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Home My WebLink AboutCO 793Conservation Order 793 Greater Mooses Tooth Field 1. April 12, 2021 CPAI Application for Pool Rules Rendezvous Oil Pool (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 ORDERS STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION 333 West 7th Avenue Anchorage, Alaska 99501 Re: THE APPLICATION OF ConocoPhillips Alaska, Inc. for an order for classification of a new oil pool and to prescribe pool rules for development of the proposed Rendezvous Oil Pool within the Greater Moose's Tooth and Bear Tooth Units, Greater Moose's Tooth Field IT APPEARING THAT: Docket Number: CO-21-005 Conservation Order No, 793 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 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 defining a new oil pool, the Rendezvous Oil Pool (ROP), within the GMTU and BTU and prescribing rules governing the development and operation of that pool. 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. 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. 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 that lies 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. CO 793 July 13, 2021 Page 2 of 13 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 I 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 Altamum 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 I encountered gas columns, with condensate in the gas. ConocwPhillips GMT 2 • i Rendezvous Oil Pool �: ; ]-=Y'•�'• an •.'mr_ Development Plan Y[7Re21 J = • 4 • f.0 IOOIMt. , a • taVH • t }�, I I •I.., P �anli� ] _ • QIQeNI • ' Ono I Teeth llMtTooth Unit +y j �• m.:pn]w n nYI]p1l!111' ] rw.w 6ifhp WNIPNA • \ • I ui_i� _ GUi7%WW ft.,! I nww :.l [_]Pnpwed Ree]]V•n Ql ®Iu.ePA SurIue ASRC EubeuAau ; � •. • � • ."• :•;. A ; _ I� CPAII••se 'x w — uIWRA Psi Figure 1. Proposed Affected Area (Source: ConocoPhillips Alaska, Inc.) 5. 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 depths of 8,229 feet 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. CO 793 July 13, 2021 Page 3 of 13 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.) CO 793 July 13, 2021 Page 4 of 13 Sandstones within the Alpine C interval are fine to very fine-grained and extensively bioturbated. Porosity values range from 12 to 22 percent and average 15.6 percent, with permeabilities ranging from 0.09 to 4.57 millidarcies and averaging 0.64mD. Water saturation ranges from 30 to 80 percent and averages 49 percent. In general, Alpine C rock quality tends to improve the north toward the Spark and Rendezvous exploratory wells, and it tends to degrade somewhat to the south. Alpine C interval sediments grade conformably upward into the overlying Alpine D interval, which comprises siltstones and argillaceous sandstones that are distal deposits of the transgressive sequence. CPAI requests Alpine D be included in the proposed ROP because the Alpine C and D intervals constitute a continuous, gradational, transgressive sequence. However, the Alpine D is not expected to contribute to pay or to provide a seal for injection operations. The Alpine D, in turn, grades upward into the overlying, confining Miluveach shale. 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 is trapped stratigraphically. Deep marine shales of the Miluveach, Kalubik, and HRZ intervals (in ascending stratigraphic order) form the upper confining zone, which 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. 7. 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 It 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 Jurassic -aged reservoirs. CO 793 July 13, 2021 Page 5 of 13 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): 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 rb/mscf (at saturation pressure) 10. In -Place and Recoverable Reserves 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 1.7to2.8TCF 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. 11. Reservoir Development Drilling Plan: CPAI currently plans to develop the ROP from the 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 wellbores. There is potential for an additional 12 extended reach drilling (ERD) wells, split roughly evenly between producers and injectors. Potential ERD wells will depend, in part, on 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. CO 793 July 13, 2021 Page 6 of 13 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. 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. Reservoir Surveillance Plans: CPAI proposes to meet bottom -hole pressure survey requirements through the following reservoir pressure monitoring plan: a. Static bottom -hole pressure surveys will be conducted in all new injection wells prior to initiating injection. b. Static bottom -hole surveys may be performed on production wells at the discretion of CPAI. c. For annual pressure surveillance, a minimum of one pressure survey will be conducted annually in the oil pool, concentrating on injection wells. d. CPAI proposes the following alternative pressure survey methods: i. Stabilized bottom -hole pressure surveys, ii. Extrapolated from surface pressure on wells with a single phase of fluid in the wellbore, iii. Pressure fall -off measurements, iv. Pressure buildup measurements, V. Multi -rate tests, drill stem tests, vi. Open hole formation tests, vii. Other methods approved by the AOGCC. Pressures will be referenced to calculate GOC of-8,108 feet TVDss. All pressure surveys will be reported annually. 14. 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. CO 793 July 13, 2021 Page 7 of 13 CPAI expects to develop the reservoir using horizontal wells. Production wells will be completed 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%: 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. 15. Metering and Measurement Processes: Well testing and allocation will be conducted with a two-phase well test separator, with all wells being tested at least monthly. Fiscal allocation metering was addressed under Other Order No. 148 issued on December 19, 2018. 16. Waivers: CPAI requested the following waivers: a. Well Spacing: Spacing restrictions of 20 AAC 25.055 be waived for development wells in the proposed ROP to accommodate horizontal, line -drive wells and maximize ultimate recovery. Without prior approval, development wells will not be completed any closer than 500 feet to an external boundary where ownership and/or landownership changes. b. Directional Wellbore Plans: In lieu of the requirements of 20 AAC 25.050(b), permit to drill application(s) shall include: plan view, vertical section, close approach data, and directional data. c. Gas -Oil Ratio (GOR) Exemption: an exemption from the GOR limits of 20 AAC 25.240 to accommodate water -alternating -gas -injection for oil recovery. CONCLUSIONS: 1. Pool Rules are appropriate for CPAI's development of the proposed ROP within the GMTU and BTU. 2. Eliminating spacing restrictions on wellbores within the Affected Area will increase the operator's flexibility in placing wells as the pool is developed and will not affect recovery, promote waste, jeopardize correlative rights, or result in an increased risk of fluid movement into freshwater aquifers. 3. Correlative rights of owners and landowners of offset acreage will be protected by a 500-foot set -back requirement from a property line where landowners and owners are not the same. 4. Water and water -alternating -gas injection into the ROP will preserve reservoir energy and increase ultimate recovery. 5. There are no freshwater aquifers in the proposed Affected Area of the ROP. 6. Annular pressure management is necessary to prevent failure of well integrity and uncontrolled release of fluids or pressure and to minimize threats to human safety and the environment. CO 793 July 13, 2021 Page 8 of 13 7. Granting CPAI's requested Directional Wellbore Plan waiver in lieu of 20 AAC 25.050(b) will ensure equally accurate surveillance of the wellbore to prevent well intersection, compliance with spacing requirements, and protection of correlative rights. 8. A GOR limitation waiver is appropriate because the ROP will be developed as a waterflood and water -alternating -enriched -gas enhanced recovery project. Once pressure maintenance operations commence, GORs should not exceed the limits imposed by 20 AAC 25.240(a). However, before the pressure maintenance operations commence, injectors may he pre -produced to ensure adequate reservoir voidage to accommodate water injection. During this period, there may be wells that exceed the GOR limits. 9. Although the proposed Affected Area extends on to the BTU, the area the CPA] proposes to develop with initial development wells and potential ERD wells lies entirely within the GMTU. 10. CPAI's proposed Administrative Action rule is unnecessary. NOW THEREFORE IT IS ORDERED: Development and operation of the GMTU and BTU Lookout Oil Pool is subject to the following rules and the statewide requirements under 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 - NEIA Section 9 - N 1/2 Sections 10-12 - Nl/2 Township 8 North, Range 2 East Section 4 - W 1/2 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 - N 1/2, SE 1 A Section 10 - N 1/2, SE 1 A Sections 1 I-14 - All Section 15-NEl/4, Sl/2 Section 21 -NEIA Sl/2 Sections 22-28 - All Section 29 - NEIA, Sl/2 Sections 32-36 —All CO 793 July 13, 2021 Page 9 of 13 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 — W 1 /2 Section 6 — All Section 7 — N 1 /2 Section 8—NW1/4 Township 10 North, Range 1 West Sections 1-4 —All Section 5 — E 1 /2 Section 8 — NE 1 A Sections 9-12 — All Section 13 — N 1 /2 Section 14—N1/2 Section 15—N1/2 Section 16—NEIA Township 10 North, Range 1 East Sections 1-17 —All Section 18—N1/2 Section 20 — E 1 /2 Sections 21-28 — All Section 29 — E 1 /2 Section 32 — EI/2 Sections 33-36 — All Township 10 North, Range 2 East Section 3 — NW 1/4, S1/2 Sections 4-10 — All Section 11—NW1/4, SI/2 Section 12—S1/2 Sections 13-36—All CO 793 July 13, 2021 Page 10 of 13 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 A Township 11 North, Range 1 West Section 25 — S1/2 Section 33 — S 1 /2 Sections 34-36 —All Township 11 North, Range 1 East Section 9 — SEl/4 Section 10-S1/2 Section 11 — SW 1 A Section 13 — S 1 /2 Sections 14-16 — All Section 17—SE1A Section 19—SE1A Sections 20-29 — All Section 30—NE1A, S1/2 Sections 31-36 —All Township 11 North, Range 2 East Section 18— S1/2 Sections 19-20 — All Section 21 —SW]/4 Section 27 — S W 1 /4 Sections 28-33 —All Section 34 — W 1/2 Rule 1 Field and Pool Name The field is the Greater Moose's Tooth Field. Hydrocarbons underlying the Affected Area and within the interval identified in Rule 2, below, constitute the ROP. Rule 2 Pool Definition The ROP is defined as the accumulation of oil common to and corcelating with the interval between the measured depths of 8,229 