradient is 14 actually .80 because the produced water is heavier. 15 COMMISSIONER CHMIELOWSKI: Thank you. 16 MS. GLESSNER: Yes. 17 MR. TIMMERMAN: All right, Garrett Timmerman 18 here again. Going to Slide 15. Take a look at water 19 we have in the region in terms of water salinity. In 20 terms of fresh water or whether there exists to be any 21 fresh water. Looking at wells both within Rendezvous 22 pool and regionally, we have identified no fresh water 23 variant intervals. That being defined as a sand with 24 less than 10,000 parts per million salinity. What I'm 25 showing again is the Rendezvous 2 type log. And you Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net AOGCC PUBLIC HEARING 5/252021 ITMO: APPLICATION OF CONOCOPHILLIPS AK, INC. DocketNo. CO-21-005 Page 26 1 see on the left portion of this slide various 2 calculated salinities of each of those sands. You'll 3 note in the C-40 and C-30 we're using an off set well, 4 the Mitre 1, Plugback 1, because the sands in the 5 Rendezvous 2 have no calculated porosity in order to be 6 able to calculate that salinity. I'll mention again 7 we've done this analysis, not only for the core wells 8 in the Rendezvous pool, but across the GMT2 area and 9 have consistent results for the sands. So have not 10 identified any fresh water intervals. 11 COMMISSIONER SEAMOUNT: Is this area part of 12 the area -wide aquifer exemption that EPA established a 13 long time ago? 14 MR. TIMMERMAN: I do not know that. 15 COMMISSIONER SEAMOUNT: Okay. 16 MR. TIMMERMAN: Yeah, so I guess based on this, 17 we'd like to request in our -- based on this finding 18 that no fresh water aquifers are present in this area. 19 Focusing in now on the shallower zone, on Slide 16, I'd 20 like to talk a bit about a proposed annular disposal 21 interval. This slide is showing the log section of 22 Rendezvous A to Rendezvous 2. Focusing in now kind of 23 on the narrow -- or excuse me, the upper stratigraphy, 24 what we have above us is the Colville group highlighted 25 on the right by that green box. This would include CB Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net AOGCC PUBLIC HEARING 5/25/2021 ITMO: APPLICATION OF CONOCOPHILLIPS AK, INC. DocketNo. CO-21-005 Page 27 1 formation, which is typically weakly consolidated clays 2 with some interbedded siltstone and mudstones. Below 3 that is the K3, which is part of the Nanushuk Group 4 that's highlighted by the pink stratigraphic top that 5 cuts across there. And then below the K3 out here in 6 the Rendezvous area we go directly in the Torok Group, 7 which is kind of those -- that albein sequence of shelf 8 to marine slope type deposits. Looking for an area -- 9 a proposed area of annular disposal, we're considering 10 the K3, or proposing using the K3 sand. That sand can 11 be seen by looking at that K3 marker, and then it's 12 that first sand that you see about 50 feet below that 13 K3 marker. This is different than the interval we're 14 currently using in Alpine. The interval we're 15 currently using in Alpine is the C30 that you see at 16 the top of the slide but because the stratigraphy and 17 the surface section dips to the east, that C30 is 18 stratigraphically, or depositionally higher here and 19 very close to the permafrost base. So in Alpine where 20 we're using it there it's quite a bit deeper, here it's 21 considerably shallower and much closer to the 22 permafrost so we don't think it's a viable zone to use 23 for that. And because of that we're considering that 24 deeper K3 interval. We are planning to set our surface 25 casings right below the K3 marker in that shale -- in Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2, Anch. AK 99501 Fax: 907-243-1473 Email: sahileegei.net AOGCC PUBLIC HEARING 5/252021 ITMO: APPLICATION OF CONOCOPHILLIPS AK, INC. DocketNo. CO-21-005 Page 28 1 the K3 shale. To talk more about annual disposal I'll 2 pass it to Nina Anderson. 3 MS. ANDERSON: So we'll be using a similar 4 method that we have used currently at CD5 or previously 5 at CD5 and GMT6 for submitting a sundry application for 6 approval for annual disposal. Once a well out here has 7 been drilled and completed and handed over to 8 production, we will review that data and consider it a 9 possibility for a candidate for annual disposal and 10 then we will submit the appropriate sundry application 11 at that point. 12 COMMISSIONER CHMIELOWSKI: Would the annual 13 disposal be used just during drilling operations? 14 MS. ANDERSON: Yes. It would be just used 15 during drilling operations for wells that are drilled 16 specifically on that drill site. 17 COMMISSIONER CHMIELOWSKI: Thank you. 18 CHAIRMAN PRICE: If there's no questions on 19 this slide I'd like to go back one slide actually and 20 ask somewhat of a loaded question. On the -- you know, 21 a few years ago, before my time, there was a revision 22 to hydraulic fraction regulations here and there was a 23 little bit of pushback from industry, here you've got 24 somewhat low permeabilities, you're going to have to do 25 quite a bit of hydraulic fracturing. There's no Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net AOGCC PUBLIC HEARING 5/25/2021 ITMO: APPLICATION OF CONOCOPHILLIPS AK, INC. DocketNo. CO-21-005 Page 29 1 aquifers in this area. So I'm curious if -- what is -- 2 how can you characterize, if you can, any hurdles or, I 3 guess characterize how difficult the current 4 regulations are when it comes to the process for 5 getting approval for hydraulic fracturing when there's 6 no aquifers present? Can anybody comment on that? 7 (No comments) 8 CHAIRMAN PRICE: I guess I'm asking is it 9 overly burdensome? 10 MS. GLESSNER: I am not specifically involved 11 with that but it seems to be the same as any other 12 permit or sundry process that we would have to do. 13 CHAIRMAN PRICE: Okay, thanks. Any other 14 thoughts or comments on that or was that it? 15 (No comments) 16 CHAIRMAN PRICE: Okay. 17 MR. VERSTEEG: So this is Joe Versteeg moving 18 on to Slide No. 17. Talk a little bit about the fluid 19 properties and the volumes, some of the reservoir 20 parameters. So the initial pressure for Rendezvous is 21 3800 psi and you can see from our tvd study that the 22 bubble point pressure is very close to that so we have 23 a saturated reservoir. And these properties are 24 derived from the black oil tvd study done in the 25 Rendezvous 3 appraisal well. The reservoir temperature Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net AOGCC PUBLIC HEARING 5/25/2021 ITMO: APPLICATION OF CONOCOPHILLIPS AK, INC. DocketNo. CO-21-005 Page 30 1 is 207 degrees. As Garrett mentioned earlier some of 2 the properties, the oil formation volume factor's 3 relatively high at 1.7 and that couples with that high 4 solution GOR of 1279. Very favorable oil viscosity for 5 water fluid, we're expecting a very efficient flood 6 because of the, you know, the very low oil viscosity so 7 that works in our favor for the secondary recovery. 8 Gas formation volume factor of .8, so .8 reservoir 9 barrels per thousand cubic feet of gas. Moving on to 10 the volumes, we have a range for the oil in place of 11 300 to 460 million barrels. Primary recover -- and 12 that 20 percent number is very much an estimate but, of 13 course, is included in the full EUR(ph) numbers but if 14 you apply that estimate, expect to recover between 60 15 to 92 million barrels just on primary. If you consider 16 the benefits of both the water flood and the enriched 17 gas flood, I think the range number recovery could be 18 between 35 to 60 percent, which equates to 105 to 276 19 million barrels recovery. For the original gas in 20 place, as was mentioned before, we do have a GOC in the 21 gas cap, the estimate is 1.7 to 2.8 TCF in place and 22 our estimate of the yield based on some data we have 23 for the wells in that area is 30 to 60 barrels per 24 million cubic feet of gas. 25 COMMISSIONER SEAMOUNT: Mr. Versteeg, what do Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr, Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net AOGCC PUBLIC HEARING 525/2021 1TMO: APPLICATION OF CONOCOPHILLIPS AK, INC. DocketNo. CO-21-005 Page 31 1 you figure the life of the production to be? How many 2 years? 3 MR. VERSTEEG: We're expecting it out to 2050 4 or so, I mean so a long life. It's a low permeability 5 reservoir, as was mentioned before, so, you know, 6 expect some nice initial peak rates but then it should 7 be kind of a low through -put stable flood that goes out 8 in time. So we expect a long life on it. 9 COMMISSIONER SEAMOUNT: It'll be a long time 10 before you can sell at 2 TCF gas, uh? 11 MR. VERSTEEG: Well, we are looking at 12 development plans for that but we just -- the details 13 haven't matured yet to where we're really able to 14 discuss that publicly yet so. 15 COMMISSIONER SEAMOUNT: Understood. 16 MR. VERSTEEG: So over on Slide 18. As was 17 mentioned earlier, so the strategy here is to go with 18 the alternating enriched gas water flood and with the 19 ultimate goal of optimizing the recovery in the 20 reservoir and that's how we could achieve that upper 21 end of the recovery is with enriched gas flood. To the 22 question before, yes, we would expect to be using 23 either seawater, or produced water. We will start -- 24 or the plan is to start on seawater and then eventually 25 switch over to produced water. And then after we computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste, 2., Anch. AK 99501 Fax: 907-243-1473 Email: sahile®gci.net AOGCC PUBLIC HEARING 5/25/2021 ITMO: APPLICATION OF CONOCOPHILLIPS AK, INC. Docket No. CO-21-005 Page 32 � 1 inject water for a period of time we'll start the 2 enriched gas slugs alternating with the water, again, 3 to get that first year recovery and make sure that we 4 optimize the recovery and the full volume. 5 So we're -- as was mentioned earlier, we're 6 really targeting the oil rim for this development and 7 we're really -- the development is planned to, or 8 designed to minimize gas coning and to manage the GOR 9 so the approach on this is to -- in the northern row 10 where we will potentially be underneath the gas cap we 11 will maximize our offset, our vertical offset from the 12 GOC. And then, of course, with your injection strategy 13 that will also help -- we'll target to replace all our 14 voidage and have a injection withdrawal ratio of one 15 which should also help with any concerns about gas. 16 COMMISSIONER CHMIELOWSKI: A question. Will 17 you begin production before an injector is in place or 18 will you wait until you have injection before you begin 19 production? 20 MR. VERSTEEG: There will be -- we'll have to 21 have -- at least, in the plan, we'll have to have a 22 couple injectors on to start the facility. So not 23 necessarily all the patterns around all the producers, 24 there may be sides of the producers that will not have 25 an injector drilled but we will simultaneously start up computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net AOGCC PUBLIC HEARING 5/25/2021 ITMO: APPLICATION OF CONOCOPHILLIPS AK, INC. DocketNo. CO-21-005 Page 33 1 injection and production. But it will not necessarily 2 mean that every pattern will have full support 3 initially. 4 COMMISSIONER CHMIELOWSKI: So it's for facility 5 reasons, not reservoir reasons that you would do it 6 them at the same time? 7 MR. VERSTEEG: Yes. It's to..... 8 COMMISSIONER CHMIELOWSKI: Right. 9 MR. VERSTEEG: .....start it up, yes. 10 COMMISSIONER CHMIELOWSKI: Okay. And how long 11 do you think you'll wait until you begin gas injection? 12 MR. VERSTEEG: Ideally six months to 12 months 13 is what we -- we want to get a good slug of water in 14 before we start the gas injection so we'd definitely 15 look to start at least some gas injection within a year 16 so. 17 COMMISSIONER CHMIELOWSKI: Okay, thank you. 18 MR. VERSTEEG: So on Slide 19. Just an 19 overview of what we expect on our peak rates. From an 20 oil production standpoint we have a range of 20 to 21 45,000 barrels a day and the cap on the -- the peak 22 production, the 45,000 barrels a day is related to the 23 fact that we have an on site production separator. So 24 that's an estimate of what we think we can get through 25 that. We may exceed that 45 but that's what provides uu ryui mamx, LLU Phone: 907-243-0668 135 Christensen Dr., Ste, 2., Anch. AK 99501 Fax: 907-243-1473 Email: sahilecagci.net AOGCCPUBLICHEARING 5/25/2021 ITMO: APPLICATION OF CONOCOPHILLIPS AK, INC. Docket No co-9I-nn< Page 34 1 that constraint. The gas correlates, peak gas kind of 2 correlates with the peak oil, you know, with the GOR 3 numbers. As was discussed earlier, we're expecting 4 this to be a pretty slow flood so a slow ramp up in 5 water production, maybe hitting a peak of 40,000 6 barrels a day, but not expecting a lot of water up 7 front. From the injection side, peak rates expect in 8 the range of 20 to 50,000 barrels of water per day. 9 And then for the enriched gas, between 20 to 70 million 10 CF gas per day. 11 COMMISSIONER SEAMOUNT: Why is your estimated 12 peak production so much lower than Alpine's was? I 13 think Alpine got to 100,000 a day, right? 14 MR. VERSTEEG: Yes. Part of the reason is 15 because of that separator limit. We think if we 16 weren't constrained by that separator limit we could 17 potentially exceed the 45,000. Also we are in a lower 18 perm environment here so compared to Alpine, so we are 19 expecting some, maybe early flush rates, but should 20 stabilize out to a lower rate. So as you're kind of 21 compounding out your time, you decline off pretty 22 rapidly and you're bringing on additional wells so it 23 may not give you the same peak that you achieved at 24 Alpine. 25 COMMISSIONER SEAMOUNT: Okay. —.o "• 11� Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email: while@gci.net AOGCC PUBLIC HEARING 5/25/2021 ITMO: APPLICATION OF CONOCOPHILLIPS AK, INC. DocketNo. CO-21-005 Page 351 1 CHAIRMAN PRICE: How long do you think you 2 could maintain production at those levels? I know you 3 said you thought all the way out to 2050 you would be 4 producing from the field, but how -- at that -- do you 5 anticipate kind of how long you could stay within that 6 20 to 45 per day? 7 MR. VERSTEEG: Yeah, these are just estimates 8 of peak rates so, you know, we would expect that we 9 would decline out as we go out in time off the peaks. 