and 8,393 feet on the resistivity log recorded in the Rendezvous 2 well. (See Figure 2, above.) Rule 3 Well Saacine There shall be no restrictions as to well spacing except that no pay shall be opened to a well within 500 feet of an external property line where the owners and landowners are not the same on both sides of the line. CO 793 July 13, 2021 Page 1 I of 13 Rule 4 Drilling Waivers All permit to drill applications for deviated wells within the ROP shall include a plat with a plan view, vertical section, close approach data and a directional program description in lieu of the requirements of 20 AAC 25.050(b). Rule 5 Well Logging and Sampling Requirements a. A suite of petrophysical well logs including, at a minimum, gamma ray, resistivity, neutron porosity, and density porosity logs shall be acquired across the ROP in one well from each drill site. Gamma ray and resistivity curves shall be recorded from base of conductor to total depth in each well. The AOGCC may require additional wells to be logged using one or more petrophysical logging tools. b. A mud log and cutting samples shall be obtained from the base of the conductor through the ROP in at least one well drilled from each drill site. Rule 6 Reservoir Pressure Monitoring a. A bottom -hole pressure survey shall be taken on each well prior to initial injection. b. The operator shall obtain the pressure surveys needed to manage properly the hydrocarbon recovery processes subject to the annual plan outlined in Rule 8, below. At a minimum, a pressure survey shall be acquired from at least one well on each drill site each year. c. The reservoir pressure datum will be -8,108 feet TVDss. d. Pressure surveys may consist of stabilized static pressure measurements at bottom -hole or be extrapolated from surface measurements (single phase fluid conditions), pressure fall -off measurements, pressure buildup measurements, multi -rate test results, drill stem test results, and open -hole formation tests or other methods approved by the AOGCC. e. A Reservoir Pressure Report, Form 10-412, shall be utilized for all surveys; all relevant data shall be attached to the report. The data submitted shall include, at a minimum, rate, pressure, depth, fluid gradient, temperature, and all other well conditions necessary for a complete analysis of each survey being conducted. f. The results and data from any special reservoir pressure monitoring tests or surveys shall also be submitted in accordance with paragraph (e) of this rule. Rule 7 Gas -Oil Ratio Exemption Wells producing from the ROP are exempt from the GOR limits of 20 AAC 25.240(a) as long as CPAI is engaged in enhanced recovery operations. An enhanced recovery operation must be initiated within 12 months of the issuance of this order. CO 793 July 13, 2021 Page 12 of 13 Rule 8 Annual Reservoir Review a. An annual reservoir surveillance report must be filed by April V of each year and include future development plans, reservoir depletion plans, and surveillance information for the prior calendar year, including: i. The voidage balance, by month, of produced fluids and injected fluids and the cumulative status for each producing interval; ii. A reservoir pressure map at datum, and a summary and analysis of the reservoir pressure surveys within the pool; iii. The results and, where appropriate, an analysis of production and injection log surveys, tracer surveys, observation well surveys, and any other special monitoring; iv. A review of pool production allocation factors and issues over the prior year; V. A review of the progress of the enhanced recovery project; and vi. A reservoir management summary, including results of any reservoir simulation studies. Rule 9 Sustained Casing Pressure for Production Wells a. At the time of installation or replacement, the operator shall conduct and document a pressure test of tubulars and completion equipment in each production well that is sufficient to demonstrate that planned well operations will not result in failure of well integrity, uncontrolled release of fluid or pressure, or threat to human safety. b. The operator shall monitor each production well daily to check for sustained pressure, except if prevented by extreme weather conditions, emergency situations, or unavoidable circumstances. Monitoring results shall be kept available for AOGCC inspections. c. The operator shall notify the AOGCC within three working days after the operator identifies a well as having: (i) sustained inner annulus pressure that exceeds 2,000 pounds per square in gauge (psig) for all production wells, or (ii) sustained outer annulus pressure that exceeds 1,000 psig. d. If the operator identifies sustained pressure in the inner annulus of a production well that exceeds 45 percent of the burst pressure rating of the well's production casing for inner annulus pressure, or sustained pressure in the outer annulus that exceeds 45 percent of the burst pressure rating of the well's surface casing for outer annulus pressure, the operator shall notify the AOGCC within three working days and take corrective action. Unless well conditions require the operator to take emergency corrective action before AOGCC approval can be obtained, the operator shall submit in an Application for Sundry Approvals (Form 10-403) a proposal for corrective action. The AOGCC may approve the operator's proposal or require other corrective action, including a mechanical integrity test or other diagnostic tests. The operator shall give the AOGCC sufficient notice of the testing schedule to allow the AOGCC to witness the tests. e. Except as otherwise approved by the AOGCC under (d) of this rule, before a shut-in well is placed in service, any annulus pressure must be relieved to a sufficient degree: (1) that the inner annulus pressure at operating temperature will be below 2,000 psig, and (2) that the outer annulus pressure at operating temperature will be below 1,000 psig. CO 793 July 13, 2021 Page 13 of 13 A well subject to (c) but not (d) of this rule may reach an annulus pressure at operating temperature that is described in the operator's notification to the AOGCC under (c) of this rule, unless the AOGCC prescribes a different limit. f. For purposes of this rule, i. "inner annulus" means the space in a well between tubing and production casing; ii. `outer annulus" means the space in a well between production casing and surface casing; and iii. "sustained pressure" means pressure that (A) is measurable at the casing head of an annulus, (B) is not caused solely by temperature fluctuations, and (C) has not been applied intentionally. Rule 10 Production Surface Commineline. Measurement and Allocation a. Production from ROP maybe commingled on the surface with production from other pools within the GMTU and the CRU. b. Wells must be tested at least monthly. DONE at Anchorage, Alaska and dated July 13, 2021. Jerem Digitally signed Y by Jeremy Fdce Price Dele: M21.07.13 i&301746tl0' Jeremy M. Price Chair, Commissioner Digitally signed by Daniel DanlelS arnwnt SeamOunt Dee: ,4ox-0a'(ID'1rW 1453:43 Daniel T. Seamount, Jr. Commissioner Digitally signed by Jessie L. Jessie L. chmielow: Chmielowski 111121.07.13 14:4354 -06'DD Jessie L. Chmielowski Commissioner 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 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, July 13, 2021 5:04 PM To: AOGCC Public Notices Subject: [AOGCC-Public-Notices] AOGCC Conservation Order No. 793 Attachments: CO 793.pdf Please see attached. Re: THE APPLICATION OF ConocoPhillips Alaska, Inc. for an order for classification of a new oil pool and to prescribe pool rules for development of the proposed Rendezvous Oil Pool within the Greater Moose's Tooth and Bear Tooth Units, Greater Moose's Tooth Field f- 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 Docket Number: CO-21-005 Conservation Order No. 793 Greater Moose's Tooth Unit Bear Tooth Unit Greater Moose's Tooth Field Greater Moose's Tooth -Rendezvous Oil Poo[ 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:Hlist.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 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: CO-21-005 Alaska, Inc. for an order for classification of a ) Conservation Order No. 793 Amended new oil pool and to prescribe pool rules for ) Greater Moose's Tooth Unit development of the proposed Rendezvous Oil ) Bear Tooth Unit Pool within the Greater Moose's Tooth and ) Greater Moose's Tooth Field Bear Tooth Units, Greater Moose's Tooth ) Greater Moose's Tooth -Rendezvous Oil Pool Field ) North Slope Borough, Alaska August 10, 2021 IT APPEARING THAT: 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 defining a new oil pool, the Rendezvous Oil Pool (ROP), within the GMTU and BTU and prescribing rules governing the development and operation of that pool. 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 Conservation Order 793. 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. 2. 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. CO 793 Amended August 10, 2021 Page 2 of 13 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 that lies 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 Altamura 1 encountered black oil, while Rendezvous A, Spark IA, Spark 4, and Carbon 1 encountered gas columns, with condensate in the gas. 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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 depths of 8,229 feet 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. 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.) CO 793 Amended August 10, 2021 Page 4 of 13 Sandstones within the Alpine C interval are fine to very fine-grained and extensively bioturbated. Porosity values range from 12 to 22 percent and average 15.6 percent, with permeabilities ranging from 0.09 to 4.57 millidarcies and averaging 0.64mD. Water saturation ranges from 30 to 80 percent and averages 49 percent. In general, Alpine C rock quality tends to improve the north toward the Spark and Rendezvous exploratory wells, and it tends to degrade somewhat to the south. Alpine C interval sediments grade conformably upward into the overlying Alpine D interval, which comprises siltstones and argillaceous sandstones that are distal deposits of the transgressive sequence. CPAI requests Alpine D be included in the proposed ROP because the Alpine C and D intervals constitute a continuous, gradational, transgressive sequence. However, the Alpine D is not expected to contribute to pay or to provide a seal for injection operations. The Alpine D, in turn, grades upward into the overlying, confining Miluveach shale. 