10 So, yeah, this -- the 20,000 is really just a low end 11 of the peak rate we would expect to see during that 12 life. 13 MS. ANDERSON: Okay, Nina Anderson here. 14 Starting on Page 20. I will give an overview of the 15 drilling plan. As Dana alluded to in the earlier side, 16 8, I believe, we have a program for 36 horizontal 17 wells, 18 producers and 18 injectors of varying 18 production and lateral lengths. As you can see from 19 the map on the right the layout is similar to our 20 directionally drilled wells at both CD5 and MT6 and 21 previous drill sites. We'll be using a similar 22 drilling program with known drilling fluids, using 23 known directional tools and ARVHA's (ph). All the 24 wells will be supported by existing Alpine 25 infrastructure. The key focus out here is really ouiPumr noamx, LM Phone: 907-243-0668 135 Christensen Dr., Ste. 2, Anch. AK 99501 Fax: 907-243-1473 Email: sahilecgci.net AOGCC PUBLIC HEARING 525/2021 ITMO: APPLICATION OF CONOCOPHILLIPS AK, INC. Docket Nn rn-iIAnc Page 361 1 maintaining our hole conditions and our well bore 2 stability. There is some concern as we have thickening 3 shales. So we have the HRZ, the Kalubik, and the 4 Miluveach shales and to combat that, and to mitigate 5 the risk out here we have three design variances that 6 we have built into our program. The 3-string design. 7 The 4-string design conventional, which breaks our 8 intermediate into two sections. And then our 4-string 9 pipe conveyed system. And I'll get into more detail in 10 the upcoming slides. That is the same method that we 11 used at GMT1 or MT6. In addition to the well design 12 we'll also be using managed pressure drilling out here 13 to help with our pressure stabilization during 14 connections to maintain a constant bottomhole pressure 15 and reduce the pressure cycling across the shales. 16 The next slide. So moving on to Slide No. 21. 17 This shows the well construction for our 3-string 18 design. This is kind of our standard 3-string design 19 that has been implemented at Alpine. Starting with a 20 42 inch hole, 20 inch insulated conductor. We will 21 drill with an inhibited spud mud down into the K-3 22 where we will TD. 13-3/8ths casing will be run and 23 cemented to surface. At that point we'll install test 24 our BOPE, provide notification to the State per all 25 regulations. The intermediate hole section here will vu.Puia .."o" �u Phone: 907-243-0668 135 Christensen Dr., Ste. 2, Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net AOGCC PUBLIC HEARING 5/252021 ITMO: APPLICATION OF CONOCOPHILLIPS AK, INC. DocketNo. CO-21-005 Page 37 1 be an under ringed hole section, 9-7/8ths x 11 inch 2 hole. WE'll be using our inhibited LSND mud system, 3 and then running 7-5/8th inch casing and cementing that 4 shoe per all the AOGCC requirements to maintain that we 5 have cement coverage above any existing hydrocarbon 6 bering zones. Cement quality logs, sonic logs will be 7 run on all injectors and all planned frac producers out 8 here. And then moving on to our lateral we will have a 9 6.5 inch hole that will be drilled steered through the 10 reservoir. We'll be using a combination of mineral oil 11 based mud and water based mud as we drill this hole 12 section. A 4.5 inch liner will be on producers. All 13 of our injectors out here will be barefoot completions, 14 open hole with run one tubing and lower completion 15 design. Our TDs do vary from about 22,000 to 36,000 16 feet out in this area. Our completion is a liner top 17 packer which will be set above the Alpine C and within 18 that confining zone. We'll be running producers, gas 19 lift and we'll have permanent downhole pressure gauges 20 installed for reservoir monitoring. We will be 21 fracture stimulating the producers. There is a 22 difference in that northern row. Those producers will 23 have a very short liner and we're looking at about four 24 swell packers and frac ports. And the southern well -- 25 southern row we'll be running full length laterals to �ompmer Matrix, LLc Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email: sahile®gci.net AOGCC PUBLIC HEARING 5/25/2021 ITMO: APPLICATION OF CONOCOPHILLIPS AK, INC. Docket No. CO-21-005 Page 38 1 TD with about 20 frac stages and 20 swell packers. 2 Wellhead standard, big bore vertical well tree out 3 here. We will have a 10,000 foot tree put on for the 4 fracture stimulation, and then following up with our 5 5,000 pound tree. 6 CHAIRMAN PRICE: You mentioned you anticipated 7 issues with hole stability, sluffing, any other issues 8 that you could see arising here? 9 MS. ANDERSON: With our -- that was our -- 10 that's kind of one of our primary concerns out in this 11 area and that was where a lot of our focus was. A lot 12 of the other zones are similar and similar problems and 13 risks that we mitigate through our standard drilling 14 practices. 15 CHAIRMAN PRICE: Why is hole stability such a 16 problem out here, is there something different than the 17 rest of the fields that you work in up here? 18 MS. ANDERSON: I can speak to that, Garret can 19 probably speak a little better. 20 MR. TIMMERMAN: Yeah, it's just that the 21 thickness of the shale package, it's so -- so thick and 22 predominant and it -- it's at angle as well. So even 23 our, kind of closest wells were at a, you know, 45 24 degree shale angle and then turning to horizontal 25 within that shale package and it just kind of creates a computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net AOGCC PUBLIC HEARING 525/2021 ITMO: APPLICATION OF CONOCOPHILLIPS AK, INC. DocketNo. CO-21-005 Page 391 1 mechanical problem for us. 2 MS. ANDERSON: And then as I move into the 4- 3 string I will point out that kind of the driving factor 4 for determining which design that we do select of those 5 three design variance is dependent on kind of that 6 shale thickness that Garrett mentioned and the location 7 of our HRZ slump blocks. And then also the extended 8 reach of our wells. Some of them we have intermediate 9 casing shoes out to 17,000 feet. So as we look at that 10 design, we consider which of the three designs we feel 11 most comfortable with proposing for that area. 12 So moving on to Slide 22. Here, the well 13 construction for the 4-3tring design. The difference 14 on this well is that our intermediate section is broken 15 into two strings. Intermediate 1 will be a 12-1/4 inch 16 hole, very similar mud system from the 3-string design. 17 But we will be TD'ing into the top 100 feet measure 18 depth of the HRZ. Then running a 9-5/8ths casing, 19 which will be run back to surface, and that shoe will 20 be cemented per all requirements. Then for that second 21 intermediate, we'll be drilling that shorter section 22 down into our reservoir with a 8.5 inch hole and then 23 running 7.5 inch liner. Now, on some of the wells 24 where we have a more challenging shale package to drill 25 through or an extended reach with a high deviated angle v- i-P-. mamx, LLc Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email: sahileftanet AOGCCPUBLICHEARING 5/25/2021 ITMO: APPLICATION OF CONOCOPHILLIPS AK, INC. DocketNo. CO-21-005 Page 40 1 we will be looking at steerable drilling liner, the 2 technology, which we have proved in the past at MT6. 3 Then, yeah, as I pointed out the lateral and the 4 completion are all very similar to the 3-string design. 5 CHAIRMAN PRICE: Do you anticipate any requests 6 for variance from regulations with these various 7 construction designs? 8 MS. ANDERSON: At this point, no, we do not 9 have any waiver specific to the drilling design plan or 10 variances that we will be requesting. 11 MS. GLESSNER: Okay, this is Dana Glessner 12 again. I'm on Slide 23, switching topics a bit, to 13 facilities and metering. The GMT2 production 14 measurement and allocation system was previously 15 approved by the AOGCC through Other Order 148 in 16 December of 2018. GMT2, like GMT1 will have both a 17 test and production separator on site. The production 18 will be metered after 3-phase separation on the drill 19 site before it is transported and commingled with GMT2 20 and the other CRU pools at the Alpine Central Facility. 21 Our wells will be tested monthly and production will be 22 allocated back to individual wells from test. And on 23 September 24th, 2020 we submitted our application to 24 the AOGCC per the Industry Guidance Bulletin, 13-002 25 for the GMT2 final measurement approval for the fiscal computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email: sahilecgci.net AOGCCPUBLICHEARING 5/25/2021 ITMO: APPLICATION OF CONOCOPHILLIPS AK, INC. DocketNo. CO-21-005 Page 41 1 allocation metering system. And on the bottom of the 2 slide, just briefly talking about water and gas for the 3 pool injection will be sourced from the Alpine Central 4 Facility as is customary with our other drill sites but 5 here at GMT2 -- or GMTU, gas sent from CRU to GMT2 will 6 be measured before it leaves the CRU. And then gas and 7 water injection at GMT2 will be measured at each 8 individual injector. 9 And I will move on to Slide 24, which is my 10 last slide of the non -confidential section, just to 11 talk about fluid compatibility. We do expect 12 Rendezvous production to be fully compatible with 13 Lookout and the other CRU pools. The compositions are 14 similar to Lookout and Alpine so we do expect full 15 compatibility with the produced fluids and then the 16 Rendezvous water production is also expected to be 17 completely compatible as an injection fluid at GMT2 and 18 CRU. 19 And that is our last slide. 20 COMMISSIONER CHMIELOWSKI: I have a quick 21 question. So producing GMT2, 1 and 2 -- GMT2 into the 22 Alpine Central Facility will backout other oil 23 production; is that correct? 24 MS. GLESSNER: Yes. 25 COMMISSIONER CHMIELOWSKI: And is there any vuiPuwl mamx, LLc Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email: sahilengunet AOGCC PUBLIC HEARING 5/25/2021 ITMO: APPLICATION OF CONOCOPHILLIPS AK, INC. Dockethlo. CO-21-005 Page 421 1 long-term impact to ultimate recovery in other oil 2 pools? 3 MS. GLESSNER: Joe, would you be able to handle 4 that one for me, thank you. 5 MR. VERSTEEG: Yes, you're correct that there 6 will be some back out in our portfolio. Most of the 7 near term backout is actually, we're expecting to be on 8 pad backout so -- because of that limit on the 45,000 9 barrel a day, so it would come in less than that and 10 there would be less. But in the term our forecasts are 11 really not showing as much backout on the early wells. 12 And it just depends on how long the field life goes, 13 but, yes, we would expect that you recover all that 14 with your payback period. So it's really a function of 15 end of field life, right, so. 16 COMMISSIONER CHMIELOWSKI: Thank you. 17 CHAIRMAN PRICE: I have a question on your 18 field development. I know the changing economics 19 changes the timeline for things, but do you have an 20 anticipated timeline of when all 36 wells will be 21 drilled and developed? 22 MS. GLESSNER: The initial 36 wells drilling 23 extends through the end of 2024? 24 CHAIRMAN PRICE: Thank you. Any other 25 questions, Commissioners. computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr, Ste, 2, Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net AOGCCPUBLIC HEARING 525/2021 ITMO: APPLICATION OF CONOCOPHILLIPS AK, INC. DocketNo. CO-21-005 Page 431 1 (No comments) 2 CHAIRMAN PRICE: At this time we're going to 3 take a five minute break before we get into the 4 confidential portion. 5 (Off record) 6 (Confidential) 7 (On record) 8 CHAIRMAN PRICE: Okay, folks we are back in the 9 public portion of this hearing. This is Jeremy Price 10 with AOGCC. We do have a couple of follow-up public 11 questions for you as well. 12 Commissioner. 13 COMMISSIONER CHMIELOWSKI: Thanks. I'm going 14 to refer to Slide 11, it has to do with Rendezvous 15 properties. And you discussed earlier the porosity and 16 permeability estimates and ranges for the Rendezvous 17 oil pool and mentioned that they were lower than for 18 the Alpine oil pool. My question is, will injecting 19 produced water or seawater into this reservoir with 20 lower permeability cause any issues with fluid 21 compatibility and potentially cause the recovery to be 22 lower in this oil pool? 23 MR. VERSTEEG: The expectation on water 24 injection is that we will be able to inject above 25 parting pressure and we have multiple analogs to computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email: sahileftei.net AOGCCPUBLIC HEARING 5/25/2021 ITMO: APPLICATION OF CONOCOPHILLIPS AK, INC. Docket No. CO-2I-005 Page 44 1 demonstrate, in other fields, that as long as we're 2 able to inject above parting pressure that we can 3 inject sufficiently with produced water or seawater. 4 So that's just from a historical perspective. 5 COMMISSIONER CHMIELOWSKI: So no concerns about 6 the reservoir quality being slightly lower in this oil 7 pool? 8 MR. VERSTEEG: Well, it is a -- certainly it is 9 a concern, I mean it is lower perm but that's the way 10 we think we will be able to address it is by injecting 11 above parting pressure. 12 COMMISSIONER CHMIELOWSKI: Okay, thank you. 13 CHAIRMAN PRICE: Any other questions for this 14 public portion before we close out? 15 (No comments) 16 CHAIRMAN PRICE: I'm not seeing a need, unless 17 I'm missing something, we don't need to extend the -- 18 to hold open the record, I think we're good to close it 19 today. 20 MS. GLESSNER: Yes, we would be. 21 CHAIRMAN PRICE: Okay. Then at this time we'll 22 adjourn. The time is 11:55. 23 (Off record) 24 (END OF PROCEEDINGS) 25 computer Matrix, LLC Phone: 907-243-0668 135 Christensen Du, Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email: sahile®gci.net AOGCCPUBLICHEARING 5/25/2021 ITMO: APPLICATION OF CONOCOPHILLIPS AK, INC. DocketNo. CO-21-005 Page 45 1 TRANSCRIBER'S CERTIFICATE 2 I, Salena A. Hile, hereby certify that the 3 foregoing pages numbered 02 through 45 are a true, 4 accurate, and complete transcript of proceedings in 5 Docket No. CO-21-005; AIO-21-004, transcribed under my 6 direction from a copy of an electronic sound recording 7 to the best of our knowledge and ability. 8 .01 10 DPTE 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 wmpumr matnx, LLL: Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Arch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net lk C- STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION May 25, 2021 at 10:00 am CO-21-005 & AIO-21-004 NAME Dana Glesser Patrick D, Doherty AFFILIATION ConocoPhillips ConocoPhillips Testify (yes or no) QS Kevin Donley ConocoPhillips Tyndall Ellis ConocoPhillips Stephen Tatcher (Cisco) ConocoPhillips Patrick Doherty ConocoPhillips Andy Bond Oil Search - lfG� I �i.�..ti c'•� OKJ(� Y(.