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 is trapped stratigraphically. Deep marine shales of the Miluveach, Kalubik, and HRZ intervals (in ascending stratigraphic order) form the upper confining zone, which 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. CO 793 Amended August 10, 2021 Page 5 of 13 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): 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 rb/mscf (at saturation pressure) 10. In -Place and Recoverable Reserves 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 1.7to2.8TCF 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. 11. Reservoir Develonment Drilling Plan: CPAI currently plans to develop the ROP from the 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 wellbores. There is potential for an additional 12 extended reach drilling (ERD) wells, split roughly evenly between producers and injectors. Potential ERD wells will depend, in part, on 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. CO 793 Amended August 10, 2021 Page 6 of 13 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 Mana eg ment: 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. 13. Reservoir Surveillance Plans: CPAI proposes to meet bottom -hole pressure survey requirements through the following reservoir pressure monitoring plan: a. Static bottom -hole pressure surveys will be conducted in all new injection wells prior to initiating injection. b. Static bottom -hole surveys may be performed on production wells at the discretion of CPAI. c. For annual pressure surveillance, a minimum of one pressure survey will be conducted annually in the oil pool, concentrating on injection wells. d. CPAI proposes the following alternative pressure survey methods: Stabilized bottom -hole pressure surveys, ii. Extrapolated from surface pressure on wells with a single phase of fluid in the wellbore, iii. Pressure fall -off measurements, iv. Pressure buildup measurements, Multi -rate tests, drill stem tests, vi. Open hole formation tests, vii. Other methods approved by the AOGCC. Pressures will be referenced to calculate GOC of -8,108 feet TVDss. All pressure surveys will be reported annually. 14. 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. CO 793 Amended August 10, 2021 Page 7 of 13 CPA] expects to develop the reservoir using horizontal wells. Production wells will be completed 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% 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. 15. Metering and Measurement Processes: Well testing and allocation will be conducted with a two-phase well test separator, with all wells being tested at least monthly. Fiscal allocation metering was addressed under Other Order No. 148 issued on December 19, 2018. 16. Waivers: CPAI requested the following waivers: a. Well Spacing: Spacing restrictions of 20 AAC 25.055 be waived for development wells in the proposed ROP to accommodate horizontal, line -drive wells and maximize ultimate recovery. Without prior approval, development wells will not be completed any closer than 500 feet to an external boundary where ownership and/or landownership changes. b. Directional Wellbore Plans: In lieu of the requirements of 20 AAC 25.050(b), permit to drill application(s) shall include: plan view, vertical section, close approach data, and directional data. c. Gas -Oil Ratio (GOR) Exemption: an exemption from the GOR limits of 20 AAC 25.240 to accommodate water -alternating -gas -injection for oil recovery. CONCLUSIONS: 1. Pool Rules are appropriate for CPAI's development of the proposed ROP within the GMTU and BTU. 2. Eliminating spacing restrictions on wellbores within the Affected Area will increase the operator's flexibility in placing wells as the pool is developed and will not affect recovery, promote waste, jeopardize correlative rights, or result in an increased risk of fluid movement into freshwater aquifers. 3. Correlative rights of owners and landowners of offset acreage will be protected by a 500-foot set -back requirement from a property line where landowners and owners are not the same. 4. Water and water -alternating -gas injection into the ROP will preserve reservoir energy and increase ultimate recovery. 5. There are no freshwater aquifers in the proposed Affected Area of the ROP. 6. Annular pressure management is necessary to prevent failure of well integrity and uncontrolled release of fluids or pressure and to minimize threats to human safety and the environment. 7. Granting CPAI's requested Directional Wellbore Plan waiver in lieu of 20 AAC 25.050(b) will ensure equally accurate surveillance of the wellbore to prevent well intersection, compliance with spacing requirements, and protection of correlative rights. CO 793 Amended August 10, 2021 Page 8 of 13 8. A GOR limitation waiver is appropriate because the ROP will be developed as a waterflood and water - alternating -enriched -gas enhanced recovery project. Once pressure maintenance operations commence, GORs should not exceed the limits imposed by 20 AAC 25.240(a). However, before the pressure maintenance operations commence, injectors may be pre -produced to ensure adequate reservoir voidage to accommodate water injection. During this period, there may be wells that exceed the GOR limits. 9. Although the proposed Affected Area extends on to the BTU, the area the CPAI proposes to develop with initial development wells and potential ERD wells lies entirely within the GMTU. 10. CPAI's proposed Administrative Action rule is unnecessary. NOW THEREFORE IT IS ORDERED: Development and operation of the GMTU and BTU Rendezvous Oil Pool is subject to the following rules and the statewide requirements under 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 -NEIA Section 9 - N1/2 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 - N W 1 /4 Township 9 North, Range 1 East Sections 1-3 - All Section 4- N 1 /2, SE 1 A Section 10 - Nl/2, SE1/4 Sections 11-14 - All Section 15 - NE1/4, Sl/2 Section21-NEI/4, S1/2 Sections 22-28 - All Section 29 - NE 1 /4, S l /2 Sections 32-36 —All CO 793 Amended August 10, 2021 Page 9 of 13 Township 9 North, Range 2 East Sections 1-10 - All Section 11 -N1/2 Section 12-N1/2 Section 15 - W 1/2 Sections 16-21 - All Section 22 - W 1 /2 Sections 29-32 - All Township 9 North, Range 3 East Section 5 — WI/2 Section 6 — All Section 7—N1/2 Section 8 — N W I /4 Township 10 North, Range 1 West Sections 1-4 —All Section 5 — E 1 /2 Section 8 — NE 1 /4 Sections 9-12 — All Section 13 — N 1 /2 Section 14—N1/2 Section 15—NI/2 Section 16—NEIA Township 10 North, Range 1 East Sections 1-17 — All Section 18—NI/2 Section 20 — E I /2 Sections 21-28 — All Section 29 — E 1 /2 Section 32 — E 1 /2 Sections 33-36 — All Township 10 North, Range 2 East Section 3 —NW l/4, 51/2 Sections 4-10 — All Section 11—NWl/4, Sl/2 Section 12—S1/2 Sections 13-36 —All CO 793 Amended August 10, 2021 Page 10 of 13 Township 10 North, Range 3 East Section 18 — W 1/2 Section 19 — W 1 /2 Section 30 — N W 1 /4, S I /2 Section 31 — All Section 32 — S W 1 /4 Township I 1 North, Range 1 West Section 25 — S1/2 Section 33 — Sl/2 Sections 34-36 — All Township 11 North, Range 1 East Section 9—SE1/4 Section 10-S1/2 Section 11 —SW]/4 Section 13 — S 1 /2 Sections 14-16 — All Section 17—SE1/4 Section 19—SE1/4 Sections 20-29 — All Section 30—NE1/4, Sl/2 Sections 31-36 — All Township 1 I North, Range 2 East Section 18 — Sl/2 Sections 19-20 — All Section 21 — S W 1 /4 Section 27 — SW 1 /4 Sections 28-33 — All Section 34— WI/2 Rule 1 Field and Pool Name The field is the Greater Moose's Tooth Field. Hydrocarbons underlying the Affected Area and within the interval identified in Rule 2, below, constitute the ROP. Rule 2 Pool Definition The ROP is defined as the accumulation of oil common to and correlating with the interval between the measured depths of 8,229 and 8,393 feet on the resistivity log recorded in the Rendezvous 2 well. (See Figure 2, above.) Rule 3 Well Soacinz There shall be no restrictions as to well spacing except that no pay shall be opened to a well within 500 feet of an external property line where the owners and landowners are not the same on both sides of the line. CO 793 Amended August 10, 2021 Page 11 of 13 Rule 4 Drilling Waivers All permit to drill applications for deviated wells within the ROP shall include a plat with a plan view, vertical section, close approach data and a directional program description in lieu of the requirements of 20 AAC 25.050(b). Rule 5 Well Logging and Sampling Requirements a. A suite of petrophysical well logs including, at a minimum, gamma ray, resistivity, neutron porosity, and density porosity logs shall be acquired across the ROP in one well from each drill site. Gamma ray or resistivity curves shall be recorded from base of conductor to total depth in each well. The AOGCC may require additional wells to be logged using one or more petrophysical logging tools. b. A mud log and cutting samples shall be obtained from the base of the conductor through the ROP in at least one well drilled from each drill site. Rule 6 Reservoir Pressure Monitoring a. A bottom -hole pressure survey shall be taken on each well prior to initial injection. b. The operator shall obtain the pressure surveys needed to manage properly the hydrocarbon recovery processes subject to the annual plan outlined in Rule 8, below. At a minimum, a pressure survey shall be acquired from at least one well on each drill site each year. c. The reservoir pressure datum will be -8,108 feet TVDss. d. Pressure surveys may consist of stabilized static pressure measurements at bottom -hole or be extrapolated from surface measurements (single phase fluid conditions), pressure fall -off measurements, pressure buildup measurements, multi -rate test results, drill stem test results, and open -hole formation tests or other methods approved by the AOGCC. e. A Reservoir Pressure Report, Form 10-412, shall be utilized for all surveys; all relevant data shall be attached to the report. The data submitted shall include, at a minimum, rate, pressure, depth, fluid gradient, temperature, and all other well conditions necessary for a complete analysis of each survey being conducted. f. The results and data from any special reservoir pressure monitoring tests or surveys shall also be submitted in accordance with paragraph (e) of this rule. Rule 7 Gas -Oil Ratio Exemption Wells producing from the ROP are exempt from the GOR limits of 20 AAC 25.240(a) as long as CPAI is engaged in enhanced recovery operations. An enhanced recovery operation must be initiated within 12 months of the issuance of this order. CO 793 Amended August 10, 2021 Page 12 of 13 Rule 8 Annual Reservoir Review a. An annual reservoir surveillance report must be filed by April 1" of each year and include future development plans, reservoir depletion plans, and surveillance information for the prior calendar year, including: The voidage balance, by month, of produced fluids and injected fluids and the cumulative status for each producing interval; ii. A reservoir pressure map at datum, and a summary and analysis of