�1 YPs D SRvti �ja�Ns l� LO Chris /-JaiAAcP_ Ax ccCL o ConocoPhillips _. Rendezvous Pool Hearing Conservation and Area Injection Orders May 25, 2021 Ms. Dana Glessner • ConocoPhillips Alaska, Inc • Production Engineer • BS Petroleum Engineering, West Virginia University • 20 years industry experience, 12 years in Alaska working Kuparuk and Alpine fields • Expert Witness: Production Engineering Ms. Nina Anderson • ConocoPhillips Alaska, Inc • Drilling Engineer • BS Chemical Engineering, University of Missouri - Rolla • 22 years industry experience in Alaska working Kuparuk and Alpine fields • Expert Witness: Drilling Engineering Mr. Garrett Timmerman • ConocoPhillips Alaska, Inc • Development Geologist • BS Geology, Michigan Technological University • MS Geology, University of Montana • 15 years industry experience, 1 year in Alaska working Alpine fields • Expert Witness: Geology Mr. Joe Versteeg • ConocoPhillips Alaska, Inc • Reservoir Engineer • BS Petroleum Engineering, University of Alaska - Fairbanks • 24 years industry experience, 21 years in Alaska working Kuparuk, Prudhoe, and Alpine fields • Expert Witness: Reservoir Engineering ConocoPhillips 1. Project Overview (Dana Glessner) • Location and History • Ownership and Pool boundary • Mechanical Condition of Existing wells in Pool • Oil Rim Development plan 2. Geology (Garrett Timmerman and Dana Glessner) • Geologic Overview • Reservoir Structure • Pool Interval • Injection Containment • Shallow Interval Salinity • Proposed Annular Disposal Interval 3. Reservoir (Joe Versteeg) • Fluid properties, OOIP and Resource recovery • Reservoir Management • Production and Injection Rates 4. Well Construction (Nina Anderson) • Drilling plan • Well Construction and Integrity 5. Production (Dana Glessner) • Facilities and Metering • Fluid compatibility 6. Confidential Section (Garrett Timmerman) Alpine C Seismic and Isochore Interpretation Conoaok llips Rendezvous is the Pool GMT2 is second development in Greater Moose's Tooth Unit • 8 miles SW of GMT1(Lookout) S Utilize existing Alpine infrastructure History: • 1998-2000: NPR -A Exploration 3D Seismic 2000-2004: Exploration drilling • 2008: Rendezvous 2 drilled & flow tested • 2014: Rendezvous 3 drilled & flow tested 2017-2020 : Development 3D Seismic acquisition, processing and interpretation 2018: GMT2 Sanctioned by ConocoPhillips • 2019-2020: 15Y two construction seasons • 2021: • Final installation of facilities and pipelines • First production and injection startup expected in Q4 First well spud on April 2711 Bear Tooth Unit NATIONAL PETROLEUM RESERVE-ALASKA Greater Mooses Tooth Unit if. T2 0 1.292.5 Colville i River Unit C �rDZ rLI _D A �P FIE Cos` CC; mid res ConocoPhillips Working Interest Owner: 100% ConocoPhillips (Operator) Surface Owners: BLM Kuukpik Subsurface Owners: ASK BLM Proposed Pool Boundary: • Approximately one full quarter section beyond the largest estimate of Alpine sand presence to ensure appropriate coverage of the reservoir held by the GMTU WIO. The Pool boundary terminates in the south and southeast at the GMTU boundary and excludes sections not currently held by the GMTU WIO. ConocoPhillips ConocoPhillips AlaSkg GMT 2 Rendezvous Oil Pool Development Plan F��F HC tin Z!Z 1 EL Ust ro + SPAR., KOU 2_ 5 COS-3161'e, x I "' 3t i i Colville T11N. UM NOOSES GKOUP TM.MW.UM 400TH c_ ) I - I I; Ril., 11w. um 71—i T11.1 -N _�E� UE T11', RH —unit 3 TION. R6 TuawmQ 4 + ON is U� 4A 7 ------- Greater Pr"T13p1 LNooses fflnit Tooth.. ffifflnit__ i5 ou A 2 : 2 Bear + SP, RK 00 Tooth h Unit a ffnNN M2 A 13 3: _.L'0.N _p2WUM T'W F 1W UM TION E.1 11 ww Kum T fYI %I... + P&AWells I rn ME, um gwwy )20 V MQNMI 3, gr Suspended Wells Dusting Well Path GMT2 Well Plans PIONEER I ■ GMT2X Well Plans 7 Proposed Rendezvous Oil Pool m Reservoir Boundary Kuukpfk Surface ASK Subsurface Unit Boundary Unleased x +A TAMUM Industry Lease ow, UM F/ T9N. R E. UM Is TW,�, UM CPAI Lease w ull 21 NPR -A f T!.. 7Z TM. ME. W; Pad Pipeline d nNumo is m Road Conocx;�Phillips • Plugged & Abandoned • Altamura 1 • Carbon 1 • Moose's Tooth C • Rendezvous 2 • Rendezvous A • Spark DD-9 • Spark 1 • Spark 1A • Spark 4 • Suspended • Rendezvous • Scout 1 • Well count: 18 producers, 18 injectors • Enriched water alternating gas (EWAG) flood • Horizontal lateral length in reservoir will range from 10,000'—18,000' • Northern wells will drill under gas cap • Producers will be hydraulically fractured • No hydraulic fracturing under or near gas cap g � TION, Alt T1ON, R2E T9N, RIE R—Im '^"a T N, R2E -- �, ___ b� \ Well Nairn. T)-lIX Pratlucer � '�i� �� MTIJIX In)aclor • Exploration Well ±� ❑n Drill order 1 Reservoir Boundary 6 I /Proposed Pool Boundary y` ,.NNM I..M?l 114e 9 a»J .TN 6XA 9X* '0. .Us v»>J CwowPhiiips Location: • NPR -A — Greater Moose's Tooth Unit Geo Setting: • Upper Jurassic Alpine C sand deposited in accommodation resulting from Upper Jurassic Unconformity (UJU) incision • Fine to very fine-grained sandstone • Open Marine, Lower Shoreface (near storm wave base) deposition • Transgressive Deposit Trap: • Stratigraphic — Miluveach Shale above/ Kingak Shale below Charge: • Lower Kingak sourced oil Fluids: • 37.2°API gravity, 0.232 cP oil • GOR 1279 SCF/STB, Bo 1.7 • GOC -8108' TVDss (MDT Rendezvous A and Rendezvous 3) • ODT-8450' TVDss (Altamura 1) Sw NE MA O Z N O Z W W s0 Q U Y W o ss _ Co.._Gp `` D o a Cc W u, 00 w O 96 -- Nanush LOU W U Q W � o W U 0 z 144 AIP U r¢ fn 0 Q Nechelik w Kingak Frn m 2W _ Shubllk Fm. R�hnr � TRIASSIC Z Q W W OZ PERMIAN W a PENNSYLVANIAN W j N W Lisburne Gp. *-Alpine C SS .* - Primary Source (Kingak) ConocoPhinips Depth Map of the Upper Jurassic Unconformity (UJU), Reservoir Base Irm ,3 ,SSM ta'J)OW :.,m 14N 143M 141 14:OYYJ ,W=O Fault Exploration Well Development Well ERD Development Well Reservoir Boundary Proposed Pool Boundary 50' Contour Interval Depth TVDss, feet o eoo3 ,ma ,sew � zsvr,us Ym... d ---- t,,,w 190 ConocoPhillips Proposed vertical limits for the Rendezvous Oil Pool V L C S 2 e Alpine C Sand Properties in FA�JS �iC Rendezvous 2: _ Porosity: Avg. 15.6%, Range 12-22% r Permeability: Avg. 0.64 mD, Range 0.09-4.57 mD ' Water Saturation: Avg. 0.49, Range 30-80% Upper Jurassic Unconformity i Conocophillips Well Section showing log character of the Alpine interval through the Rendezvous Pool Ni u s �_c 15.2 mi South cO(IOCOpIIliIPS The Alpine sand interval (C&D) is contained above and below by extensive deep marine shales. Very thick and competent shale section above the Alpine (thicker than typical in CRU area) Approximately 1700' of Kingak shale lies below the Alpine Interval (as observed in the W Fish Creek 1 well) ConocoPhillips Injection Containment continued Sea Water I Gas 14 Rendezvous Area Type Log — Shallow Salinity Analysis Summary CPAI requests a finding in the Orders that no freshwater aquifers are present in the Rendezvous area. Permafrost �Iville Group (Clay with :erbedded silt & minor nds) inushuk Group (K•3 to Albian ; top sets, shallow marine, :s/shales and thin fine- 3ined sands rok (Albian slope & deep trine shales with inter- dded sands) ; Fill Z/Kalubik/Miluveach Shales pine C Sandstone (Target) ConocoPhillips Permafrost base at -1,000' TVDss C3o CID cs Surface Casing M K2 ab.M+- Aftan 97 4. Aban 96 Alb, n A@an 9A Gl}- n1bIM 93 � - 15951 fIUS _ " f3p 1!ESb !IP!!, TS mmue]e2R GR LfnD u0 oB ,box ,.ar REb'A I,Pw 65 4q !xw !alf' :ea-.-n.i® s ate. mrs »xuv]af+: R!SS a ,w;AS -:•x _: •�..;x`,baw f`r RWB RF.SS RYOB DiC us.. b Im505 = �m>w� J_C ,boa in.ti si - .oc f ]f4B : bViD ,K4CIO YJA i :xm -x =ar e zW 3 z6» - 2M �. 1x0 K3 i 7�0 i - 1004 30i0 aom JXD I _..K7 _•.AIdAn 3W0 I �4 r"0 I � Alba 3W wo >OaD I Ym - _ .Alban ]b0 may. .. Alban WO a000 000 AlbM Colville Group: Weakly consolidated, silty, medium gray claystone with some siltstone lenses. ;'Nanushuk Group: I.Shallow marine deltaic .sediments, like Colville, but more lithified. Torok Group: Series of " 97 slope to deep marine sediments forming 96 clinoforms. Mainly 95 marine shale with interbedded turbiditic ss sands. ConocoPhill Ips Reservoir Fluid Properties (8140 feet TVDss in Rendezvous 3) Property Units Measured Value Initial Reservoir Pressure, psia 3802 Reservoir Temperature, OF 207 Saturation Pressure, psia 3815 Oil formation volume factor, RVB/STBO 1.7 Oil Density, °API 37.2 Oil Viscosity, cp 0.232 Gas formation volume factor, RVB/MCF 0.8 Gas oil ratio, SCF/BBL 1279 In Place and Recoverable Resource Volumes (Pre Development) Hydrocarbon Resource Estimated Volumes Original Oil in Place, OOIP 300 to 460 MMSTB Primary Recovery (Er = 20% of OOIP) 60 to 92 MMSTB Primary + EWAG Recovery (Er = 35-60% of OOIP) 105 to 276 MMSTB Original Gas in Place, OGIP 1.7 to 2.8 TCF Yield Range 30 to 60 BBL/MMSCF ConocoPhillips Enriched Water Alternating Gas (EWAG) flood Seawater or Produced Water Enriched Gas ,. Oil rim only development is designed to minimize gas coning and manage the GOR Gas cap production will be minimized by maintaining offset with producers, including fracture stimulation offset , Injection/Withdraw ratio of 1.0 will be targeted ConocZi hllips Peak Annual Rates Production • Oil (MBOPD) 20-45 • Gas (MMCFPD) 25-100 • Water (MBWPD) 5-40 • Lift Gas (MMCFPD) 10-25 Injection Water (MBWIPD) 20-50 Gas (MMCFPD) 20-70 ConocoPhillips 36 horizontal wells • 18 Producers • 18Injectors • Similar drilling program and well design as CD5 Key Focus Areas: • Wellbore stability - directional drilling through HRZ, Kalubik and Miluveach shales • Mix of well casing designs anticipated • 3-string (Similar to CD5) • 4-string (Conventional Int2) • 4-string (Pipe Conveyed Intl — GMT1) • Managed Pressure Drilling (MPD) 4 IL ®b—I e,W111400, 1 5,000 ft. ConocoPhillips • 20" Insulated conductor w/ thermo-siphon • Surface: • 16" Hole • Inhibited Spud Mud • TD into the K-3 • 13-3/8" Casing & Cement to Surface • Install and test BOPE with notice to State • Intermediate: • 9-7/8" x 11" Hole • LSND Mud • 7-5/8" Casing • Cement Shoe per AOGCC requirements • Run cement quality log • Lateral • 6.5" Hole • Mineral Oil Based or Water Based mud • 4-%2" Liner on producers, Openhole for injectors • TD "' 22,000' to 36,000' MD • Completion • Liner top packer set above Alpine C within confining zone Gas lifted producers w/ permanent downhole pressure gauges • Fracture stimulation producers (sleeves —700 ft apart w/ swell packers) • Wellheads with vertical tree (10K frac tree, then 5K prod tree) Top aMM.0 W 39 WI NIO M.NIa CP.9Vaw BOIM. aNNNeplo wlxe I} WLIOlLC ♦1rCl2.ML40N.0303 Da.11role G] . T~9 r 13nM WpoWn Il w-%' lPd.1 Nlp9N 0 013' IDi 23 N4 e P DLM 12 }q 3)KS Dp• 11 Gx . 4 NOW*. Pxeer VA' YLa MNVVM(3]5 ID! 5) 1,wr lap Padm I NMONr%' T* Par New* 2%PI vTW Pc...r C/. 1L0N LM Wd%3 LMS WJ S• WCIMnsIa W WMe lrec Apra W Q If A MD I."' n IM31D L40 ❑(P INT CmM993 ,Z%5'MD hDNM mod* TD ConocoPhillips • 20" Insulated conductor w/ thermo-siphon • Surface: • 16" Hole • Inhibited Spud Mud • TO -3,650' to 4,115' MD (K-3) • 13-3/8" Casing & Cement to Surface • Install and test BOPE Intermediate 1: • 12'/." Hole • LSND Mud • TO into the HRZ • 9-5/8" Casing • Cement Shoe per AOGCC requirements • Intermediate 2: • 8-Y." Hole LSND Mud • 7" Liner (some with Steerable Drilling System) • TO into the Alpine C • Cement Shoe per AOGCC requirements • Run cement quality log • Lateral • 6.5" Hole • Mineral Oil Based or Water Based mud • 4-%" Liner on producers, Openhole for injectors • TD — 22,000' to 36,000' T., Alp. C • Completion • Liner top packer set above Alpine C within confining zone • Gas lifted producers w/ permanent downhole pressure gauges Fracture stimulation producers (sleeves —700 ft apart w/ swell packers) Wellheads with vertical tree (10K frac tree, then 5K prod tree) 2r rf Wf NJoY WN d com. u. so YN. cN+Y�.d+o )Jsr srdaa C•Nny A-W U 6 OW IAd WydX) s sm a3 vw ud Nvd)s) ravNLadnvin.+ 2W.0 di •: � • i"GLN .i Ir•d.a,a+vae.w di>.r,om —M GMT2 production measurement and allocation system was approved by AOGCC through Other Order 148 on 12/19/2018 GMT2, like GMT1, will have both a test separator and production separator on -site Production metered after 3-phase separation on the drillsite before transport and commingling with GMT1 and the other CRU Pools Wells will be tested monthly, production will be allocated back to individual wells from well tests _ On 9/24/2020 an application was submitted to AOGCC per Industry Guidance Bulletin 13-002 for GMT2 final measurement approval for the fiscal allocation metering system • Water and gas for Pool injection sourced from Alpine Central Facility Gas sent from CRU to GMTU will be measured before leaving CRU Gas and water injection at GMT2 will also be measured at each individual injector ConocoPhillips Rendezvous production is expected to be fully compatible with Lookout and other CRU Pools from both a production processing and injection perspective. ➢ Rendezvous production compositions are expected to be similar to the Lookout and Alpine Pools and fully compatible with all CRU pools ➢ Rendezvous is a close analog to the Alpine Pool because both pools share a similar geologic history with the same oil charge source (Lower Kingak) and comparable structural and depositional schemes. ➢ Rendezvous water production will be a mixture of Rendezvous connate water and seawater or ACF produced water and it is not expected to be significantly different than Lookout and Alpine Oil Pools produced water and therefore should be fully compatible with all GMTU and CRU pools. ➢ Application of scale inhibitors, corrosion inhibitors and any other production treatments at Rendezvous will be similar to those at Lookout and other CRU pools ConocoPhillips Notice of Public Hearing STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION Re: Docket Numbers: CO-21-005 And AIO-21-004 The application of ConocoPhillips Alaska, Inc. (CPAI) for order establishing pool rules and an area injection order for the proposed Rendezvous Oil Pool in the Greater Moose's Tooth Unit. CPAI, by letter dated April 12, 2021, requests the Alaska Oil and Gas Conservation Commission (AOGCC) issue orders establishing pool rules and an area injection order Rendezvous Oil Pool in the Greater Moose's Tooth Unit on the North Slope of Alaska. The AOGCC has scheduled a public hearing on this application for May 25, 2021, at 10:00 a.m. at 333 West 711 Avenue, Anchorage, Alaska 99501. If interested party wishes to participate at the hearing telephonically, they should call 1-800-315- 6338 and, when instructed to do so, enter the code 14331. 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 71 Avenue, Anchorage, Alaska 99501. Comments must be received no later than the conclusion of the May 25, 2021 hearing. If, because of a disability, special accommodations may be needed to comment or attend the hearing, contact the AOGCC's Special Assistant, Grace Salazar at (907) 793-1221, no later than May 21, 2021. Jeremy JeDined by em;MP, Date: 2021.0 ..16 M. Price KN57-0B-W Jeremy M. Price Chair, Commissioner Please note to those participating telephonically, the call -in number has changed to: 1-650-479-3207 or toll -free at 1-855-244-8681 Access Code: 1779999214# Notice of Public Hearing Attendee ID/password: 76498367# STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION Re: Docket Numbers: CO-21-005 And AIO-21-004 The application of ConocoPhillips Alaska, Inc. (CPA]) for order establishing pool rules and an area injection order for the proposed Rendezvous Oil Pool in the Greater Moose's Tooth Unit. CPAI, by letter dated April 12, 2021, requests the Alaska Oil and Gas Conservation Commission (AOGCC) issue orders establishing pool rules and an area injection order Rendezvous Oil Pool in the Greater Moose's Tooth Unit on the North Slope of Alaska. The AOGCC has scheduled a public hearing on this application for May 25, 2021, at 10:00 a.m. at 333 West Th Avenue, Anchorage, Alaska 99501. If interested party wishes to participate at the hearing telephonically, they should call 1-800-315- 6338 and, when instructed to do so, enter the code 14331. 