the reservoir pressure surveys within the pool; iii. The results and, where appropriate, an analysis of production and injection log surveys, tracer surveys, observation well surveys, and any other special monitoring; iv. A review of pool production allocation factors and issues over the prior year; V. A review of the progress of the enhanced recovery project; and vi. A reservoir management summary, including results of any reservoir simulation studies. Rule 9 Sustained Casing Pressure for Production Wells a. At the time of installation or replacement, the operator shall conduct and document a pressure test of tubulars and completion equipment in each production well that is sufficient to demonstrate that planned well operations will not result in failure of well integrity, uncontrolled release of fluid or pressure, or threat to human safety. b. The operator shall monitor each production well daily to check for sustained pressure, except if prevented by extreme weather conditions, emergency situations, or unavoidable circumstances. Monitoring results shall be kept available for AOGCC inspections. c. The operator shall notify the AOGCC within three working days after the operator identifies a well as having: (i) sustained inner annulus pressure that exceeds 2,000 pounds per square in gauge (psig) for all production wells, or (ii) sustained outer annulus pressure that exceeds 1,000 prig. d. If the operator identifies sustained pressure in the inner annulus of a production well that exceeds 45 percent of the burst pressure rating of the well's production casing for inner annulus pressure, or sustained pressure in the outer annulus that exceeds 45 percent of the burst pressure rating of the well's surface casing for outer annulus pressure, the operator shall notify the AOGCC within three working days and take corrective action. Unless well conditions require the operator to take emergency corrective action before AOGCC approval can be obtained, the operator shall submit in an Application for Sundry Approvals (Form 10-403) a proposal for corrective action. The AOGCC may approve the operator's proposal or require other corrective action, including a mechanical integrity test or other diagnostic tests. The operator shall give the AOGCC sufficient notice of the testing schedule to allow the AOGCC to witness the tests. e. Except as otherwise approved by the AOGCC under (d) of this rule, before a shut-in well is placed in service, any annulus pressure must be relieved to a sufficient degree: (1) that the inner annulus pressure at operating temperature will be below 2,000 prig, and (2) that the outer annulus pressure at operating temperature will be below 1,000 prig. CO 793A August 10, 2021 Page 13 of 13 A well subject to (c) but not (d) of this rule may reach an annulus pressure at operating temperature that is described in the operator's notification to the AOGCC under (c) of this rule, unless the AOGCC prescribes a different limit. f. For purposes of this rule, i. "inner annulus" means the space in a well between tubing and production casing; ii. "outer annulus" means the space in a well between production casing and surface casing; and iii. "sustained pressure" means pressure that (A) is measurable at the casing head of an annulus, (B) is not caused solely by temperature fluctuations, and (C) has not been applied intentionally. Rule 10 Production Surface Commingling. Measurement and Allocation a. Production from ROP may be commingled on the surface with production from other pools within the GMTU and the CRU. b. Wells must be tested at least monthly. DONE at Anchorage, Alaska and dated August 10, 2021. Jeremy Dlgaall elgnedby le ey Price Date 10r1.09.10 Price 13N):17-081W Jeremy M. Price Chair, Commissioner Daniel DlgltaAy signed by Dank)Seamount Seamciunt °30ouiZoeroo0 Daniel T. Seamount, Jr. Commissioner 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. Ifthe AOGCC grants anapplication for reconsideration, this order ordecision does not become fiinal. 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 ICED) <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 71h 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://list.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. Darwin Waldsmith P.O. Box 13557 P.O. Box 39309 Denver, CO 80201-3557 Ninilchik, AK 99639 INDEXES THE STATE °'ALASKA GUV'I RKt)R MiKI. I)l N] i AV'l 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 our 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 mns 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 ConocoPhillips phone 907.263.4464 July 29, 2021 RECEIVED �By Grace Salazar at 1:49 Pro, 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 AIO 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 ROP. 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 It 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 it 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 6 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, / t�„v`` Stephen Thatcher Manager, WNS Development North Slope Operations and Development i ConocoPhillips 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 ConocoPhillips 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: ns ll F74: N1/2 /2 ll /2 T8N R2E 8: NW1/4 27: NW1/4 28: W1/2, NE1/4 T9N R2E 33: W1/2 Supplement to Rendezvous Conservation Order and Area Injection Order Applications Page 2 of 3 this letter is a map ool boundary expanded to the south. Please contact Dana Glessnero(265Ishowing 6478, gle sQadco ocollphillips.com) ifyou have questions or would like to discuss this request. Regards, !/ T"-L Stephen Thatcher Manager, WNS Development North Slope Development Supplement to Rendezvous Conservation Order and Area Injection Order Applications Page 3 of 3 Attachment 1 Conoco �,� h11 ! 1 1.1� ■Iel Phillips L ■w ! ! -' Alas3a ..t . . n'� . ■ GMT 2 _ �Y •1 uu —xrs Rendezvous Oil au Pool a • - ■1i wil: 1 sraalla Development Plenmozl ■ - .. . 4S "�" .i'F6saxyi.'. i w i xlws � /• I �;. ■ .. .. / / xis x %" i CoWllle F tl Nfi:C,UU i11N __ !111N•HrE.VAI I�ODOTIG _.__, t / ly(E BI TIIN,n)E.VL1� wV■r_ I lfµ Pja .v Unit " V•.1 1 W..0%, ' TIM RIF Ul.r pN ` iION, RIE. NIA x.RE ■ , 1111YM0s ■ 1 I. F.IFII nw1A013 • + �u TIC Greater •� „ Uxai 1, 1, Mooses Ta•1u a _.._ .. Tooth Unit... • e , ti= Bear a Al.` Tooth Unit ■ _ 1 _ i lu1 Pr u rue 2 1 \\\ p. i10 N V,V 1 I'ON 11'/ 1.1 L,I �IE !A I` '1 me.µ\ _I �41�• 1.1.1• W. VLI • T I1- R]E.UN PAAWeBs ¢T1 a IT xuB xlRNI 5zveutx \\\ s S ■ ,A Suspended WelkbillingWeill'alb\• I •ulnu.�: • SrJ PIONFER1 B GAITZ Well Plans —GLITA Well Plans ' ■ __. W w Jesse.; J Proposed Rendezvous Oil Pool - — • ° '' Q Reservoir Boundary • ul uuu oon e; ® Kuukpik Surface ASK Subsurface '"'a lino Boundary Unleased -�.. .. , c ., Industry Lease •. UAI � Teel• .� - *ul, WE. ma IJPR-A Qa!' GPAI LLease.. .:.- _o' ••. lN■_E,U Pad . 1I - isTsai, 8 7 Pipeline l- ll.l — Road A ��A•as _ s ... - AOGCC PUBLIC HEARING 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- 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 5/25/2021 nMO: APPLICATION OF CONOCOPHILLIPS AK, INC. DocketNo. CO-21-005 Page 2 1 TABLE OF CONTENTS 2 Opening remarks by Chairman Price 3 03 3 Testimony by Ms. Glessner 08 4 Testimony by Mr. Timmerman 14 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: sahileQgci.net AOGCCPUBLIC HEARING 5/25/2021 ITMO: APPLICATION OF CONOCOPHILLIPS AK; INC. DoeketNo. 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., Arch. AK 99501 Fax: 907-243-1473 Email: sahile0agei net AOGCCPUBLICHEARING 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: 907-243-0668 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. DmketNo. 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., 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 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 CONOCOPHI LIPS AK- INC. 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: sahileQgci.net AOGCCPUBLIC HEARING 5/25/2021 ITMO: APPLICATION OF CONOCOP14ILLIPS 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 AOGCC PUBLIC HEARING 5/25/2021 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: sahile@gci.net AOGCC PUBLIC HEARING 525/2021 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: 907-243-0668 Email: sahile@gci.net 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 AOGCCPUBLICHEARING 5/25/2021 ITMO: APPLICATION OF CONOCOPHILLINoPCO 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 Email: sahile@gci.net 135 Christensen Dr, Ste, 2., Anch. AK 99501 Fax: 907-243-1473 AOGCCPUBLIC HEARING 5/25/2021 ITMO: APPLICATION OF CONOCD PHILLO. CO IPS AK , INC. 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: 907-243-1166s 135 Christensen Du, Ste, 2., Anch. AK 99501 Fax: 907-243-1473 Email: sahile algci.net AOGCCPUBLIC HEARING 525/2021 ITMO: APPLICATION OF CONOCO kILLIPS AK, INC. 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 Email. sahileQgci.net 135 Christensen Dr., Ste.2., Anch. AK 99501 Fax: 907-243-1473 AOGCC PUBLIC HEARING 5/2512021 ITMO: APPLICATION OF CONOCOPHILLIPS No. CO , INC. 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 Minim LLC Phone: 907-243-0668 Email: sahile(�gci.net 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 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: 907-243-0668 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 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 5/25/2021 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: 907-243-0668 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. DockeINo.CO-21-005 1 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 AOGCC PUBLIC HEARING 5/2512021 ITMO: APPLICATION OF CONOCOPHILLIPS AK, INC. DocketNo. CO-21-005 Page 19 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., Arch. AK 99501 Fax 907-243-1473 Email: sahileQgci.net AOGCC PUBLIC HEARING 1 sporadic? 5/25/2021 ITMO: APPLICATION OF CONOCOPHILLIPS AK, INC. DocketNO.CO-21-005 Page 20 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 g 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 AOGCCPUBLIC HEARING 5252021 ITMO: APPLICATION OF CONOCOPHILLIPS AK, INC. DocketNo. CO-21-005 Page 21 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: sahile@gci.net AOGCCPUBLICHEARING 5/252021 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 AOGCC PUBLIC HEARING 5/25/2021 ITMO: APPLICATION OF CONOCOPHILLIPS AK, INC. DocketNo. 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 AN, 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: sahilecgci.net AOGCC PUBLIC HEARING 5/25/2021 ITMO: APPLICATION OF CONOCOPHILLIPS AK, INC. Docket No. CO-21-005 Page 25 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 5/25/2021 ITMO: APPLICATION OF CONOCOPHILLIPS AK, INC. Docket No. 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. Docket No. 