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 7's Avenue, Anchorage, Alaska 99501. Comments must be received no later than the conclusion of the May 25, 2021 hearing. If, because of a disability, special accommodations may be needed to comment or attend the hearing, contact the AOGCC's Special Assistant, Grace Salazar at (907) 793-1221, no later than May 21, 2021. Jeremy JeDigitally e y0A'�Ice"9 Date: 2021.04.16 M. Price 14A9:57-08b0' Jeremy M. Price Chair, Commissioner Notice of Public Hearing STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION Re: Docket Numbers: CO-21-005 And AIO-21-004 The application Of ConOCOPhllllps Alaska, Inc. (CPAI) for order establishing pool rules and an area injection order for the proposed Rendezvous Oil P00l in the Greater Moose's Tooth Unit. CPAI, by letter dated April 12, 2021, requests the Alaska Oil and Gas Conservation Commission (AOGCC) issue orders establishing pool rules and an area injection Order Rendezvous Oil Pool in the Greater Moose's Tooth Unit On the North Slope of Alaska, The AOGCC has scheduled a public hearingg on this application for May 25, 2021, at 10:00 a.m. at 333 West 7th Avenue, Anchorage, Alaska 99501, If interested parry wishes to Participate atthe hearing telephonically, they Sh0uld Cali 1-800-315-6338 and, when Instructetl t0 do so, enter the Code 14331. Because the hearing will start at 10:00 a.m., the phone lines will be available startinSS 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 the conclusion of the May 25, 2021 hearing. If, because of a disability, special accommodations may be needed to comment or attend the hearing, contact the AOGCC's Special Assistant, Grace Salazar at (907) 793-1221, no later than May 21, 2021. //signature on file// Jeremy M. Price Chair, Commissioner Pub: April 18, 2021 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 AO-08-21-019 FROM: Alaska Oil and Gas Conservation Commission AGENCY CONTACT: Jody Colombie/Samantha Carlisle DATE OF A.O. AGENCY PHONE: 4/16/2021 90 279-1433 333 West 7th Avenue Anchorage, Alaska 99501 DATES ADVERTISEMENT REQUIRED: Account Number: 100869 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: i✓ LEGAL j- DISPLAY r- CLASSIFIED r OTHER (Specify below) DESCRIPTION PRICE CO-21-005 and AIO-21-004 Initials of who prepared AO: Alaska Non -Taxable 92-600185 SUDMITINVOCE sHowN'CAU.kit TANG: ORDFk NO:,CERTIFHiOAMOAM. O9':: - PUBLICATION WITH ATTACHsflCOPY OR,: AIiVaRTISMENT TO AOGCC 333 West 7th Avenue Anchors e, Alaska 99501 Page 1 of I Total of All Pa es S REF Type Number Amount Date Comments I PvN IVCO21795 2 AO AO-08-21-019 3 4 FIN AMOUNT SY Act Template PGM LGR object FY DIST LIQ 1 21 AOGCC 3046 21 2 3 4 5 Pure A oil m T Purchasing Authority's Sigoalure Telephone Number 1. A . D a receiving agency name must appear on all Invoices and documents relating to this purchase. 2. a state is registered for tax free transactions under Chapter 32, IRS code. Registration number 92-73-0006 K. hems are for the exclusive use of the state and not for iSTRIBUTION ,?1: ':» ..,...._.....,. .,.,. _. _ .:,..; .... DIYis19&F15CSU�r#glAal¢O Capies: Publisher (taxed)1)11VIs10PFf4CAy SSYIY148.. Form:02-901 Revised: 4/19/2021 ANCHORAGE DAILY NEWS AFFIDAVIT OF PUBLICATION Account #: 100869 ST OF AK/AK OIL AND GAS CONSERVATION COMMISSION 333 W. 7TH AVE STE 100, ANCHORAGE, AK 99501 Order #: W0022074 STATE OF ALASKA THIRD JUDICIAL DISTRICT Lisi Misa being fast 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 04/18/2021 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 'mil/ "I/ Il Subscribed and sworn to before me this 19th day of April 2021 Anchorage, Alaska MY C'7O r �SSI �N jE,XPIRES Cost: $219.16 RECEIVED APR Z 1 2021 AOGCC Notice of Public Hearing STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION Re: Docket Numbers: CO-21-005 And AIO-21-004 The application of ConocoPhillips Alaska, Inc. (CPAI) for order establishing pool rules and an area injection order for the proposed Rendezvous Oil Pool in the Greater Moose's Tooth Unit. CPAI, by letter dated April 12, 2021, requests the Alaska Oil and Gas Conservation Commission (AOGCC) issue orders establishing pool rules and an area injection order Rendezvous Oil Pool in the Greater Moose's Tooth Unit on the North Slope of Alaska. The AOGCC has scheduled a public hearing on this application for May 25, 2021, at 10:00 a.m. at 333 West 7th Avenue, Anchorage, Alaska 99501. If interested party wishesto participate at the hearing telephonically, they should calf 1-800-315-6338 and, when instructed to do so, enter the code 14331. 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 the conclusion of the May 25, 2021 hearing. If, because of a disability, special accommodations may be needed to comment or attend the hearing, contact the AOGCC's Special Assistant, Grace Salazar at (907) 793-1221, no later than May 21, 2021. //signature on file// Jeremy M. Price Chair, Commissioner Pub: April 18, 2021 v+Hts'y PUBLIC I JADA L. NOWLtNG II STATE OF ALASKA LKAYC•roI, ur rC,4dy14.2024 Colombie, Jody J (CED) From: Colombie, Jody J (CED) <jody.colombie@alaska.gov> Sent: Friday, April 16, 2021 2:14 PM To: AOGCC Public Notices Subject: [AOGCC_Public_Notices] Public Hearing Notice - CPA Attachments: Rendezvous Pool Rules and AIO Public -Hearing notice.pdf Re: Docket Numbers: CO-21-005 And AIO-21-004 The application of ConocoPhillips Alaska, Inc. (CPAI) for order establishing pool rules and an area injection order for the proposed Rendezvous Oil Pool in the Greater Moose's Tooth Unit. Jody J Colombie AOGCC Special Assistant Alaska Oil and Gas Conservation Commission State of Alaska 333 West 7'" Avenue Anchorage, AK 99501 Phone Number : 907-793-1221 Email: jody.colombie@alaska.gov List Name: AOGCC_Public_Notices@list.state.ak.us You subscribed as: jody.colombie@alaska.gov Unsubscribe at: http://list.state.ak.us/mailman/options/aogcc_public_notices/jody.colombie%40alaska.gov Benue 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. P.O. Box 13557 Denver, CO 80201-3557 Darwin Waldsmith P.O. Box 39309 Ninilchik, AK 99639 ConocoPhillips April 12, 2021 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. Box 100360 Anchorage, AK 99510-0360 phone 907.263.4464 RECEIVED APR 1 Z 2021 AOGCC RE: Application for Area Injection Order for Rendezvous Oil Pool, North Slope, AK Dear Commissioner Price: In accordance with 20 AAC 25.402, Enhanced Recovery Operations, and 20 AAC 25.460, Area Injection Orders, ConocoPhillips Alaska, Inc. (CPAI) as operator of the Greater Moose's Tooth Unit (GMTU), requests that the Alaska Oil and Gas Conservation Commission approve CPAI's application for an Area Injection Order for the proposed Rendezvous Oil Pool (ROP), which is within the GMTU. ROP drilling is expected to commence in Q2 2021 and injection operations are planned to be initiated in Q4 2021. Pursuant to 20 AAC 25.537 and 20 AAC 25.540(c)(10), CPAI requests that Appendix 1 to this application be treated as confidential as the information is a trade secret or is commercially sensitive confidential and proprietary information entitled to confidential treatment. CPAI requests that the hearing date for this application be scheduled as soon as possible after the 30-day public notice period has concluded. Please contact Dana Glessner (265-6478, glessd@conocophillips.com) if you have questions or require additional information. Regards, � n -, 1� Stephen Thatcher Manager, WNS Development Cc: Chait Borade, Arctic Slope Regional Corporation Erik Kenning, Arctic Slope Regional Corporation Wayne Svejnoha, United States Department of Interior, Bureau of Land Management CPAI Application for Area Injection Order, Rendezvous Oil Pool April 12, 2021 Page 1 of 51 ConocoPhillips APPLICATION FOR AREA INJECTION ORDER IN THE RENDEZVOUS OIL POOL April 12, 2021 Section A— Introduction 20 AAC 25.402(c)(1) Section B — Plot of Project Area 20 AAC 25.402(c)(2) Section C — Operator & Surface Owners 20 AAC 25.402(c)(3) Section D — Section E — Affidavit Description of Proposed Operation 20 AAC 25.402(c)(4) 20 AAC 25.402(c)(5) Section F — Pool Description 20 AAC 25.402(c)(6) Section G — Formation Geology 20 AAC 25.402(c)(7) Section H — Section I — Logs of Injection Wells Mechanical Integrity of Injection Wells 20 AAC 25.402(c)(8) Section J — Injection Fluids 20 AAC 25.402(c)(9) 20 AAC 25.402(c)(10) Section K— Injection Pressures 20 AAC 25.402(c)(11) Section L — Fracture Information 20 AAC 25.402(c)(12) Section M — Formation Water Quality 20 AAC 25.402(c)(13) Section N — Aquifer Exemption 20 AAC 25.402(c)(14) Section O — Hydrocarbon Recovery 20 AAC 25.402(c)(15) Section P — Confinement in Offset Wells Section Q — Proposed Area Injection Order Rules List of Figures/Exhibits A-1: Defining Well, Rendezvous 2, Highlighting Pool Interval A-2: ROP Boundary with Proposed and Existing Wells D-1: Affidavit G-1: A) Cross Section flattened on top Alpine (Alpine D) from Spark 4 — Carbon 1 - Rendezvous A — Rendezvous 2 — Altamura 1. B) Reference Map Shows the Cross Section Over Depth Map of the UJU. G-2: Rendezvous Area Stratigraphic Section — Rendezvous 2 Well Log G-3: Depth map of the Upper Jurassic Unconformity (UJU, Reservoir Base) 1-1: Proposed Three String Rendezvous Injector Well Design 1-2: Proposed Four String Rendezvous Injector Well Design J-1: Kuparuk Seawater Treatment Plant Water Composition J-2: Alpine Facility Produced Water Composition J-3: CD5K Enriched Gas Injectant Composition J-4 Alpine Facility Dry Gas Composition L-1: Rendezvous 2 Log, Alpine Formation and Confining Intervals L-2: Rendezvous 2 Upper Zone Well Containment Model Results L-3: Rendezvous 2 Lower Zone Well Containment Model Results L-4: Formation Water Salinity Summary with the Rendezvous Type Log (Rendezvous 2) and the Lithology Summary CPAI Application for Area Injection Order, Rendezvous Oil Pool April 12, 2021 Page 2 of 50 Appendix 1 — Confidential Information G-4: Lambda -rho extraction above UJU surface highlighting reservoir presence within the reservoir boundary and pool area. (Confidential, Appendix 1) G-5: Lambda -rho seismic volume showing the seismic response of the Alpine C sand above the mapped UJU horizon within the GMT2 development area. (Confidential, Appendix 1) G-6: Alpine C Isochore for Rendezvous Pool showing Exploration Wells and proposed Pool Boundary (Confidential, Appendix 1) G-7: Rendezvous Net Oil Pay with proposed drilling locations (Confidential, Appendix 1) CPAI Application for Area Injection Order, Rendezvous Oil Pool April 12, 2021 Page 3 of 50 SECTION A — INTRODUCTION Document Scope This application is submitted for approval by the Alaska Oil and Gas Conservation Commission (AOGCC) to establish area injection rules pursuant to 20 AAC 25.402, Enhanced Recovery Operations, and 20 AAC 25.460, Area Injection Orders (AIO), for the Rendezvous Oil Pool (ROP) as described in the Conservation Order (CO) application filed separately and concurrently with this application. In its capacity as Operator of the Greater Moose's Tooth Unit (GMTU) and on behalf of the GMTU working interest owners (WIO), ConocoPhillips Alaska, Inc. (CPAI) submits this application to the AOGCC. The purpose of this application is to gain authorization from the AOGCC to inject fluids for pressure maintenance and enhanced recovery of hydrocarbons in the ROP pursuant to 20 AAC 25.402 and 20 AAC 25.460. CPAI requests the AOGCC approve the proposed rules which will provide for economic development of the resources, promote greater ultimate recovery, and prevent waste. This application contains confidential data concerning the ROP which CPAI requests be held confidential in accordance with the provisions of 20 AAC 25.537 and 20 AAC 25.540(c)(10). Confidential data is provided in Appendix 1. Introduction The ROP was first assessed and delineated from 2000 to 2004 by the Rendezvous A (2000), the Rendezvous 2 (2001), the Spark 1A (2001), the Moose's Tooth C (2001), the Altamura 1 (2002), the Spark 4 (2004), and the Carbon 1 (2004) wells. Rendezvous 2 and Altamura 1 encountered liquid hydrocarbons, while Rendezvous A, Spark 1 A, Spark 4, and Carbon 1 encountered a full gas column with liquid hydrocarbons present in the well tests. Based on this data a gas -oil contact (GOC) was estimated to lie somewhere between the Rendezvous A and Rendezvous 2 wells. CPAI screening evaluations of liquid and gas developments have shown a standalone processing facility is not economically feasible. Therefore, the ROP oil column development will be routed back to the Alpine Central Facility (ACF) for processing. Additionally, a development of the ROP gas cap routed through the ACF for processing is also not feasible due to gas handling limitations, which will result in significant production backout of existing pools. CPAI continues to actively analyze development options for Spark. In 2008, the GMTU was formed. In 2018, a Record of Decision was issued on a Supplemental Environmental Impact Statement authorizing the project to develop the ROP. The project to develop the ROP is also known as the Greater Moose's Tooth 2 (GMT2) Project and was sanctioned by CPAI in 2018. GMT2 is the second development wholly within the National Petroleum Reserve, Alaska and the GMTU. The project consists of a new drillsite and associated facilities located approximately 8 miles southwest of the Greater Moose's Tooth 1 (GMT1) project/ Moose's Tooth 6 (MT6) drillsite (Figure 3), with a permanent road connecting the two drillsites, four new cross-country pipelines (produced fluid, water injection, gas injection and dry gas supply) and 36 horizontal wells (18 producers and 18 injectors, as shown in Figure 4). An injection program of water alternating with enriched gas injection will optimize recovery from the pool. GMT2 production will be measured for custody transfer prior to being commingled on the surface with production from the Lookout Oil Pool (LOP) and the Colville River Unit (CRU). GMT2 production will be processed at the ACF in the CRU. The ROP is defined as the accumulation of hydrocarbons common to and correlating with the interval between the measured depths of 8,229 feet and 8,393 feet (-8,104 feet and -8,268 feet true vertical depth sub -sea (TVDss) respectively) in the Rendezvous 2 well (Figure A-1). Figure A-2 shows the positions of the exploration wells in relation to the ROP boundary and proposed oil development. From a geologic and reservoir perspective, the ROP is like the LOP in that it does not have Alpine A sand present, does not include Kuparuk sands, and is light oil with an associated higher solution gas -oil ratio (GOR) than CRU Alpine sand oil. From an operations perspective, the ROP will be operated similar to the LOP and CRU upper Jurassic oil pools. CPAI Application for Area Injection Order, Rendezvous Oil Pool April 12, 2021 Page 4 of 50 SECTION B — PLOT OF