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: sahile@gci.net AOGCC PUBLIC HEARING 5/25/2021 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, T 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 AOGCCPUBLICHEARING 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 5/25/2021 ITMO: 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. DocketNu 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 AOGCCPUBLIC HEARING 5/2512021 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 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 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. 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. DoeketNo. CO-21-005 Page 35 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 Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax 907-243-1473 Email: sahile0agci.net AOGCC PUBLIC HEARING 5/252021 ITMO: APPLICATION OF CONOCOPHILLIPS AK, INC. DocketNo. CO-21-005 Page 36 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 Computer Matrix, LLC Phone: 907-243-0665 135 Christensen Dr., Ste. 2., Anch. AN 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 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 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 381 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: 907-243-0665 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-string 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 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 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 sahile@gci.net AOGCC PUBLIC HEARING 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 Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2, Anch. AK 99501 Fax 907-243-1473 Email: sahile@gci.net AOGCCPUBLICHEARING 5252021 ITMO: APPLICATION OF CONOCOPHILLIPS AK, INC. DocketNo. 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. AN 99501 Fax: 907-243-1473 Email: sahile@gci.net AOGCC PUBLIC HEARING 5/25/2021 ITMO: APPLICATION OF CONOCOPHILLIPS AS, 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: 907-243-0665 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 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 Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net AOGCCPUBLICHEARING 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 5/25/2021 ITMO: APPLICATION OF CONOCOPHILLIPS AK, INC. DocketNo. CO-21-005 Page 45 TRANSCRIBER'S CERTIFICATE I, Salena A. Hile, hereby certify that the foregoing pages numbered 02 through 45 are a true, accurate, and complete transcript of proceedings in Docket No. CO-21-005; AIO-21-004, transcribed under my direction from a copy of an electronic sound recording to the best of our knowledge and ability. Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gei.net lk 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 AFFILIATION Testify (yes or no) ConocoPhillips Patrick D, Doherty ConocoPhillips Kevin Donley ConocoPhillips Tyndall Ellis ConocoPhillips Stephen Tatcher (Cisco) ConocoPhillips Patrick Doherty ConocoPhillips Andy Bond Oil Search C%Gfrch MQ( coK, Co R.C S A�-,Wp / AoG6c N6 Ghri s l-,)aikcc c-e Aea GC, iV 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 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 ConocoPhillips • Rendezvous is the Pool • GMT2 is second development in Greater ,.f C0= Moose's Tooth Unit NATIONAL PETROLEUM Colville RESERVE-ALASKA River Unit • 8 miles SW of GMT1(Lookout)�G-�' ,-,]. Bee/ Tooth �CD2 CD1,F.LPINE • Utilize existing Alpine infrastructure Unit ccs 1 ` CD: History: GMTt Greater \ %, • 1998-2000: NPR -A Exploration 3D Seismic Moose$ • 2000-2004: Exploration drilling Tooth Unit • 2008: Rendezvous 2 drilled & flow tested c • 2014: Rendezvous 3 drilled & flow tested GMT2 • 2017-2020 : Development 3D Seismic acquisition, processing and interpretation t,•�' • 2018: GMT2 Sanctioned by ConocoPhillips .•"" • 2019-2020: 15Y two construction seasons • �: 202 Final installation of facilities and pipelines °•'•--r,� • First production and injection startup N expected in Q4 • �•.a. �..,., • First well spud on April 27th 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 "'j GMT 2 men a Rendezvous Oil Pool WITO I Development Plan SPARK fU 5112021 ZE 1. .2 ME 7, a- w PH Il K0Ui Colville T11N. UW�� T11N.RjE.UM NOOSES 16 I T); 'T Z N R3E 'm River Tlft.�.UM 7 0 1w um T ON RIF W T10N 83 Unit T" MWAG, M ; Greater Cr �T I r(�HKM07 1, Mousesw —Tooth Unit — O a ANOD4 9 &i Bear Tooth Unit )3'1oNXKQ 2 T1M R,VVI TION. F 1W UM T90N,RIE. I %\\Hew- i Wum Is IM0 6801610 + P&AWells C Suspended Wells Existing Well Path a\; -i_ a GMT2 Weil Plans PIONEER 4 FF GMT2X Well Plans O i a Proposed Rendervous Oil Pool -- ---- 1.,101.10111 Reservoir Boundary A Kuukpik Surface ASRC Subsurface ......... F. H'. � Unit Boundary Z Unleased +ALTANU Industry Lease um fM j/:� TEN' R E.UM TM RxF UN, 171 CPAI Lease N W FIE UKI E TON R E.Ukl NPR -A ■ Pad Pipeline ngxuo Is Road Conocoi • 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 3 • 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 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: • 37.20API 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) w aZ Y W O> 00 cc N Sw NE S? MA m 0 2 0 Z so ✓ J,, y.'� w In O 96 Nanush !� W W ono , U 144 aP U N Q No Kingak Fm zo Shublik Fm. F TRIASSIC s--- Z Qw wOZZ PERMIAN �w w0 PENNSYLVANIAN W w � N W Usbume Gp. - Alpine C SS * - Primary Source (Kingak) ConomPhil 1ps Depth Map of the Upper Jurassic Uncontormity (UJU), Keservolr rsase ......... ......n. ... umv 1 M 10M ,vAWO 147M V �j2 V � i '��, �� ) \ may_✓ / �yP {� � an now : i`� i J,�'.. - ��. � 'lgtt/o �� Q �. / I ♦ ' 1 p OJ/Re Ni � 'AOJ ,0000 ,f000 NOJD :SDYJ,ttIS r� Fault • Exploration Well i S Development Well ERD Development Well Reservoir Boundary / Proposed Pool Boundary 50' Contour Interval Depth NDss, feet Proposed vertical limits for the Rendezvous Oil Pool U o c> c aim C exso ' 6 dR a - aiw O y d C 1"10 Ca S aiso l Alpine C Sand Properties in Rendezvous 2: • Porosity: Avg. 15.6%, Range 12-22% • Permeability: Avg. 0.64 mD, Range 0.09-4.57 mD • Water Saturation: Avg. 0.49, Range 30-80% � Upper Jurassic �,�'fj Unconformity ConocophiUips Well Section showing log character of the Alpine interval through the Rendezvous Pool RI..wh South i - GR ssn9 Mp PESD :%i'^sy. ;qE ......• 'Vp[55 NMI 53 • �a..rs 3 mi �R Ssn^J IM RESD LwY ...s Rf$S a.7 NPNI 44 �.r..0 pR08 mi A TAMUkA , s G¢ 'E`er_�� _ ...ge_cc. S=_ .. _Rn06 flMOB �Drc • b e D.c f !{ 7< FCS_KRZ FCS Kalubik lAluveach Alpine ( Alpine—( U11 The Alpine sand interval (M) 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) TApproximately 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 ilville Group (Clay with terbedded silt & minor nds) anushuk Group (K-3 to Albian i; top sets, shallow marine, Its/shales and thin fine- 'ained sands orok (Albian slope & deep narine shales with inter- ,edded sands) CS Fill ARZ/Kalubik/Miluveach Shales alpine C Sandstone (Target) ConocoPhillips Permafrost base at —1,000' TVDss Surface Casing M. Alb Alb Alb Alb Colville Group: Weakly consolidated, silty, medium gray claystone with some siltstone lenses. Nanushuk Group: Shallow marine deltaic sediments, like Colville, but more lithified. Torok Group: Series of slope to deep marine sediments forming clinoforms. Mainly marine shale with interbedded turbiditic sands. 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 ConocoP lips • 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 Intl) • 4-string (Pipe Conveyed Intl — GMT1) • Managed Pressure Drilling (MPD) n•, rzac S'WO ft. • 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 at Lateral • 6.5" Hole • Mineral Oil Based or Water Based mud • 4-%2" Liner on producers, Openhole for injectors • TO — 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 SK prod tree) Top Abm.c 2P 14 pP1 n.ao m W IaeE Co .u. at.* CNl 01. W1A'e q-L!• W. LAW mcAU1 Y,1Ka Geq M02.115'M N4'12.ln1,41DW 353 ooMgl. G> . Plo O. P,ver Tup.10l Lnw WRolM.n ' 11 4 •A- LlMlq nlppb O 813 IC: 21 a'Aa "GLM 12 11, 31HSDl W(e GaP;e al4-%'1A O1 PaN 51 Lt4' LfMmp Moplf U N 616ne1T1q pxditl Nenp.TW Tx'Tp Baer seae VP lna Tov Pa .' 4Y,- 1L68 L40 NydM3L Vwl axeG gtlln i1aWMCOb 7 ID pone fe11Q 26Wp'M LStl• A.211312• Ldp TIP 1K CY O4 UNT1IU hpgt,p�.dC� ConocoPhillips • 20" Insulated conductor w/ thermo-siphon Surface: • 16" Hole • Inhibited Spud Mud • TD `3,650' to 4,115' MD (K-3) • 13-3/8" Casing & Cement to Surface • Install and test BOPE • Intermediate 1: • 12 Y." Hole • LSND Mud • TO into the HRZ • 9-5/8" Casing • Cement Shoe perAOGCC 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-Y." Liner on producers, Openhole for injectors • TD — 22,000' to 36,000' ]P 7! ppl HJO MUIpIpO eo 4w ..•.n<ro w>a iWOp Carotrm 11 •�X' lanOYq NW4 i l d!J' O� JI s.•4. r C,LY �1 PrpO,men N Sh'•(lanGYq MOip 04 IS )!' NOG", eir« xa it OPa I1U- 0 ppt Lao WC1 W Y Svlaw Cavnp bIR' Id 6001 L 40 Wry 3 5 54- U 5 pN Ld011,M T-PA0.wc P W' &V 12"Li Np056]I ,.1.0 pwoI • Completion Liner top packer set above Alpine Cwithin confiningzone r�`Pand" 14H 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 SK prod tree) "w 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 Ak conocoPhinips 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 7' 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 Jeemy M. Ntally eed Date:2021D4.16 M. Price 14. 9S2-0"D 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. (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 72h 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 711 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 Digitally signed by Jeremy M. Ptice Date: 2021.04.16 M. Price 14. g:51 08-00- Jeremy M. Price Chair, Commissioner Notice of Public 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. (CPAQ 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 (AGGCC) 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 partvwishes to participate at the hearing telephonically, they should calif 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. file// Pub: April 18, 2021 STATE OF ALASKA ADVERTISING ORDER NOTICE TO PUBLISHER SUBMIT (DAVIT FSHOWING PUBLICADVERTISINGORDERNO.,CERTIFIED AFFIDAVIT OF PUBLICATION WITR ATTACKED COPY OF ADVERTISMENT. ADVERTISING ORDER NUMBER 1 p 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 907) 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: 1J LEGAL j— DISPLAY r CLASSIFIED OTHER (Specify below) DESCRIPTION PRICE CO-21-005 and AIO-21-004 Initials of who prepared AO: Alaska Non -Taxable 92-600185 st.0an.. ..... es iowav >aiav a si vc: ORDER ISIO:;CERYRTRDAF.EiDAVYI''tfK;::: :piluiiCw?oHwiTH:AlydtxE"BCOIrY:OP: AOGCC 333 West 7th Avenue Anchorage, Alaska 99501 Page I of 1 Total of All Pa es $ REF Type Number Amount Date Comments I PvN VCO21795 z Ao AO-08-21-019 3 4 FIN AMOUNT SY Act. Template PGM LGR Object FV DIST LIQ I 21 AOGCC 3046 21 2 3 4 Pit An T Purchasing Authority's Signature Telephone Number A.O. # and receiving agency name must appear on all invoices and documents relating to this purchase. state is registered for tax free transactions under Chapter 32, IRS code. Registration rmmber 92-73-0006 K. Items are for the exclusive use of the state and not far 111STRI .... o...... a .... 