PROJECT AREA 20 AAC 25.402(c)(1) 20 AAC 25.402(c)(1) - An application for injection must include a plat showing the location of each proposed injection well, abandoned or other unused well, production well, dry hole, and other well within one -quarter mile of each proposed injection well. Figure A-2 shows the proposed wells for the ROP development along with all previously drilled wells in the ROP area. Thirty-six horizontal wells are proposed - 18 injectors and 18 producers. There are an additional 12 wells, 6 producers and 6 injectors, that are identified as potential extended reach drilling (ERD) targets depending on reservoir outcome. The oil column in the ROP is penetrated by the Rendezvous 3, Rendezvous 2, and Altamura 1 vertical appraisal wells, which confirmed the presence of oil-bearing reservoir sands. The Rendezvous field also has a gas cap, commonly referred to as Spark, which has been penetrated by the Rendezvous A, Spark 4, Moose's Tooth C, Carbon 1, Spark 1, Spark 1A, and Spark DD-9 wells. All wells have been plugged and abandoned except for Rendezvous 3 which has been suspended and has potential utility as a surveillance well to monitor reservoir flood performance. Consequently, there are currently no plans to plug and abandon the Rendezvous 3 well. CPAI Application for Area Injection Order, Rendezvous Oil Pool April 12, 2021 Page 5 of 50 SECTION C — OPERATOR & SURFACE OWNERS 20 AAC 25.402(c)(2) 20 AAC 25.402(c)(2) - An application for injection must include a list of all operators and surface owners within a one -quarter mile radius of each proposed injection well. CPAI is the designated operator of the GMTU, which includes the new Moose's Tooth 7 (MT7) drillsite from which the Rendezvous wells will be drilled. The surface owners and operators within one -quarter mile radius of the proposed injection area are listed below. Operators: No operator other than CPA[ Surface Owners: United States Department of Interior Bureau of Land Management Alaska State Office 222 West 7th Avenue #13 Anchorage, Alaska 99513 Attn: Branch Chief, Energy and Minerals Kuukpik Corporation P.O. Box 89187 Nuiqsut, Alaska 99789-0187 Attention: Joe Nukapigak, President CPAI Application for Area Injection Order, Rendezvous Oil Pool April 12, 2021 Page 6 of 50 SECTION D — AFFIDAVIT 20 AAC 25.402(c)(3) 20 AAC 25.402(c)(3) - An application for injection must include an affidavit showing that the operators and surface owners within a one -quarter mile radius have been provided a copy of the application for injection. Exhibit D-1 is an affidavit showing that the operators and surface owners within a one -quarter mile radius of the proposed injection area have been provided a copy of this application. CPAI Application for Area Injection Order, Rendezvous Oil Pool April 12, 2021 Page 7 of 50 SECTION E — DESCRIPTION OF PROPOSED OPERATION 20 AAC 25.402(c)(4) 20 AAC 25.402(c)(4) - An application for injection must include a full description of the particular operation for which approval is requested. The ROP will be developed from the new GMTU drillsite MT7, which is connected to the ACF. The ROP will be developed with horizontal production and injection wells in line drive patterns, oriented with the maximum principal horizontal stress, that range in length from 10,000 feet to 18,000 feet within the reservoir. The development plan includes a total of 36 wells, 18 horizontal injection wells and 18 horizontal production wells. There is room on the drillsite for an additional 12 wells that are considered potential ERD targets. Pressure support will be maintained with water and enriched gas injection. An Enriched Water Alternating Gas (EWAG) flood will be initiated early in the waterflood to improve ultimate recovery. Enriched gas injection will result in oil swelling and yield incremental recovery. 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. The EWAG will enhance displacement efficiency and result in improved recovery. Simulation work demonstrated an optimal well spacing of 1,200 feet separation between injectors and producers. The producers are planned as multistage fracture stimulated horizontal wells and the injectors will be unlined or barefoot completions. CPAI Application for Area Injection Order, Rendezvous Oil Pool April 12, 2021 Page 8 of 50 SECTION F — POOL DESCRIPTION 20 AAC 25.402(c)(5) 20 AAC 25.402(c)(5) - An application for injection must include the names, descriptions, and depths of the pools to be affected. Location As shown on Figure A-2, the affected area proposed for the Rendezvous AIO is the entire ROP, as proposed, which is within the following land: I Imint Moririian Township Range Sections 4-5: All 8: NE1/4 T8N R1E 9: N1/2 1-3: All 4: N1/2, SE1/4 10: N1/2, SE1/4 11-14: All 15: NE1/4, S1/2 21: NE1/4, S1/2 22-28: All 29: NE1/4, S1/2 T9N R1E 32-36: All 1-10: All 11-12: N1/2 15: W1/2 16-21: All 22: W1/2 T9N R2E 29-32: All 5: W1/2 6: All 7: N1/2 T9N R3E 8: NW1/4 1-4: All 5: E1/2 8: NE1/4 9-12: All 13-15: N1/2 T1ON R1W 16: NE1/4 1-17: All 18: N1/2 20: E1/2 21-28: All 29: E1/2 32: E1/2 T10N R1 E 33-36: All CPAI Application for Area Injection Order, Rendezvous Oil Pool April 12, 2021 Pa e9of50 9 W1/4, S1/2 : All NW1/4, S1/2 S1/2 T10N R2E 36: All 19: W1 /2 NW1/4, S1/2 All T10N R3E SW1/4 S1/2 !19:SE1/4 S1/2 T11 N R1 W 36: All E1/4 S1/2 SW1A S1/2 -16: All : SE1/4 : SE1/4 20-29: All 30: NE1/4, S1/2 T11N R1E 31-36: All 18: S1/2 19-20: All 21: SW1/4 :1 27: SW1/4 28-33: All T11N R2E 34: W1/2 Pool Definition Injection of fluids for enhanced recovery is proposed for the correlative interval shown in Figure F-1, known as the ROP. Within the requested areal extent, the ROP is defined as the accumulation of hydrocarbons common to and correlating with the interval between the measured depths of 8,229 feet and 8,393 feet (-8,104 feet and - 8,258 feet TVDss respectively) in the Rendezvous 2 well. CPAI Application for Area Injection Order, Rendezvous Oil Pool April 12, 2021 Page 10 of 50 SECTION G — FORMATION GEOLOGY 20 AAC 25.402(c)(6) 20 AAC 25.402(c)(6) - An application for injection must include the name, description, depth, and thickness of the formation into which fluids are to be injected, and appropriate geological data on the injection zone and confining zone, including lithologic descriptions and geologic names. Stratigraphy and Sedimentology The ROP is a hydrocarbon accumulation formed by a stratigraphic trap of the shallow marine Upper Jurassic Alpine sandstone. The Alpine sandstone unconformably overlies the Kingak Shale and underlies the Miluveach Formation. Within the ROP the Alpine sandstone can be subdivided into the Alpine C and Alpine D intervals. The Alpine C interval consists of nearshore transgressive sands infilling the paleotopography created by incision of the regionally extensive Upper Jurassic Unconformity (UJU). The Alpine D interval conformably overlies the Alpine C sands and is characterized by interbedded siltstones and argillaceous sandstones that represent distal deposition of the transgressive sequence. The Alpine C interval contains reservoir quality sands and is the development target within the ROP. Figure G-1 is a cross-section from the northern Spark 4 southward to the Carbon 1, Rendezvous A, Rendezvous 2, and Altamura 1 wells highlighting the Alpine interval. A type log of the full stratigraphic column is shown in Figure G-2. Structure Within the proposed pool area, the top of the Alpine sand (D interval) lies between -7,474 feet and -8,613 feet TVDss, and the top of the UJU lies between -7,474 feet and -8,617 feet TVDss. The reservoir dips approximately 1 degree to the south with local variations fluctuating between 0 and 2-degree dip, generally southward. Structurally, the Rendezvous incision was developed during base -level fall associated with an uplift of the Beaufortian rift shoulder. The structure map of the UJU (Figure G-3) shows the area of incision with the current regional dip to the south. Within the ROP, the Alpine A interval has been completely removed by the UJU which has incised into the Kingak interval below. There is one set of seismically mapped normal faults present in the proposed development area, and another set to the north of the proposed development area, both of which are interpreted to be Early Cretaceous in age (Figure G-3). The set of faults within the development area are on the eastern extent of the development, with a general NNE -SSW strike, and normal throws (both down to the east and west) of 30 feet to 50 feet. With an estimated gross sand thickness of 80 feet to 100+ feet, reservoir compartmentalization is not expected. To the north of the proposed development area a set of faults trend WNE-ESE with normal, down to the south throws of 5 feet to 30 feet. Similar to the eastern faults, with an estimated reservoir thickness of 90 feet to 120 feet in the area, no reservoir compartmentalization is expected. Trap Configuration and Seals The hydrocarbon accumulation in the ROP area is formed by a stratigraphic trap of the shallow marine, Upper Jurassic Alpine sandstone. The Alpine sandstone unconformably overlies the Kingak Shale and underlies the Miluveach Formation. The Kingak formation below and Miluveach, Kalubik, and Highly Radioactive Zone (HRZ) shales above provide the seal for the Alpine sandstone. Reservoir Compartmentalization Reservoir compartmentalization is not expected in the ROP. In cored wells, extensive bioturbation has homogenized the reservoir removing any stratigraphic barriers. It is interpreted that this bioturbation is extensive throughout the Alpine Rendezvous deposit. Where observed on seismic data, faulting in the pool does not have adequate offset to isolate portions of the reservoir. CPAI Application for Area Injection Order, Rendezvous Oil Pool April 12, 2021 Page 11 of 50 Permafrost Base The base of permafrost is interpreted to lie between -800 feet to -1,200 feet TVDss within the proposed development area. Reservoir Fluids and Contacts No water contacts have been encountered or interpreted within the ROP. None of the exploration or development wells drilled within the CRU or the GMTU have encountered an oil -water contact (OWC) in Jurassic -aged sands. As a result, an OWC is not expected within any portion of the proposed ROP. There is a gas -oil contact (GOC) present in the ROP and it is currently estimated at -8,108 feet TVDss based on fluid pressure gradients observed in modular formation dynamics testing (MDT) data from the Rendezvous A and Rendezvous 3 wells. The GOC informs the northern oil boundary within the ROP and is reflected in the net pay map shown in Figure 14 (Confidential, Appendix 1). Confidential seismic, sedimentologic, and net -reservoir interpretations supporting this application are provided in Appendix 1. CPAI Application for Area Injection Order, Rendezvous Oil Pool April 12, 2021 Page 12 of 50 SECTION H — LOGS OF INJECTION WELLS 20 AAC 25.402(c)(7) 20 AAC 25.402(c)(7) - An application for injection must include the logs of the injection wells if not already on file with the commission. To date, no injection wells have been drilled. Well MT7-04 is planned as the first injection well in the ROP with spud estimated in April 2021. The logs associated with the drilling and completion of this wellbore will be filed with the AOGCC once available and as required. CPAI Application for Area Injection Order, Rendezvous Oil Pool April 12, 2021 Page 13 of 50 _ SECTION I — MECHANICAL INTEGRITY OF INJECTION WELLS 20 AAC 25.402(c)(8) 20 AAC 25.402(c)(8) - An application for injection must include a description of the proposed method for demonstrating mechanical integrity of the casing and tubing under 20 AAC 25.412 and for demonstrating that no fluids will move behind casing beyond the approved injection zone, and a description of (A) the casing of the injection wells if the wells are existing; or (B) the proposed casing program, if the injection wells are new. The injection well designs for the ROP are similar to wells in the LOP. A mix of casing designs is anticipated to mitigate hole stability issues through HRZ, Kalubik and Miluveach formations just above the reservoir. The well design may be a three string, four string with conventional intermediate #2, or four string with pipe conveyed steerable drilling liner (SDL) section. The generic well designs can be found in Figures 1-1 and 1-2. Some wells may initially be designed as four string based on expected HRZ slump block presence and thickness. Maintaining stability of the borehole and horizontal geo-steering in the pay zone are keys to success. Surface casing set below the C-5 marker in the Colville Group will be cemented back to surface. Within the planned development area, the base of permafrost is interpreted to lie between -800 feet to -1,200 feet TVDss. For the three string design the intermediate hole will be drilled in one interval with 7-5/8 inch casing back to surface. The surface casing will be upsized to 13-3/8 inches on initial three string wells to provide the contingency to sidetrack and convert to a four string casing design. 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, potentially in stages if any hydrocarbon bearing formations are encountered in accordance with 20 AAC 25.030(d)(5). With the four string conventional design the intermediate hole will be broken into two sections with 9-5/8 inch casing from surface set at the top of the HRZ. The top of cement will extend a minimum of 500 feet measured depth or 250 feet true vertical depth, whichever is greater, above the shoe or higher, potentially in stages if any hydrocarbon bearing formations are encountered in accordance with 20 AAC 25.030(d)(5). The intermediate #2 section of the four string conventional design will be run from the HRZ to the Alpine C sand and will be drilled and completed with a 7 inch liner. If hole instability is too severe the interval will be drilled via SDL, which is a liner that is carried into hole behind a directional drilling and logging pilot assembly that is retrieved prior to cementing. 