1pr)�aa1: 0 ... Palrh.... (i..... AlwsFodFiacgl, Recsiviag 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 first duly sworn on oath deposes and says that she is a representative of the An- chorage Daily News, a daily newspaper. That said newspaper has been approved by the Third Judicial Court, Anchorage, Alaska, and it now and has been published in the English language continually as a daily newspaper in Anchorage, Alaska, and it is now and during all said time was printed in an office maintained at the afore- said place of publication of said newspaper. That the annexed is a copy of an advertisement as it was published in regular issues (and not in supplemental form) of said newspaper on 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 Subscribed and sworn to before me this 19th day of April 2021. TOWPublic inaJ e State of AJaske Third Division Anchorage, Alaska MY COM�vII� I(,)ilN�)E�XPIRES Cost: $219.16 RECEIVE® 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 partywishestoparticipateatthehearingtelephonically, they should cal( 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.. it-1r�Y uBLIC^ JADA L. NOWLING STATE OF ALASKA liny :_xr.:nrR .hdv 14, 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`6 Avenue Anchorage, AK 99501 Phone Number: 907-793-1221 Email: jody.colombie@alaska.gov List Name: AOGCC_Public_Notices@list.state.ak.us You subscribed as: jody.colombie@alaska.gov Unsubscribe at: http:Hlist.state.ak.us/mailman/options/aogcc_Public_notices/jody.colombie%40alaska.gov Bernie Karl 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. Darwin Waldsmith P.O. Box 13557 P.O. Box 39309 Denver, CO 80201-3557 Ninilchik, AK 99639 VI II S 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 RE: Application for Pool Rules Rendezvous Oil Pool, North Slope, AK Dear Commissioner Price, RECEIVED APR 1 Z 2021 AOGCC In accordance with 20 AAC 25.520, 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 a Conservation Order to classify the Rendezvous Oil Pool (ROP) and to prescribe pool rules for development of the ROP within the GMTU. 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 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, } � I �Wes, 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 Pool Rules, Rendezvous Oil Pool April 12, 2021 Page 1 of 53 P hilli Conoco ps APPLICATION FOR POOL RULES OF THE RENDEZVOUS OIL POOL April 12, 2021 1. Introduction 2. Geology 3. Reservoir 4. Reservoir Development 5. Drilling 6. Well Operations 7. Facilities 8. Proposed ROP Rules List of Figures: 1. Proposed Rendezvous Pool Area 2. Defining well, Rendezvous 2, highlighting proposed Rendezvous Oil Pool interval 3. GMT2 Project Location 4. Rendezvous Pool proposed development plan with drilling order for initial ten wells 5. 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. Depth map of the UJU (Reservoir Base) 6. Depth map of the UJU (Reservoir Base) 7. Proposed Three String Rendezvous Producer Well Design 8. Proposed Four String Rendezvous Producer Well Design 9. Annular Disposal Interval— K-3 10, GMT2 Facilities and Metering, red circles are AOGCC custody meters Appendix 1 - Confidential Information 11. Lambda"Rho extraction above UJU surface highlighting reservoir presence within the reservoir boundary and pool area. (Confidential, Appendix 1) 12. 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) 13. Alpine C Isochore for Rendezvous Pool showing Exploration Wells and proposed Pool Boundary (Confidential, Appendix 1) 14. Rendezvous Net Oil Pay with Proposed Drilling Locations (Confidential, Appendix 1) CPAI Application for Pool Rules, Rendezvous Oil Pool April 12, 2021 Page 2 of 53 Appendix 2: 15. Formation water salinity summary with Rendezvous type log (Rendezvous 2) and lithology summary. Appendix 3 — Annular Disposal of Drilling Waste at CD5 Appendix 4 — Docket OTH 14-026 Annular Disposal of Drilling Waste at CD5 Appendix 5 — CD5-93 Annular Disposal Sundry and Approval Appendix 6 — MT6-05 Annular Disposal Sundry and Approval CPAI Application for Pool Rules, Rendezvous Oil Pool April 12, 2021 Page 3 of 53 1. INTRODUCTION Scope of Application This application is submitted for approval by the Alaska Oil and Gas Conservation Commission (AOGCC) to define the proposed Rendezvous Oil Pool (ROP) and establish Pool Rules for the oil pool pursuant to 20 AAC 25.520. ConocoPhillips Alaska, Inc. (CPAI), submits this application to the AOGCC in its capacity as Operator of the Greater Moose's Tooth Unit (GMTU) and on behalf of the GMTU working interest owners (WIO). The scope of this application includes a discussion of geological and reservoir properties of the proposed ROP as they are currently understood, and CPAI's plans for reservoir development, reservoir surveillance, and well construction. 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. Concurrent with this request, CPAI is also separately applying to the AOGCC for an Area Injection Order (AIO) for the proposed ROP. Pool Area and Interval The proposed area to be covered by the ROP rules is shown in Figure 1. The Rendezvous 2 well provides the type log for the ROP shown in Figure 2. CPAI requests that the Alpine C and Alpine D intervals, as shown in the correlative section on the type log from measured depths (MD) of 8,229 feet to 8,393 feet or -8,104 feet to -8,268 feet true vertical depth below mean sea level also termed true vertical depth subsea (TVDss), be included in the Pool. The base of the ROP is defined by the Upper Jurassic Unconformity (UJU) as defined by the Rendezvous 2 well at 8,393 feet MD and -8,268 feet TVDss.1 The top of the ROP is defined by the top of the Alpine D interval (base of the Miluveach Shale) as shown in the Rendezvous 2 well at 8,229 feet MD and -8,104 feet TVDss. The proposed pool boundary extends approximately one full quarter section beyond the largest estimate of Alpine sand presence (Figure 1) 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 W10. Project Background 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 1A, 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. Figure 1 shows the positions of the exploration wells in relation to the ROP boundary and proposed oil development. 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 ACF for processing. The 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. Consistent with obligations under the Bear Tooth Unit (BTU) and GMTU Agreements CPAI continues to actively analyze development options for Spark. I The information contained in this application is intended to satisfy the requirement of 20 AAC 25.517(a) that the operator of the Rendezvous Oil Pool submit to the AOGCC a plan of reservoir development and operation. CPAI Application for Pool Rules, Rendezvous Oil Pool April 12, 2021 Page 4 of 53 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 rior to ng on the surface w with production from the LOP ltransfer be measured for custody LOPand he CRU GMT2 produ tonwill be processed at hegled ACF in the CRU. 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. Ownership CPAI is the operator and 100% working interest owner in the GMTU, and is 100% working interest owner of the producing intervals in the CRU. CPAI is the operator of the GMTU and the CRU. The Surface Owners of the ROP area are Kuukpik Corporation (Kuukpik) and the United States of America, Department of the Interior, Bureau of Land Management (BLM). The Subsurface Owners of the ROP are Arctic Slope Regional Corporation (ASRC) and BLM. The Rendezvous Participating Area (PA) is being formed to develop the ROP. The proposed ROP PA boundary is also shown in Figure 1. CPAI Application for Pool Rules, Rendezvous Oil Pool April 12, 2021 Page 5 of 53 Con000"Phillips1.1 Al� GMT 2 Rendezvous Oil Pool 21 Development Plan A— ■ -I- U" MoOSES Colville ITI Ft".W RTW w TOOTH C SIRES A:w • River J■ SE UM. unit— . nwMQ 6 ■CARBON I w nwAQ is Ift.01.1 a 1A Greater Moosas wlT -. 7 Tooth Unit Tool D 4, a P&A Wells TIO R, U RENDEzwVS2 ,a Suspended wells T a a E. —Etas hq Well Pathfir3 GMT2 Well Plans GMT2K Well Plans Proposed Rendezxxxs Oil Pod a C3 Draft Rendenous PA a lip Reservoir Boundary E—e Ku*pkSuffaceA5RCSubsurlaoe a tiMUnit Bounclari Unleased +KTAMU Industry Lem C3 CPAd Lease NPR -A Pad Pipeline P.MQ Road Figure 1: Proposed Rendezvous Pool Area CPAI Application for Pool Rules, Rendezvous Oil Pool April 12, 2021 Page 6 of 53 Figure 2: Defining well, Rendezvous 2, highlighting proposed Rendezvous Oil Pool interval CPAI Application for Pool Rules, Rendezvous Oil Pool April 12, 2021 Page 7 of 53 CD0 NATIONAL PETROLEUM Colville RESERVE-ALASKA �: River , i Unit iA Beer C01+ALPINE Tooth 1CD2 Unit CD5 J i Greeter GMTJ 'Jk CDd Moo Unit Unit � GMT2 s� fin• - AaY I t4 :A'��•MM ! w;;1. 125C25 g 75 10 Mies Figure 3: GMT2 project location CPAI Application for Pool Rules, Rendezvous Oil Pool April 12, 2021 Page 8 of 53 1412000 1410M 142WW 1424000 1428000 IMM 1436000 1440000 144400D 144M i r b n T1ON, RE �'r i ,►0 9 1 8 $. T10N, R2f T9N, R Rendezvous ezwu s $� TSIN, R2E I Well Name 4M Producer 8111'2dOr Injector ro Exploration Well 8 Drill Order gR s Reservoir Boundary J / Proposed Pool alem°r, 3 Boundary 1412000 1418000 1420000 1424000 1428000 1432000 1438000 1440000 1444070 144i= 0 2000 4000 8000 8000 1000 MS Figure 4: Rendezvous Pool proposed development plan with drilling order for initial ten wells CPAI Application for Pool Rules, Rendezvous Oil Pool April 12, 2021 Page 9 of 53 2. GEOLOGY Pool Identification 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 TVDss respectively) in the Rendezvous 2 well (Figure 2). Upper Confining Interval Deep marine shales of the highly radioactive zone (HRZ), Kalubik and Miluveach intervals form the upper confining zone for the ROP. Total thickness varies from 680 feet to 1,600+ feet. Recommended Pool The top Alpine D marker down to the UJU records continuous deposition of transgressive sands infilling the paleotopography created by incision of the regionally extensive UJU. The Alpine package is identified by seismic and well data. A detailed description is provided under the Stratigraphy and Sedimentology section. Lower Confining Interval Below the ROP is the Kingak shale. The Kingak is approximately 1,700 feet thick in the proposed area of development, consisting of marine shales and siltstones. 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 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 5 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 Appendix 2, Figure 15. 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 6) 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 6). 