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 Alpine C sand in accordance with 20 AAC 25.030(d)(5) or higher based on the production packer setting depth. The production section is planned as a single lateral, geo-steered to stay in the Alpine C and will be unlined. If out of pay excursions and / or fault crossings occur, a liner with external swell packers to isolate these sections may be run. In lieu of the packer depth requirement under 20 AAC 25.412(b), CPAI requests the packer/isolation equipment depth for injection wells may be located greater than 200 feet measured depth from above the top of the perforations/open interval but shall not be located above the confining zone and shall have outer casing cement volume sufficient to place cement a minimum of 300 feet measured depth above the planned packer depth. This will accommodate efficient wireline operations down to the pressure isolation equipment. The tubing/casing annulus pressure of each injection well will be tested in accordance with 20 AAC 25.412(c). Drilling and completion operations will be performed in accordance with 20 AAC 25. In accordance with 20 AAC 25.412(d), cement quality logs, or other data approved by the AOGCC, will be provided for all injection wells to demonstrate isolation of the injected fluids to the approved interval. CPAI Application for Area Injection Order, Rendezvous Oil Pool April 12, 2021 Page 14 of 50 SECTION J — INJECTION FLUIDS 20 AAC 25.402(c)(9) 20 AAC 25.402(c)(9) - An application for injection must include a statement of the type of fluid to be injected, the fluid's composition, the fluid's source, the estimated maximum amounts to be injected daily, and the fluid's compatibility with the injection zone. The ROP will be developed with water injection followed by cycles of enriched gas, known as EWAG. Primary injected fluids are seawater and enriched gas from the ACF. The seawater and enriched gas will be the same as is injected into other GMTU and CRU pools. Produced water may be injected in the future. Other fluids may also be injected for reservoir stimulation, reservoir performance evaluation, freeze protection, chemical inhibition or to otherwise ensure efficient and safe operation of the wells in the ROP; however, these fluids are not planned for continuous injection as a means for enhanced recovery. The volumes of these other fluids are expected to be de minimis and are not expected to hinder the recovery efficiency or performance of the proposed ROP. Types and sources of fluids requested for injection are (compositions included for fluids that may be dedicated injection fluids): • Source water from the Kuparuk seawater treatment plant (composition listed in Figure J-1) • Produced water from the ACF (recent ACF produced water composition in Figure J-2) • Enriched hydrocarbon gas from the ACF (composition listed in Figure J-3) • Lean gas from the ACF (ACF composition listed in Figure J-4) • Tracer survey fluids to monitor reservoir performance (chemical, radioactive, etc.) • Fluids used to improve near wellbore injectivity (via use of acid or similar treatment) • Fluids used to seal wellbore intervals which negatively impact recovery efficiency (cement, resin, etc.) • Fluids associated with freeze protection (diesel, crude, glycol, methanol, etc.) • Standard oilfield chemicals (corrosion inhibitor, scale inhibitor, etc.) • Small amounts of Class 11 fluids, which will be mixed with the source or produced water including: sump fluid, hydrotest fluid, rinsate generated from washing trucks, excess well work fluids, meltwater collected from well cellars. Fluid Compatibility The primary and miscellaneous fluids listed above are expected to be compatible with the ROP as has been demonstrated by performance in the analog Alpine Oil Pool (AOP) and LOP. Moderate barium sulfate scale formation in production wells, as has been experienced to various degrees in GMTU and CRU pools, is possible due to the mixing of seawater (containing sulfate, SO4) and formation connate water (containing barium, BA). A scale inhibition treatment program, like that performed in GMTU and CRU pools, will be performed at ROP as required. Injection Volumes Injection will proceed in a manner to maintain reservoir voidage to a value of 1.0. Alternating cycles of injected water and gas will be managed to maximize oil production and minimize any extreme returns of the injected fluids. Injection rates will be limited by injection pressures in order to not exceed the overburden pressure gradient and cause fractures to penetrate through the confinement layer. Injection rates for the ROP injection wells are expected to typically be in the range of 1,000 to 15,000 barrels of water per day (BWPD) and 1 to 15 million standard cubic feet per day (MMSCFD). CPAI Application for Area Injection Order, Rendezvous Oil Pool April 12, 2021 Pane 15 of 50 SECTION K — INJECTION PRESSURES 20 AAC 25.402(c)(10) 20 AAC 25.402(c)(10) - An application for injection must include the estimated average and maximum injection pressure. Maximum estimated surface water and gas injection pressures are 2,850 psi and 4,200 psi, respectively. Maximum surface pressures are based on the ACF pump discharge pressure for water and gas. These pressures are unlikely to be realized at the MT7 drillsite. Average estimated surface water and gas injection pressures are 2,650 psi and 4,000 psi, respectively. These are the expected pressures at the MT7 drillsite header accounting for pressure drop in the pipeline system. CPAI Application for Area Injection Order, Rendezvous Oil Pool April 12, 2021 Page 16 of 50 SECTION L — FRACTURE INFORMATION 20 AAC 25.402(c)(11) 20 AAC 25.402(c)(11) - An application for injection must include evidence to support a commission finding that each proposed injection well will not initiate or propagate fractures through the confining zones that might enable the injection fluid or formation fluid to enter freshwater strata. In the ROP area, the Alpine C is over and underlain by laterally and vertically extensive, ductile shales and silts that provide a confining barrier to isolate formation and injected fluids within the Alpine C. The overlying strata of the HRZ, Kalubik and Miluveach range in thickness from 680 feet to 1,630 feet. Approximately 1,700 feet of Kingak underlies the pool (Figure L-1). Historical injection experience in the analog AOP and LOP Alpine C sand verifies the competency of the confining zones. Fracture gradient analysis has been calibrated with rock mechanical properties from analog core data and drilling leak off tests in the overlying shales. Data indicates overlying intervals have fracture gradients of 0.85 psi/ft or higher. By analog rock properties, the underlying Kingak shale is expected to have a similar fracture gradient. Fracture gradient in the Alpine C interval is approximately 0.65 psi/ft. To ensure containment of fluids within the ROP, CPAI recommends a rule limiting injection pressure to a maximum injection gradient of 0.81 psi/ft. CPAI conducted a containment analysis that verified the 0.81 psi/ft injection gradient will not initiate or propagate fractures through the upper and lower confining strata. The analysis involved the use of fracture modelling software with inputs based on the Rendezvous 2 well logs. Figure L-2 and L-3 show results of the simulated injection of 10 million barrels of water, at a rate of 15,000 barrels per day, into a vertical well at bottomhole injection pressures above 0.81 psi/ft. The Figures show the fracture growth is contained within the strata modeled. The simulations of the water injection cases indicate that fracture growth is contained within the Pool without risk of breaking through overburden or underburden containment zones for a gradient below 0.81 psi/ft. The fracture modelling software used was version 9.1.3.57of Grid Oriented Hydraulic Fracture Extension Replicator (GOHFER), due to its reliability and common use within CPAI as well as in the fracturing industry. GOHFER is a planar 3-D geometry fracture simulator developed by Barree & Associates in association with Stim-lab and is commercially available throughout the industry for performing hydraulic fracture simulation work. FreshwaterAguifers in the GMTU (Figure L-4) There are no freshwater or underground sources of drinking water in the ROP area. Data from multiple wells in the ROP and surrounding area indicate shallow water salinities below the permafrost are in excess of 10,000 ppm. In the GMTU. ROP 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. Within the Rendezvous Pool sands penetrated include: K-3, K-2, Albian 97, Albian 96, Albian 95, and Albian 94 with depths ranging from 2933 ft to 3941 ft TVDSS. Salinity calculations made on the available intervals within the Rendezvous pool are shown in the table below and Figure 15. Zone Rendezvous 2 K-3 Rendezvous 2 K-2 Rendezvous 2 Albian 97 Rendezvous A Albian 96 Spark 1 Albian 95 Rendezvous 3 Albian 94 3056-3170 ft 18,00oppm 3331-3406 ft 16,000ppm 3554-3640 ft 18,000ppm 3655-3699 ft 17,000ppm 3820-3853 ft 24,000ppm 3916-4045 ft 13,000ppm In addition to wells within the Rendezvous Pool, a regional investigation was done to investigate additional sands and further verify formation salinity. No clean, porous sands with calculated salinities of less than 10,000 ppm TDS were present below the permafrost zone regionally. Sands penetrated include: C-40, C-30, K-3, K-2, CPAI Application for Area Injection Order, Rendezvous Oil Pool April 12, 2021 Page 17 of 50 Albian 97, Albian 96, Albian 95, and Albian 93. Salinity calculations made on the available intervals within the Rendezvous pool region are shown in the table below. Mitre 1 P61 C-40 1700-1860 ft 31,0ouppm Mitre 1PB1 C-30 2248-2276 ft 27,OOOppm Ti0miaq 2 K-3 2380-2500 ft 14,OOOppm Flat Top 1 K-2 3814-3840 ft 13,OOOppm Flat Top 1 Albian 97 4030-4160 ft 13,OOOppm Lookout 2 Albian 96 4100-4200 ft 17,OOOppm Lookout 1 Albian 95 4400-4459 ft 16,OOOppm Ti9miaq 6 Albian 93 3240-3260 ft 17,OOOppm 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 Rwa value using the following formula: 0m x R, Rwa — a Rwa Resistivity of water necessary to make a zone 100% water bearing 0 Porosity in decimal from logs Rt Formation resistivity from logs m Cementation exponent a Tortuosity (assumed to be 1.0 per Archie correlation) There is no cementation exponent information from the wells used for this study but such data does exist in the CD2-11 Qannik well. This Qannik well is the analog for the wells used for this study. Formation data from the CD2-11 shows m to be 1.8, hence range of 1.8-2.0 was used for the analysis that follows. For very shallow unconsolidated formation intervals, C40 and C30, an m value of 2 was used in the calculations. Well: Mitre 1PB1 Formation: C40 (Well depth 1700-1860ft) Calculation: Rt is taken from LWD resistivity tool and Porosity comes from the density log Rt = 1.86ohm-m, Raw density = 2.01g/cc, m = 2, Porosity = (2.65-2.01)/(2.65-1) = 0.388v/v. The calculation yields a Rwa equal to 0.28. Using chart Gen-9 from Schlumberger chart books with a formation temperature of 52degF, gives a salinity of 31,000 ppm NaCl equivalent. Well: Mitre 1PB1 Formation: C30 (Well depth 2248-2276ft) Calculation: Rt is taken from LWD resistivity tool and Porosity comes from the density log Rt = 3.43ohm-m, Raw density = 2.19g/cc, m = 2, Porosity = (2.65-2.19)/(2.65-1) = 0.279v/v. The calculation yields a Rwa equal to 0.267. Using chart Gen-9 from Schlumberger chart books with a formation temperature of 62degF, gives a salinity of 27,000 ppm NaCl equivalent. Well: Tinmiaq 2 Formation: K3 (Well depth 2380-2500ft) Calculation: Rt is taken from Array Induction tool and Porosity comes from the density log. Rt = 3.75ohm-m, Raw density = 2.15g/cc, m =1.8, Porosity = (2.65-2.15)/(2.65-1) = 0.303v/v. The calculation yields a Rwa equal to 0.437. Using chart Gen-9 from Schlumberger chart books with a formation temperature of 89.7degF, gives a salinity of 11,500 ppm NaCl equivalent. Well: Flat top 1 Formation: K2 (Well depth 3814-3840ft) Calculation: Rt is taken from LWD resistivity tool and Porosity comes from the density log CPAI Application for Area Injection Order, Rendezvous Oil Pool April 12, 2021 Page 18 of 50 Rt = 5.440hm-m, Raw density = 2.29g/cc, m =1.8, Porosity = (2.65-2.29)/(2.65-1) = 0.218v/v. The calculation yields a Rwa equal to 0.351. Using chart Gen-9 from Schlumberger chart books with a formation temperature of 100degF, gives a salinity of 13,000 ppm NaCl equivalent. Well: Flat Top 1 Formation: Albian 97(Well depth 4030-4160ft) Calculation: Rt is taken from LWD resistivity tool and Porosity comes from the density log Rt = 6.46ohm-m, Raw density = 2.33g/cc, m =1.8, Porosity = (2.65-2.33)/(2.65-1) = 0.194v/v. The calculation yields a Rwa equal to 0.337. Using chart Gen-9 from Schlumberger chart books with a formation temperature of 100degF, gives a salinity of 13,000 ppm NaCl equivalent. Well: Lookout 2 Formation: Albian 96 (Well depth 4100-4200ft) Calculation: Rt is taken from LWD resistivity tool and Porosity comes from the density log Rt = 4.92ohm-m, Raw density = 2.33g/cc, m =1.8, Porosity = (2.65-2.33)/(2.65-1) = 0.194v/v. The calculation yields a Rwa equal to 0.257. Using chart Gen-9 from Schlumberger chart books with a formation temperature of 105degF, gives a salinity of 17,000 ppm NaCl equivalent. Well: Lookout 1 Formation: Albian 95 (Well depth 4400-4459ft) Calculation: Rt is taken from LWD resistivity tool and Porosity comes from the density log Rt = 5.21ohm-m, Raw density = 2.306g/cc, m =1.8, Porosity = (2.65-2.306)/(2.65-1) = 0.208v/v. The calculation yields a Rwa equal to 0.310. Using chart Gen-9 from Schlumberger chart books with a formation temperature of 89.7degF, gives a salinity of 16,000 ppm NaCl equivalent. Well: Rendezvous 3 Formation: Albian 94 (Well depth 3916-4045ft) Calculation: Rt is taken from LWD resistivity tool and Porosity comes from the density log Rt = 6.05ohm-m, Raw density = 2.31g/cc, m =1.8, Porosity = (2.65-2.31)/(2.65-1) = 0.206v/v. The calculation yields a Rwa equal to 0.352. Using chart Gen-9 from Schlumberger chart books with a formation temperature of 98degF, gives a salinity of 13,000 ppm NaCI equivalent. Well: Tigmiaq 6 Formation: Albian 93 (Well depth 3240-3260ft) Calculation: Rt is taken from Array Induction tool and Porosity comes from the density log Rt = 4.74ohm-m, Raw density = 2.30g/cc, m =1.8, Porosity = (2.65-2.30)/(2.65-1) = 0.212v/v. The calculation yields a Rwa equal to 0.291. Using chart Gen-9 from Schlumberger chart books with a formation temperature of 89degF, gives a salinity of 17,000 ppm NaCl equivalent. Well: Rendezvous A Formation: Albian 96 (Well depth 3655-3699ft) Calculation: Rt is taken from Array Induction tool and Porosity comes from the density log Rt = 6.454ohm-m, Raw density = 2.35g/cc, m =1.8, Porosity = (2.65-2.35)/(2.65-1) = 0.18v/v. The calculation yields a Rwa equal to 0.3. Using chart Gen-9 from Schlumberger chart books with a formation temperature of 86degF, gives a salinity of 17,000 ppm NaCl equivalent. Well: Rendezvous 2 Formation: K-3 (Well depth 3056-3170ft) Calculation: Rt is taken from Array Induction tool and Porosity comes from the density log Rt = 5.5 ohm-m, Raw density = 2.24g/cc, m = 2, Porosity = (2.65-2.24)/(2.65-1) = 0.25v/v. The calculation yields a Rwa equal to 0.34. Using chart Gen-9 from Schlumberger chart books with a formation temperature of 72degF, gives a salinity of 18,000 ppm NaCl equivalent. CPAI Application for Area Injection Order, Rendezvous Oil Pool April 12, 2021 Page 19 of 50 Formation: K-2 (Well depth 3331-3406ft) Calculation: Rt is taken from Array Induction tool and Porosity comes from the density log Rt = 4.8 ohm-m, Raw density = 2.26g/cc, m = 2, Porosity = (2.65-2.26)/(2.65-1) = 0.24v/v. The calculation yields a Rwa equal to 0.36. Using chart Gen-9 from Schlumberger chart books with a formation temperature of 78degF, gives a salinity of 16,000 ppm NaCl equivalent. Formation: Albian 97 (Well depth 3554-3640ft) Calculation: Rt is taken from Array Induction tool and Porosity comes from the density log Rt = 5.5 ohm-m, Raw density = 2.32g/cc, m = 1.8, Porosity = (2.65-2.32)/(2.65-1) = 0.20v/v. The calculation yields a Rwa equal to 0.30. Using chart Gen-9 from Schlumberger chart books with a formation temperature of 83degF, gives a salinity of 18,000 ppm NaCl equivalent. Well: Spark 1 Formation: Albian 95 (Well depth 3820-3853ft) Calculation: Rt is taken from Array Induction tool and Porosity comes from the density log Rt = 5.54ohm-m, Raw density = 2.38g/cc, m =1.8, Porosity = (2.65-2.38)/(2.65-1) = 0.16v/v. The calculation yields a Rwa equal to 0.21. Using chart Gen-9 from Schlumberger chart books with a formation temperature of 90degF, gives a salinity of 24,000 ppm NaCl equivalent. Water sample analyses A water sample was obtained from Tipmiaq 6 well during a production test. The tested interval is 3440 to 3460 feet (Albian 93 interval) and lab measured salinity is 15,OOOppm (conductivity of 25200 ps/cm). CPAI Application for Area Injection Order, Rendezvous Oil Pool April 12, 2021 Page 20 of 50 SECTION M — FORMATION WATER QUALITY 20 AAC 25.402(c)(12) 20 AAC 25.402(c)(12) - An application for injection must include a standard laboratory water analysis, or the results of another method acceptable to the commission, to determine the quality of the water within the formation into which fluid injection is proposed. There is no known free water level within the ROP and therefore no analysis of native formation water is available. Similarly, there is no free water level in the LOP or AOP to provide an analysis of Jurassic water. CPA[ Application for Area Injection Order, Rendezvous Oil Pool April 12, 2021 Page 21 of 50 SECTION N — AQUIFER EXEMPTION 20 AAC 25.402(c)(13) 20 AAC 25.402(c)(13) - An application for injection must include a reference to any applicable freshwater exemption issued under 20 AAC 25.440. There have been no freshwater exemptions issued under 20 AAC 25.440 in the ROP area. There are no known freshwater aquifers in the ROP area as provided in Section L of this application. CPAI Application for Area Injection Order, Rendezvous Oil Pool April 12, 2021 Page 22 of 50 SECTION O — HYDROCARBON RECOVERY 20 AAC 25.402(c)(14) 20 AAC 25.402(c)(14) - An application for injection must include the expected incremental increase in ultimate hydrocarbon recovery. There is a GOC present in the north of the ROP but it has not been directly intersected by a wellbore to date. The GOC is currently estimated at -8,108 feet TVDss based on MDT pressure data from the Rendezvous A and Rendezvous 3 wells. The main intent of the GMT2 project is to avoid drilling into or producing from the gas cap as commercial production from the gas cap is not intended and high GOR wells will not be competitive with ACF gas handling constraints. The first northern injector will target the gas cap at the toe of the wellbore to intersect and confirm the GOC depth. Other northern production and injection wells will stay below and offset from the gas cap to minimize the potential for gas cap production and injection. Fracture stimulations will be offset laterally to avoid stimulating into the gas cap. The 1,200 foot well spacing will promote a preferential pressure gradient between northern injection and production wells, which are planned to be drilled proximal to the base of the reservoir. This pressure gradient is supported by simulation work, and is expected to limit the volume of water injection that displaces into the gas cap. The southern wells are not expected to encounter the gas cap due to the dipping structure. A voidage replacement ratio of 1.0 is targeted to avoid production from the gas cap. The oil rim development is designed to minimize gas coning and manage the GOR. The ACF is limited in total gas processing capacity, and the potential for elevated GOR could impair GMT2 offtake and ultimate recovery. As the field reaches maturity, a lean gas chase could be considered. Dry gas injection into the gas cap was considered as a potential enhanced oil recovery (EOR) method for ROP development. In this case the low permeability of the ROP impedes high recovery from a gravity drainage system. CPAI analysis shows that the gravity stable offtake rate for ROP is too low for economic development. 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. Pressure support will be maintained with water and gas injection targeting a cumulative voidage replacement ratio of 1.0. The historical success of the secondary and tertiary recovery mechanisms in the Alpine C sand of the CRU provides an analog for the expected performance in the ROP. The favorable rock properties and waterflood mobility for the proposed ROP yield an ultimate EWAG recovery that will be in the range of 35% to 60% of original oil in place (OOIP). Uncertainty factors that may impact the recovery estimate include facies distribution, net pay, voidage replacement, well productivity, and OOIP. The EWAG flood 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 20%. The remaining 15% to 40% of the ultimate recovery is expected through secondary and tertiary mechanisms with EWAG injection. The low viscosity oil of the proposed ROP 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. Other development scenarios including vertical well waterflood, horizontal waterflood only, and dry gas injection into the gas cap were also evaluated by CPAI however the horizontal EWAG development yields the maximum ultimate recovery. A slim tube study was performed to examine minimum miscibility enrichment composition and pressure. This work suggests that the first displacement is expected to be miscible, with later displacements being sub - miscible. However, enriched gas field composition has more recently been sub -miscible; thus, current expectations are for all slugs to be sub -miscible in the field. CPAI Application for Area Injection Order, Rendezvous Oil Pool April 12, 2021 Page 23 of 50 SECTION P — CONFINEMENT IN OFFSET WELLS 20 AAC 25.402(c)(15) 20 AAC 25.402(c)(15) - An application for injection must include a report on the mechanical condition of each well that has penetrated the injection zone within a one -quarter mile radius of a proposed injection well. Two exploration wells shown in Figure A-2 penetrate the ROP within a one -quarter mile radius of a proposed injection well. Rendezvous 2 was drilled and cased with tubing completion run in 2001, then suspended. In February and March of 2008, the well was fracture stimulated and flow tested with full plug and abandonment completed April 8, 2008. Rendezvous 3 was drilled and completed in winter of 2014. After the rig moved out the well was fracture stimulated and flow tested. Post testing, the well was secured with a downhole tubing plug, kill weight fluid with freeze protect in the tubing and production casing, tubing and inner annulus pressure tested, back pressure valve installed in tubing hanger and valve removal plugs in wellhead casing valves. Operations were suspended March 18, 2014. CPA[ Application for Area Injection Order, Rendezvous Oil Pool April 12, 2021 Page 24 of 50 SECTION Q — PROPOSED AREA INJECTION ORDER RULES The rules set forth apply to the following area referred to in this order: I ]mint Mpridinn Township Range Sections 4-5: All 8: NE1/4 T8N R1E 9: N1/2 1-3: All 4: N1/2, SE1/4 10: N1/2, SE1/4 11-14: All 15: NE1/4, S1/2 21: NE1/4, S1/2 22-28: All 29: NE1/4, S1/2 T9N R1 E 32-36: All 1-10: All 11: N1/2 12: N1/2 15: W1/2 16-21: All 22: W1/2 T9N R2E 29-32: All 5: W1/2 6: All 7: N1/2 T9N R3E 8: NW1/4 1-4: All 5: E1/2 8: NE1/4 9-12: All 13: N1/2 14: N1/2 15: N1/2 T10N R1W 16: NE1/4 1-17: All 18: N1/2 20: E1/2 21-28: All 29: E1/2 32: E1/2 T10N R1 E 33-36: All 3: NW1/4, S1/2 4-10: All 11: NW1/4, S1/2 12: S1/2 T10N R2E 13-36: All CPAI Application for Area Injection Order, Rendezvous Oil Pool April 12, 2021 Page 25 of 50 18: W1/2 19: W1/2 30: NW1/4, S1/2 31: All T10N R3E 32: SW1/4 25: S1/2 33: S1/2 T11N R1 W 34-36: All 9: SE1/4 10: S1/2 11: SW1A 13: S1/2 14-16: All 17: SE1/4 19: SE1/4 20-29: All 30: NE1/4, S1/2 T11N R1E 31-36: All 18: S1/2 19-20: All 21: SW1/4 27: SW1/4 28-33: All T11N R2E 34: W1/2 Rule 1. Authorized Injection Strata for Enhanced Recovery Fluids authorized under Rule 3, below, may be injected for the purposes of pressure maintenance and enhanced hydrocarbon recovery within the proposed Rendezvous Oil Pool (ROP), which is defined as the accumulation of oil and gas common to and correlating with the interval within the Rendezvous 2 well between the measured depths of 8,229 feet and 8,393 feet. Rule 2. Well Construction In lieu of the packer depth requirement under 20 AAC 25.412(b), the packer/isolation equipment depth for injection wells may be located above 200 feet measured depth from above the top of the perforations/open interval but shall not be located above the confining zone and shall have outer casing cement volume sufficient to place cement a minimum of 300 feet measured depth above the planned packer depth. Rule 3. Authorized Fluids for Injection for Enhanced Recovery Fluids authorized for injection are: a. Source water from the Kuparuk seawater treatment plant b. Produced water from the ACF c. Enriched hydrocarbon gas from the ACF d. Lean gas from the ACF e. Tracer survey fluids to monitor reservoir performance (chemical, radioactive, etc.) f. Fluids used to improve near wellbore injectivity (via use of acid or similar treatment) g. Fluids used to seal wellbore intervals which negatively impact recovery efficiency (cement, resin, etc.) h. Fluids associated with freeze protection (diesel, crude, glycol, methanol, etc.) i. Standard oilfield chemicals (corrosion inhibitor, scale inhibitor, etc.) j. Small amounts of Class II fluids, which will be mixed with the source or produced water including: sump fluid, hydrotest fluid, rinsate generated from washing trucks, excess well work fluids, and meltwater collected from well cellars. CPAI Application for Area Injection Order, Rendezvous Oil Pool April 12, 2021 Page 26 of 50 Rule 4. Authorized Injection Pressure for Enhanced Recovery Injection pressures will be managed not to exceed the maximum injection gradient of 0.81 psi/ft to ensure containment of injected fluids within the Rendezvous Oil Pool. Rule 5. Monitoring Tubing -Casing Annulus Pressure The tubing and casing annuli pressures of each injection well must be monitored at least daily, except if prevented by extreme weather condition, emergency situations, or similar unavoidable circumstances. Monitoring results shall be documented and made available for AOGCC inspection. Rule 6. Demonstration of Tubing/Casing Annulus Mechanical Integrity The mechanical integrity of each injection well must be demonstrated before injection begins and before returning a well to service following any workover affecting mechanical integrity. An AOGCC-witnessed mechanical integrity test (MIT) must be performed after injection is commenced for the first time in a well, to be scheduled when injection conditions (temperature, pressure, rate, etc.) have stabilized. Subsequent tests must be performed at least once every four years thereafter. The AOGCC must be notified at least 24 hours in advance to enable a representative to witness an MIT. Unless an alternate means is approved by the AOGCC, mechanical integrity must be demonstrated by a tubing/casing annulus pressure test using a surface pressure of 1,500 psi or 0.25 psi/ft multiplied by the vertical depth of the packer, whichever is greater, that shows stabilizing pressure and does not change more than 10 percent during a 30-minute period. Results of MITs must be readily available for AOGCC inspection. Rule 7. Well Integrity and Confinement Whenever any pressure communication, leakage or lack of injection zone isolation is indicated by an injection rate, operating pressure observation, test, survey, log, or any other evidence, the Operator shall notify the AOGCC by the next business day and submit a plan of corrective action on a Form 10-403 for AOGCC approval. The Operator shall immediately shut in the well if continued operation would be unsafe or would threaten contamination of freshwater. A monthly report of daily tubing and casing annuli pressures and injection rates must be provided to the AOGCC for all injection wells for which well integrity failure or lack of injection zone isolation is indicated. Rule 8. Notification of Improper Class II Injection Injection of fluids other than those listed in Rule 3 without prior authorization is considered improper Class II injection. Upon discovery of such an event, the operator must immediately notify the AOGCC, provide details of the operation, and propose actions to prevent recurrence. This requirement is in addition to and does not relieve the operator of any other obligations under the notification requirements of any other State or Federal agency, regulation or law. Rule 9. Other Conditions If fluids are found to be fracturing the confining zone or migrating out of the approved injection stratum, the Operator must immediately shut in the injection wells and immediately notify the AOGCC. Injection may not be restarted unless approved by the AOGCC. Rule 10. Administrative Action Upon proper application, or on its own motion, and unless notice and public hearing are otherwise required, the Commission may administratively waive the requirements of any rule stated herein or administratively amend this order as long as the change does not promote waste or jeopardize correlative rights, is based on sound engineering and geoscience principles, and will not result in an increased risk of fluid movement into freshwater aquifers. CPAI Application for Area Injection Order, Rendezvous Oil Pool April 12, 2021 Page 27 of 50 List of Acronyms Alaska Oil and Gas Conservation Commission (AOGCC) Alpine Central Facility (ACF) Alpine Oil Pool (AOP) Area Injection Order (AIO) Barrels Water per Day (BWPD) Colville River Unit (CRU) ConocoPhillips Alaska, Inc. (CPAI) Conservation Order (CO) Enriched Water Alternating Gas (EWAG) Extended Reach Drilling (ERD) Gas -Oil Contact (GOC) Greater Moose's Tooth Unit (GMTU) Greater Moose's Tooth 1 (GMT1) Greater Moose's Tooth 2 (GMT2) Grid Oriented Hydraulic Fracture Extension Replicator (GOHFER) Highly Radioactive Zone (HRZ) Lookout Oil Pool (LOP) Managed Pressure Drilling (MPD) Mechanical Integrity Test (MIT) Million Standard Cubic Feet Per Day (MMSCFD) Modular Formation Dynamics Testing (MDT) Moose's Tooth 6 (MT6) Moose's Tooth 7 (MT7) Oil Water Contact (OWC) Original Oil In Place (OOIP) Rendezvous Oil Pool (ROP) Steerable Drilling Liner (SDL) True Vertical Depth Sub -sea (TVDss) Upper Jurassic Unconformity (UJU) Working Interest Owner (WIO) CPAI Application for Area Injection Order, Rendezvous Oil Pool April 12, 2021 Page 28 of 50 List of Figures/Exhibits A-1: DEFINING WELL, RENDEZVOUS 2, HIGHLIGHTING POOL INTERVAL A-2: ROP BOUNDARY WITH PROPOSED AND EXISTING WELLS D-1: AFFIDAVIT G - 1 : A) CROSS SECTION FLATTENED ON TOP ALPINE (ALPINE D) FROM SPARK 4 — CARBON 1 - RENDEZVOUS A — RENDEZVOUS 2 — ALTAMURA 1. B) REFERENCE MAP SHOWS THE CROSS SECTION (RED DASHED LINE) OVER DEPTH MAP OF THE UJU. G-2: RENDEZVOUS AREA STRATIGRAPHIC SECTION — RENDEZVOUS 2 WELL LOG G-3: DEPTH MAP OF THE UPPER JURASSIC UNCONFORMITY (UJU, RESERVOIR BASE) I - 1 PROPOSED THREE STRING RENDEZVOUS INJECTOR WELL DESIGN 1-2: PROPOSED FOUR STRING RENDEZVOUS INJECTOR WELL DESIGN J - 1 : KUPARUK SEAWATER TREATMENT PLANT WATER COMPOSITION J-2: ALPINE FACILITY PRODUCED WATER COMPOSITION J-3: CD5K ENRICHED GAS INJECTANT COMPOSITION J-4: ALPINE FACILITY DRY GAS COMPOSITION L - 1 : RENDEZVOUS 2 LOG, ALPINE FORMATION AND CONFINING INTERVALS L-2: RENDEZVOUS 2 UPPER ZONE WELL CONTAINMENT MODEL RESULTS L-3: RENDEZVOUS 2 LOWER ZONE WELL CONTAINMENT MODEL RESULTS L-4: FORMATION WATER SALINITY SUMMARY WITH THE RENDEZVOUS TYPE LOG (RENDEZVOUS 2) AND LITHOLOGY SUMMARY. APPENDIX 1, CONFIDENTIAL SECTION CPAI Application for Area Injection Order, Rendezvous Oil Pool April 12, 2021 Page 29 of 50 FIGURE A-1: DEFINING WELL, RENDEZVOUS 2, HIGHLIGHTING POOL INTERVAL CPAI Application for Area Injection Order, Rendezvous Oil Pool April 12, 2021 Page 30 of 50 FIGURE A-2: ROP BOUNDARY WITH PROPOSED AND EXISTING WELLS �■ — %C t 5 ConocoPhillips I»n aill •z �— •.. � AlAll- fa ,. , ,a 1 Ifi I 1: u GMT 2r.r '�+ u1i ■r Is ■ uliulr■'.