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 CPAI Application for Pool Rules, Rendezvous Oil Pool April 12, 2021 Page 10 of 53 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 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. 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 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 Pool Rules, Rendezvous Oil Pool April 12, 2021 Page 11 of 53 .: 6 t )It.ICt tl) Ili IS1fti1Si1t1it£ titi S!))IlSiflilii i t S t it i l l U it liSil)l fSlttSi tt t itt tit I; t 111 t i ii ! 1 r ' #1ti C�[tit£1!!ttSt!lSItS iil�ii llf 117d1lf)t1t!` ,r 4 4� 't • f i ttH ti±t Si lSifilti£tt£t;i jttit Stttl ttiilillii ttlStl 1 iltitf___ 4tt11tlf€! "q iil _ _ t i'itttiirtrit)rlt� a i '.0 Figure 5: 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. CPAI Application for Pool Rules, Rendezvous Oil Pool April 12, 2021 Page 12 of 53 ifiwwv�w n 0 o s]o.) 11?00 +sore 20?M 2} fws Y� Figure 6: Depth map of the UJU (Reservoir Base) 7V Fault • Exploration Well Development Well ERD Development Well Reservoir Boundary Proposed Pool Boundary 50' Contour Interval Depth TVDss, feet CPAI Application for Pool Rules, Rendezvous Oil Pool April 12, 2021 Page 13 of 53 3. RESERVOIR Introduction The ROP consists of an Alpine C sandstone deposit. The very low oil viscosity yields a favorable mobility for water injection and is expected to yield efficient reservoir sweep. Reservoir Properties Reservoir oil fluid properties are summarized from the PVT study completed on the Rendezvous 3 well at 8,250 feet MD (-8,140 feet TVDss) and are listed below: - Initial Reservoir pressure: 3802 pounds per square inch (PSI) - Reservoir temperature: 2070 F - GOR: 1279 standard cubic feet per barrel (SCF/BBL) - API gravity: 37.20 - Bubble point pressure: 3815 PSI - Oil formation volume factor: 1.7 reservoir barrel per stock tank barrel oil (RB/STBO) - Oil viscosity: 0.232 centipoise (cP) - Gas formation volume factor: 0.8 barrel per thousand standard cubic feet (BBL/MSCF) at saturation pressure Reservoir rock properties are described in the Geologic Section. Original Oil -in -Place (OOIP) The estimated OOIP volume within the oil development area is based on the well data from Rendezvous 2, Rendezvous 3, and Altamura 1, as well as from seismic data. Predevelopment COW estimates range from 300 to 460 million barrels of oil (MMBO). Additional reservoir data from the planned oil development wells will enhance the understanding of sand distribution and may result in an update to the OOIP range estimate. An oil net pay map for a medium OOIP scenario is shown in Figure 14 (Confidential, Appendix 1). Original Gas -in -Place (OGIP) The gas accumulation, commonly referred to as Spark, has not been characterized to the same degree as the oil rim and it is not targeted for current development. A 2014 volumetric analysis estimated a potential OGIP ranging from 1.7 to 2.8 trillion cubic feet (TCF) of gas and 51 to 168 million barrels (MMBBL) of liquids. The condensate yield range for Spark is demonstrated by the flow tests and fluid samples from two exploration wells, the Spark 1A and the Carbon 1. Isochronal well tests reported multiple rates but the final flow period for Spark 1A tank corrected GOR trended to 17,000 SCF/STB or approximately 60 BBUMMSCF. The Carbon 1 well test and fluid samples produced significantly less condensate with a yield of approximately 40 BBL/MMSCF. Compositional and PVT analysis of the separator samples indicates a yield range of 30 to 60 BBUMMSCF. This range appears consistent with the corrected well test GOR trends. CPAI Application for Pool Rules, Rendezvous Oil Pool April 12, 2021 Page 14 of 53 4. RESERVOIR DEVELOPMENT Development Plan The ROP will be developed with horizontal production and injection wells in line drive patterns oriented with the maximum principal geomechanical stress direction. The initial development plan includes 18 horizontal injection wells and 18 horizontal production wells with possible pilot holes. The pilot holes would provide additional reservoir data and assist in optimization of horizontal well placement. Based on current information planned drilling locations are shown in Figure 1 and Figure 4. Pressure support will be maintained with water and gas injection targeting a cumulative voidage replacement ratio of 1.0. An Enriched Water Alternating Gas (EWAG) flood will be initiated early in the waterflood to improve ultimate recovery. EWAG will yield incremental recovery with condensing components that will result in improved oil mobility due to oil swelling and reduced interfacial tension. Simulation work demonstrated an optimal well spacing of 1,200 feet separation between injectors and producers. The producers will be developed using horizontal wells with solid liners including pre - perforated pups and fracture sleeves. External swell packers may be added to provide annular isolation between pre -perforated pups. Multi -lateral or other completion methods may be employed as conditions dictate. Vertical well waterflood and horizontal well line drive waterflood were both analyzed as development options for GMT2. A vertical well development is not as competitive due to the number of wells required. Horizontal water injection and production wells are expected to yield efficient areal and vertical sweep due to the low oil viscosity which yields favorable waterflood mobility. EWAG will additionally enhance displacement efficiency and assist with reservoir throughput as the waterflood matures. Gas Cap 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' 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 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 processing facility 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. CPA] analysis shows that the gravity stable offtake rate for ROP is too low for economic development. Recovery Mechanisms 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 expectation for ultimate recovery that will be in the CPAI Application for Pool Rules, Rendezvous Oil Pool April 12, 2021 Page 15 of 53 range of 35-60% of OOIP. A subset of the factors that may impact recovery include facies distribution, net pay, voidage replacement, well productivity, and OOIP uncertainty. Reservoir simulation and analytical analysis indicate that primary recovery alone is expected to yield recovery of 20%. The remaining ultimate recovery is expected through secondary and tertiary mechanisms with EWAG injection. The expected EWAG recovery is 25% of OOIP based on reservoir simulation at the type pattern and full field model scales. The EWAG line drive is the development option that is expected to maximize recovery. Tertiary recovery with the EWAG process is expected to generate incremental recovery above the base waterflood performance. Recovery Performance The forecast of recovery performance for the ROP with the planned development is based on multiple reservoir simulation efforts. Fine scale pattern models (type pattern models) were used to optimize well spacing and forecast performance at the pattern level. A field scale upscaled model was also used as a forecasting tool for the planned development. 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. Future Development Execution of the initial 36 well development plan will yield additional data that will provide a better understanding of the sand distribution in the Rendezvous reservoir. Additionally, the Moose's Tooth 7 (MT7) drillsite is designed to accommodate 12 additional wells that are considered extended reach drilling (ERD) targets (Figure 1, GMT2X well plans). CPAI continues to also analyze future development options for Spark. Producing Gas -Oil Ratio (GOR) Expectations CPAI requests that the requirements described in 20 AAC 25.240 be waived for the proposed ROP since the Pool plans are to implement enhanced recovery techniques. Since gas will be injected into the ROP during the life of the Pool, the GOR is expected to rise above solution GOR in some wells. The breakthrough of re -injected gas will cause GORs of some producing wells to exceed limits set forth in 20 AAC 25.240. Additionally, the ROP average reservoir pressure will be maintained above the bubble point pressure with water injection for pressure maintenance. CPAI Application for Pool Rules, Rendezvous Oil Pool April 12, 2021 Page 16 of 53 5. DRILLING Drilling/Well Design The ROP will be accessed by wells drilled from a gravel pad utilizing drilling procedures, well designs, and casing and cementing programs consistent with current practices in other North Slope fields. Maintaining stability of the intermediate borehole to drill, run and cement casing through the shales of the HRZ, Kalubik and Miluveach formations just above the reservoir is the main challenge for drilling. There are two different casing plans based on mapping of the unstable HRZ slump blocks and total footage of the intermediate hole. Well paths that do not encounter unstable HRZ slump blocks with targets near the drill pad have three hole sections, otherwise the plan is to drill the intermediate in two intervals resulting in four hole sections. The surface casing will be upsized to 13-3/8 inch on initial three string wells to provide the contingency to sidetrack and convert to a four -string casing design. Figures 7 and 8 illustrate generic ROP producer well designs and the different casing plans. Maintaining stability of the borehole and horizontal geo-steering in the pay zone are keys to success. For proper anchorage and to divert an uncontrolled flow, 80 feet of 20 inch insulated conductor casing will be set on 20 foot well centers and cemented to surface. Cement returns will be verified by visual inspection. Surface holes will be drilled, and casing set below the C-5 marker in the Colville Group for proper anchorage and protection from permafrost thaw and freeze back. Within the planned development area, the base of permafrost is interpreted to lie between -800 feet to -1,200 feet TVDss. No hydrocarbon bearing intervals have been encountered to this depth in exploration wells and this casing point provides sufficient depth for kick tolerance. Surface casing strings will be cemented in accordance with 20 AAC 25.030(d)(4). The blowout prevention equipment (BOPE) will be installed and tested in accordance with 20 AAC 25.035. A Formation Integrity Test (FIT) will be performed in accordance with 20 AAC 25.030(f) In three -string wells, the intermediate #1 section is between the proposed surface casing shoe and the top of the reservoir section. The section will be directionally drilled with the casing shoe at approximately 85 degrees just above, orjust into the Alpine C sand. This section consists primarily of interbedded shales and siltstones. 