— Rendezvous Oil Pool xx Deve#lopment Plan I ! + 2/15221 SPMK< '.. ..�IfTr>F��.: ' ■ Rfi _ _y �CoiVine T+oe++reaw. uw rv�e�w a°n ..�y TwTvc T°? y +' TT+N U a River --CAi@ox1 3 ° ° n•ITIME ° ON. RiE UM� ' lIN1Y\t] 6 IAA '+ - SMRKI I...... Is nnbluu° Greater Mo05e5 °��.s u I fi n e 1 i Tooth Unit ifi U i o — _�_ � � :a = ■ � v-1�-RENfI¢uWse ti e a -, s i> y .�.....—li_' _Bear___ ■ ._ I a A �UI+ � Tt Al WI 6' T P8A We115 � � \oVFW+ T �I t�� r�Ml.x.l.l .l.l Suspended Wells ' ` n_ ,f3E M n 1 �1.WM1al �- IYIIYAU IYPHI � 3 _ ■ _ Foisting vid Path GMT2 Well PWre '6 I a • n ° s v p _ .. Po O Proposed- . GMT2X We0 Plans Rendezvous il d 1° 3 . a Q DraR Rendezvous PA x ■ '" .- j ...l.l . l• (] Reservoir Bounden' r ,n ' • ,s b m ® Kuul Surface ASRC Suhsurlil m ■I�UNI Boundary �_ "• ` '` " - =--. _..... �. . .�XIIJIU UNeased I Industry lease U� -iery°R y CN. R'F Vid _ CPAI lease um e 1 a M. UV reel rue ut.+ - NPR -A Pad tr. Pip 11 nRoad r:— •■ CPAI Application for Area Injection Order, Rendezvous Oil Pool April 12, 2021 Page 31 of 50 EXHIBIT D-1 STATE OF ALASKA AFFIDAVIT THIRD JUDICIAL DISTRICT Jason C. Parker, on oath, deposes and says: 1. I am a Sr. Land Negotiator employed by ConocoPhillips Alaska, Inc., the designated Operator of the Greater Moose's Tooth Unit, and I have responsibilities within the State of Alaska and personal knowledge of the matters set forth in this affidavit. 2. On April 12, 2021, 1 caused copies of the Rendezvous Area Injection Order application to be provided to the following surface owners and operators of all land within a quarter -mile radius of the proposed injection areas: United States Department of Interior Bureau of Land Management Alaska State Office 222 West 7th Avenue #13 Anchorage, Alaska 99513 Attn: Branch Chief, Energy and Minerals Kuukpik Corporation P.O. Box 89187 Nuiqsut, Alaska 99789-0187 Attention: Joe Nukapigak, President Dated this 12th day of April, 2021. STATE OF ALASKA ss. THIRD JUDICIAL DISTRICT C. Parke SUBSCRIBED AND SWORN to before me this - day of Aprt k 2021. J"� ?.D;0,1 fe), NOTARY PUBLIC IN AND FOR ALASKA My Commission Expires: { I/ 1(o / L 0 L CPAI Application for Area Injection Order, Rendezvous Oil Pool April 12, 2021 Page 32 of 50 FIGURE G-1: A) CROSS SECTION FLATTENED ON TOP ALPINE (ALPINE D) FROM SPARK 4 — CARBON 1 - RENDEZVOUS A — RENDEZVOUS 2 — ALTAMURA 1. B) REFERENCE MAP SHOWS THE CROSS SECTION (RED DASHED LINE) OVER DEPTH MAP OF THE UJU. 1 s _ illftt �IIt'!Il l:tittlilttilit 1, 1111t11111lt11 u 4♦ ! St i' :3 l!!i Ilt(ttt }� tl if It 11, 11111 t!Ittlilllt 4 111-1t11l�! ►t, tt2:: tt11t1! Il t^.i111111111ttt•go t 1 I ;,tr,rt ttatn,,,,r,lu,iietttitliiu i •_ i � 11 7 !r'r 3 titilttl:Il, dill Illlrllllrlrtrllt U CPAI Application for Area Injection Order, Rendezvous Oil Pool April 12, 2021 Page 33 of 50 FIGURE G-2: RENDEZVOUS AREA STRATIGRAPHIC SECTION — RENDEZVOUS 2 WELL LOG Permafrost deville Group (Clay with terbedded silt & minor nds) inushuk Group (K-3 to Albian i; top sets, shallow marine, is/shales and thin fine- ained sands )rok (Albian slope & deep urine shales with inter - added sands) :S Fill RZ/Kalubik/Miluveach Shales (pine C Sandstone (Target) CPAI Application for Area Injection Order, Rendezvous Oil Pool April 12, 2021 Page 34 of 50 FIGURE G-3: DEPTH MAP OF THE UPPER JURASSIC UNCONFORMITY (UJU, RESERVOIR BASE) Fault • Exploration Well Development Well ERD Development Well Reservoir Boundary Proposed Pool Boundary 50' Contour Interval Depth NDss, feet 0 = t0000 1k 1 250 ws 1 t5p00] CPAI Application for Area Injection Order, Rendezvous Oil Pool April 12, 2021 Page 35 of 50 FIGURE 1-1: PRO POPSED THREE STRING RENDEZVOUS INJECTOR WELL DESIGN Top Alpine C 2Or 79 ppt HAO Insulated Conductor OO fees. cernerted to surface 1135 6" L40 OTCAW Surface Cueing@ 2AW M 4-11r 12.60 LAO 111rd563 Packer tuMg Completion. 1) 4-Y" Loading NWe(3813- N1) 2) 4-Y'x 1'Gt10 3) 4•Yr' x P GLIA 4) Produo6on Pacim 5) 4.'/' Landing Nipple (3 75' p) 5) Bal seal for selling packer 7) PerfJoirts 4.11," 12.60 L40 1110553 Haag led win perlJoOna 7-59" 29.70 L40 TN -OOHS TXP 01T Mdc TD C"ng@12.115'MD CPAI Application for Area Injection Order, Rendezvous Oil Pool April 12, 2021 Page 36 of 50 FIGURE 1-2: PROPOSED FOUR STRING RENDEZVOUS INJECTOR WELL DESIGN 20' 79 ppf H40 Mulcted Conductor 50" C*,"Mw to x ext Tutrnp Complxbn: t t 4-4- LwW he *Wk t3 6 t3' ID) 2) 4.v.* x t' GLM 3) 4 h' x l' GLM 4) Produc on Pacasr 5)4-% Landing Nipple $379' N*00) 6) Per' Joins 7) SRs t 3,M' 68 ppt 1.410 ST Cddod Surtaoe Casing J 4.1,2` 12 6 ppi L-80 Hyd563 9 5iB` 435 ppf LU Hyd363 Top)tfpin_ _ CO. ,.` 12 64 L-90 Hyd583 tuMng tin; WO per( joints 7-26 plx L-80 TXP Low „6` � g 85 deg CPAI Application for Area Injection Order, Rendezvous Oil Pool April 12, 2021 Page 37 of 50 FIGURE J-1: KUPARUK SEAWATER TREATMENT PLANT WATER COMPOSITION Sample Number: S-20101"0152 Sample Name: STP Seawater Plant Discharge Location: Area: KUPARUK Unit: STP Sample Point: STP SPD Sampled Date: 10/17/2020 12:16:DOPM Matrix Id: WATER - SEA Reviewed By: Carville, Daniele Date: 10/25/2020 Analysis Results: Test Paralneux Rewk LIOM BACTERIA' ATP ATPASE 2895 RLU DIONEX ICACETATE ACETATE <5.0 me DIONEX IC' BUTYRATE BUTYRATE <5.0 Me DIONEX IC' CHLORIDE CHLORIDE 17024.7 me DiONEX IC' FORMATE FORMATE <5.0 me DIONEX IC' PROPIONATE PROPIONATE <5.0 MCA DIONEX IC' SULFATE SO4(SULFATE) 2353.6 mgA ICP METALS • AL (ALUMINUM) AL(ALUMINUM) 0.00 me ICP METALS' 8 (BORON) B(SORON) 4.01 me ICP METALS' BA (BARIUM) BA(BARIUM) 0.01 me ICP METALS' CA ICALCIUM) CA (CALCIUM) 335.53 me ICP METALS' FE (IRON) FE(IRON) 0.00 me ICP METALS' K (POTASSIUM) K(POTASSIUM) 209.35 me ICP METALS • U (LITHIUM) U(UTMUM) 0.17 Me ICP METALS • MG (MAGNESIUM) MG(MAGNESIUMI 1042-74 me ICP METALS' MN (MANGANESE) MN (MANGANESE) 0.000 me ICP METALS' NA (SODIUM) NA(SODIUM) 9832.59 me ICP METALS' P (PHOSPHORUS) P jPHOSPHORUS) 0.02 me ICP METALS' SI ISIUCON) 51(SILICON) 0.24 me ICP METALS' ER (STRONTIUM) SR (STRONTIUM) 6.95 me ICP METALS • ZN (ZINC) CPAI Application for Area Injection Order, Rendezvous Oil Pool April 12, 2021 Page 38 of 50 FIGURE J-1: KUPARUK SEAWATER TREATMENT PLANT WATER COMPOSITION (CONTINUED) Analysis Results: Test Pamm w Re tt uOm ZN (ZINC) 0.00 mgAl QC ATP ATPASE 224706 RLU 5-2320 ALKALINITY • TOTAL BICARBONATE (HCO3) 138.9 mgA CMBONATE (003) 0.0 mgil 5-2510 • CONDUCTIVITY CONDUCTIVITY 37800 uSJcm S$520 SALINITY • SPGRAV SPECIFIC GRAVITY 1.0218 S-2540TSS' TOT SUSP SOLIDS TOTAL SUSPENDED SOLIDS 97.2 MOO "Soo PH fat • PH PH 737 5-4500SZ-(F)SULFIDE BY TITR SULFIDE <0.5 no CPAI Application for Area Injection Order, Rendezvous Oil Pool April 12, 2021 Page 39 of 50 FIGURE J-2: ALPINE FACILITY PRODUCED WATER COMPOSITION Sample Number: S-200502-00156 Sample Name: Annual AOGCC Produced Water Sampling PM Location: Area: ALPINE Unit: ALP ENV Sample Point: A7AOGCC Sampled Date: 4/30/2020 2:30:OOAM Matrix Id: WATER -PRODUCED Reviewed By: Carville, Daniele Date: 05/05/2020 Analysis Results: Ten Paamet® Rewk UOM DIONEX IC • CHLORIDE CHLORIDE 15715.2 mgp DIONEX IC • SULFATE SO4ISULFATE) 332-3 ffCA ICP METALS • AL (ALUMINUM) AL (ALUMINUM) OM mgjl ICP METALS • B (BORON) S(BORONJ 25.17 W ICP METALS' BA (BARIUM) 84 (BARIUM) 40.70 MIA ICP METALS • CA (CALCIUM) CA[CALCIUM) 16916 myA ICP METALSFE (IRONJ HE (IRON) 037 MLA ICP METALS • X (POTASSIUM) KIPOTASSIUM) 61.71 mg/I ICP METALS • U (UTHRRA) U(UTHIUM) 1-76 ine ICP METALS " MG (MAGNESHUMJ MG(MAGNESIUMI 143E "0 ICP METALS' MN (MANGANESE) MN (MANGANESE} 0:D42 mg/H ICP METALS • NA (SODIUM) NA (SODIUM) 10522.96 mgjl ICP METALS " P (PHOSPNORUSJ P{PHOSPHORUS) 2.63 mCA ICP METALS' St (SIUCON) SI I5IUCON) 1919 m[A ICP METALS " SR (STRONTIUM) SR(STRONTKIMI 14.84 mgA ICP METALS' 2N (ZINC) 771(ZINC) 002 mIIA S.2320 ALXAUNrrY •TOTAL BICARBONIXTE(HCO3) 133&7 mg/I CARBONATE(003) DD MLA 52510• CONDUCTIVTY CONDUCTIVITY 42100 41. S2520 SALINITY • SP GRAY SPECIFIC GRAVITY 10203 S-2540IDS (C) • TOT OISS SOLIDS TOTAL DISSOLVED SOUDS 29704o MSA 44500 PH (B) • PH PH 8.05 CPAI Application for Area Injection Order, Rendezvous Oil Pool April 12, 2021 Page 40 of 50 FIGURE J-3: CD5K ENRICHED GAS INJECTANT COMPOSITION Kuparok Lab Analytical Report ConcooPhillips Alaska Natural Gas Analysis Report GPA 2172.091API 14.5 Report with GPA 2145-16 Physical Properties Sample Information _..._..., .... _.--_- ....... ___--- _._ . _..__....... ... ........ (Sample Information ..._.__._.-._ nple Name 5-201222.00129 lection Dater ime mm-dd-yy hh:mm (24hr) 12-15-20 15:20 it Dale mmdd-yy hh:mm (24hr) NA xtive Date mm-dd-yy hh:mm (24hr) 12.23-20 0000 I Date mmdd-yy hh:mm 124hr) NA Ise # AKAA087852 :ility Name CD5K nple Point SP405115 nple point description Miscible Injection Gas w Cal Designation 70405001 mralory, Kuparuk Laboratory dyst Name Melanie Sindod dyzer Type Gas Chromatagraph ilyzer Make It Model Agilenl7890B Sedat#US19013013 I CalibratiordValidation Date 6.18-20 Temperature DegF 62 w Rate MSCF/Day 8551 1t Trace No e of Sample Spot -Cylinder npling Method F61 and Purge npany Collecting Sample ConcooPhillips Alaska hider ID (Serial Number) PAI Fxplomtlon #B (hod Name NSKGAS_GMT.M ction Date 2020-12-22 16:05,52 Iort Date 2020.12-23 09:56:03 2eporter Configuration File BLM Onshom.Fxdended.GPA 2145-16 GMT Sample 062320.cfgx nce Data File GAS 01240.D on File 20201223-0943445-201222-00128.csv A Phys. Property Data Source GPA Standard 2145.16 (FPS) Componem Results Component'; Raw Nomi Nam Amoum Mole% nethane 72S194 72.0856 ahane 10.4221 10.3029 iropane 12.1978 12.0583 wtens 1.1751 1.1616 ibutane 2.0941 2.0701 aentane 0.4002 03957 pentane 0.3394 0.3356 76 Group 0.1549 0.1531 :7 Group 0.0944 0.0933 :8 Group 0.0267 0.0264 :9 Plus 0.0000 0.0000 :02 0.7422 0.7337 krogen 0.5904 0,5837 'otal: 101.1566 100.0000 CPAI Application for Area Injection Order, Rendezvous Oil Pool April 12, 2021 Page 41 of 50 FIGURE J-4: ALPINE FACILITY DRY GAS COMPOSITION Sample Number. S-200704-00325 Sample Name: Alpine 3rd Stg. HP Suction Gas Location: Area- ALPINE Unit- ALPFAC Sample Point C2STG3S Sampled Date: 7/2/2020 1:30:DOAM Matrix id: GAS -COMPRESSOR Reviewed By: Tappert, Marc Date:07/10/2020 Analysis Results: Test UDM D3945N2(NMOGEN) N2 INMOGEN) 0.648 Mde % D-1945 • C 110N NOMM CARBON INOXIDE D.804 M,xe % D-1945' METHANE MEIIRANE 75.916 Md % D1545'ETHANE ETHANE 91" N d % D-1945' PROPANE PROPANE 9210 Mck% Q1945 • 4BL E 141UTANE 1081 Wit% D-1945' N-BUTANE N-BUTANE L761 Mpb% D-1945. 4PENTANE IFENTANE 0.286 M % 0.1945 • N-PENTANE N-PENTANE 0.246 M % P1945-TOTALC65 TOTAL C65 DAIS M % 61945•TotA c7s TOTAL CIS 0,029 M % 0-1NR5' C6 HEAVIER M HEAVIER 0159 Male% 61945' C8 HEAVIER [B HEAVIN ODSS M % DINS • NET HEAT OF COMBUSTION NET HEAT OF COMB 1173.5 &U/SCF 01945' AVERAGE MOL wT AVERAGE MOLECULAR V✓T 21.53 Lh.] D-1945' SP GRAV IDEAL SPECIFIC GRAY IDEAL 07572 03345' SP GRAV REAL SPECIFIC GRAV REAL 0.7590 DL s • CDMP FAAOR CDMPM%81UTY 0.9961 0IN5 • M/IDEAL CF (DRY) BN/IDEAL CF(DAY) 1295.1 &afSCF O19P5' BTU/REAL CF (DRY) M/REALCF(Oar) 12962 &u/XF 0-1945' BN/REAL CF (SAT) BTU/REALCF(SAT) 1273.5 &u/XF D-T945' BTUfIDEAL CF (SAT) MJIDEAL CF (SAT) 3275.6 &u/SCF Om3NE' PRESSURE UNEPRE55URE 1922 pi ONURE • TEMPERMURE TEMPERATURE 90 Deg CPAI Application for Area Injection Order, Rendezvous Oil Pool April 12, 2021 Page 42 of 50 FIGURE L-1: RENDEZVOUS 2 LOG, ALPINE FORMATION AND CONFINING INTERVALS Very thick and competent shale section above the Alpine (thicker than typical in CRU area) Approximately 1700' of Kingak shale lies below the Alpine Interval (as observed in the W Fish Creek 1 well) w w•1 0. 1u ■.uuu .u• uu. ■r■.r.auuan iv.. of ou for .ovvo.vu usul ua• - af• uu••. u.a of iuoul .u. :u v.:.•ao.o .00ai.avl •. u.a al wo• w ov u a.. ul uu I..•' f.u..uuua u..f .fl. • • .0 avow ... aw........ f. ..0 o s.ol .iii • • ii ii" i •Yv ui uo vosav uau uul • iaausvu of iiiu •a. ui� iv i- uu.f.•uou NUM; •.•. i i - .....000 u• u al o.l wo. • - a i..•........usY .. ufll au. . •..•as oral.• o ou.l uu i uu u.o oaY •v oul . v '.. iu..o vuuY loovl aaa • a uY. •uuovu oY ..6•w *:;:::a n.la- ..f.0 ma• NUNN .......I .ww• • Iw.. •.wa..a.{a.aa. faa.l.{I la.. R I ... .............• u\.un /... e a ii ii itvu{uuw• u oaaal o.. uu uu.v..0 ua Yu wall! ou i oou.a. .•al .aff a.f. vfa••• .Yaf• i.0 ul us v.iu u• Yf aw...l .•a• _ •...fa....w. Y..a•{.I .a1. • Iw.. •...........f• Y {.r.r tl ...• 3 tl • O¢ If.• •a.......Ya.N Y.a.a. al .... • . fff ff.•aaa..{wa{ 1......1 /... a P> I...i..............• I....a.l ..{• M • • 1.\. ......a...../• rf rflf•!• 1•••�. r...f• 1..{a..l .\w• ♦ Y 1... .a.........{a{ If ...1•la ff..a.•..w.•. I..w..Yl .aa• • Cp •.• •aaa\{{..\.... I.....YI H: r . a P^ t. •Y. Y art..O....a. uu o.l.u. ea�. lull uuu•v..u{ o.. as al oo u••. •u.uovo I.w.•al. lfuu.val uuan.. .iii i i uuou.0 u• ua.• i au• Y • Y o .u....uuu• I..aa .\.• Il . p Y�.Y1..�..��.1ry�wJJ/ 1. •..../.fa./..a I.a.• :.{• q i e 11 {a...{.{.\...• w a.. .a• P . q/....a{...a.{ 1 l If •a. _a f a Il {.a...{{...fal 00■ +...■ uu • \ Y u .............. IF CPAI Application for Area Injection Order, Rendezvous Oil Pool April 12, 2021 Page 45 of 50 FIGURE L-4: FORMATION WATER SALINITY SUMMARY WITH THE RENDEZVOUS TYPE LOG (RENDEZVOUS 2) AND LITHOLOGY SUMMARY. Rendezvous Area Type Log — Shallow Salinity Analysis Summary Permafrost �leville Group (Clay with -erbedded silt & minor nds) inushuk Group (K-3 to Albian ; top sets, shallow marine, :s/shales and thin fine- iined sands rok (Albian slope & deep trine shales with inter- dded sands) i Fill Z/Kalubik/Mlluveach Shales ,ine C Sandstone (Target)