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). See Figure 7. For the four -string casing design, the intermediate hole will be drilled in two intervals. Both sections will be directionally drilled with the first casing point being the top of the HRZ and the second casing point at approximately 85 degrees inclination just above, orjust into the Alpine C sand. After drilling out both the intermediate casing and/or liner shoes, a FIT will be performed in accordance with 20 AAC 25.030(f). For the intermediate #2 section from the top of the HRZ into the Alpine C sand, it may be drilled conventionally or via steerable drilling liner (SDL) where a liner is carried into hole behind a directional drilling and logging pilot assembly that is retrieved prior to cementing. See Figure 8. Managed pressure drilling (MPD) will 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. Based on current knowledge of reservoir characteristics, CPAI expects to develop the ROP using horizontal wells. The producers will be completed with solid liners including pre -perforated pups and fracture sleeves for hydraulic stimulation. External swell packers may be added to isolate out of pay excursions or fault crossings along the lateral and also allow for future well intervention optionality. CPAI Application for Pool Rules, Rendezvous Oil Pool April 12, 2021 Page 17 of 53 Injectors will be unlined barefoot completions. Multi -lateral or other completion methods may be employed as conditions dictate. Both injection and production wells will be completed with 4-1/2 inch tubing to minimize hydraulic friction. CPAI Application for Pool Rules, Rendezvous Oil Pool April 12, 2021 Page 18 of 53 Top AIPme C 24' 79 ppf H-40 Metal Conductor 8o redcontented to solace 13.31e" 68e Ldo 6TCAbd Surface Cadrp net 02A1W bO 4-112" 12.W Log HT0563 Top of 7-5V 33.7a L-80 TXP INT Coning I@ -&SW NO (4.4W of 3370) Downnole Gauge PfocUCaon Packer Tuprngf Uner Completion 1) 4.8" Landing Nipple (3 813" ID) 2) 4-W x 1' GLY (2.3x} 3) HES DaNnWe Gauge 4) ProQ10011 PaCKer 5) 4 .' Landing Nipple (3 7B ID) 6) Liner Top Packer I Hango"I'Tie Saa! Stowe ZXP Liner Top Packer V/." 12.6a L,80 H70563 Liner w! spell packers an d closeable trac pone set Q Qf Mew ND hadct;m Hem �A r-5f8" 29.75133.70 L40 TXP INT Casting it985' ND Figure 7: Proposed Three String Rendezvous Producer Well Design CPAI Application for Pool Rules, Rendezvous Oil Pool April 12, 2021 Page 19 of 53 20' 19 pot N-40 Nsatdled Cooductor 80 No cirwiedto w1we 13.34"MppILMOTCAW Surface Cntn9 an Q 3jw MD 441r2" 12.6 ppl L d0 HY0563 95M' 43.5 pol L-00 T%P* 9 TV US poll L d0 HYD563 Cgong set 011,m No DaMrotole Gauge Prodrtdon PacYer TUM9I Un* Crrnp149on 1) 4- :" LandM9 MIppM (3 0 W to) 2) 4-Wx T'GLM 3) 4.51'r VOLM 4) N0091on PaC"t 6)4:a' La11dMq Mpple (3.75' NaGd) 6) Uner Top P4dW I Hnqu %W TM Back aaae Z(F User Too PSMO( 12.de1 801yd593 LMM eN 40 cbdamle lrac sMeves Top ApMe C 7" 26 pot 1..60 HY05W INT C adn0 set @ 14460' MD arm Hail woduttlw tdde Top 24,65W up Figure 8: Proposed Four String Rendezvous Producer Well Design CPAI Application for Pool Rules, Rendezvous Oil Pool April 12, 2021 Page 20 of 53 Drilling Fluids The drilling fluid program designed for wells within the ROP will be prepared and implemented in accordance with 20 AAC 25.033. Formation pressures for the strata to be penetrated will be estimated based on data gathered from the exploration wells drilled into the ROP. Water based mud systems are planned for all wellbore sections where mineral oil based systems are not required to maintain hole stability or prevent reservoir damage. Annular Disposal Disposal of drilling wastes will be proposed for GMT2 in accordance with 20 AAC 25.080 in annuli of wells with surface casing set below the permafrost. Annular disposal is being implemented at the ROP for environmental, operational, and economic reasons and is in conformance with the 2004 Environmental Impact Statement, as supplemented in 2018, covering the GMT2 Project. Annular disposal at GMT2 drillsite remains an important tool to augment the capacity of local disposal wells. Wastes that are inappropriate for annular disposal at GMT2 will be injected per regulations into the disposal wells on CD1 at the ACF. Additionally, there is a new, third disposal well planned for 181 quarter 2022 in the CRU. The basis for CPAI's application is the same as was articulated in CPAI's letter to the Commission dated November 7, 2014 in support of utilizing annular disposal at the CD5 drillsite. See Appendix 3 (letter of 11/7/14 from Alexa to Foerster). After CPAI sent this letter the Commission held a hearing under Docket OTH 14-026. After the hearing, the Commission closed the matter with a letter. See Appendix 4 (letter from Foerster to Alexa dated 1/16/15). CPAI has utilized annular disposal during the CD5 drilling program from 2015 up to the most recently approved CD5-93 sundry approval #321-082 in 2021 (Appendix 5). Annular disposal was approved and proved to be instrumental in the successful Lookout drilling program during the 2018 and 2019 execution (Appendix 6). Approved sundries provided for efficient and safe drilling fluid disposal due to the remoteness and limited resources available during the Lookout program. The same reasons support approval of annular disposal for the Rendezvous wells. The proposed annular disposal interval will be the K-3 in the Cretaceous age Nanushuk Group (Figure 9). This interval contains approximately 350 feet TVD of interbedded sandstone and shale (with approximately 130 feet of sand). Surface casing will be set in shale above the K-3 marker. The upper confining barrier is composed of 1,000 feet TVD of shale and siltstone of the Upper Cretaceous Colville Group. Approximately 1,000 feet TVD of permafrost overlies this interval. The lower barrier is composed of over 3,000 feet TVD of Torok Group, primarily marine shale with some interbedded thin sands. No freshwater sands have been encountered in GMTU exploration wells as further described in Appendix 2 — Formation Water Salinity. CPAI requests a finding in the ROP Orders that no freshwater aquifers are present in the ROP area. This request is to avoid duplicative reviews of whether there are freshwater aquifers in the ROP area in future annular disposal and injection well permit applications. Blowout Prevention General well control for drilling and completion operations will be performed in accordance with 20 AAC 25.035. Directional Drilling CPAI requests that the requirements described in 20 AAC 25.050(b) be waived for the proposed ROP to relieve administrative burden. CPAI proposes that the Conservation Order require the following in each Application for a permit to drill instead of the information required by 20 AAC 25.050(b): 1) plan view 2) vertical section 3) close approach data 4) directional data Well Spacing CPAI requests that the requirements described in 20 AAC 25.055 be waived for the proposed ROP because the proposed horizontal well development, via line -drive flood pattern, will yield greater recovery CPAI Application for Pool Rules, Rendezvous Oil Pool April 12, 2021 Page 21 of 53 than a conventional vertical/slant well development plan with a minimum spacing rule. In lieu of the requirements under 20 AAC 25.055, CPAI proposes that there shall be no restrictions as to well spacing except that no pay shall be opened to a well within 500 feet of an external GMTU boundary line where the owners and landowners are not the same on both sides of the line. Permafrost base at ^1,000' NDss a Surface Casing K3' U farm 9i aleon_B6 Ndm_BS � u MOu H =Mzqm 11111111=11131111111 m�1 Figure 9: Annular Disposal Interval — K-3 Colville Group: Weakly consolidated, silty, medium gray daystone with some siitstone lenses. Nanushuk Group: Shallow marine deltaic sediments, like Colville, but more lithi ied. Torok Group: Series of st slope to deep marine sedimentsforming 96 chnoforms. Mainly n marine shale with Interbedded turbiditic ?+ sands. CPAI Application for Pool Rules, Rendezvous Oil Pool April 12, 2021 Page 22 of 53 6. WELL OPERATIONS Well Design and Completions Production and injection wells will use 4-1/2 inch tubing to minimize friction associated with the high rate potential of the reservoir and the horizontal completions. Based on well performance, tubing size is subject to change. Producing wells will be equipped with gas lift mandrels. A single packer will provide pressure isolation for the tubing -casing annulus. Wells with liners placed in the horizontal segments may utilize combination liner hanger/packers. Artificial Lift Artificial lift will be via gas lift; however, CPAI may employ other techniques (jet pump, electrical submersible pumps, etc.) to optimize reservoir pressure drawdown as the reservoir matures. Dry gas will be delivered to the drillsite at approximately 4,000 psi and the pressure will be dropped down to approximately 2,000 psi for the purposes of gas lift. Reservoir Surveillance CPAI requests that the Commission approve the reservoir pressure monitoring plan set forth in Section 8, Rule 6 of this application. The pool common datum for reporting should be -8,108 feet TVDss. Well Work Operations Well work operations in the ROP will include routine mechanical integrity tests of each wellbore and artificial lift maintenance. Operations will also include remedial management of scale, paraffins and other well issues with slickline, inhibitor, or hot diesel treatments. Stimulation Stimulation techniques, including hydraulic fracturing, is planned for the producers at GMT2. Wellbore trajectories, cementing programs, and tubulars will be designed to accommodate hydraulic fracture stimulation techniques. Hydraulic stimulation operations will be performed in accordance with 20 AAC 25.283. Well Safety Valve System GMT2 wells will be equipped with vertical trees. The installation and inspection and testing of safety valve systems will be conducted following notification of the AOGCC consistent with the requirements of 20 AAC 25.265. Well Instrumentation and Monitoring Wells will be equipped with instrumentation and monitored in real-time at the ACF. CPA[ plans to install the following instrumentation: • Tubing pressure and temperature Inner annulus pressure • Outer annulus pressure • Bottomhole pressure (producers) Gas lift rate (producers) • Water and enriched gas injection rate (injectors) CPAI Application for Pool Rules, Rendezvous Oil Pool April 12, 2021 Page 23 of 53 7. FACILITIES Drill Site Facilities and Flowlines The ROP will be developed from the new MT7 drillsite which will connect to the ACF for production processing and delivery of dry gas, enriched gas, water, and electricity. See Figure 10. MT7 is not a normally manned drillsite, however, a drillsite operator will be present on the drillsite every day except in extreme weather. The MT7 design requires minimal operator presence for operations. Monitoring of critical well and facility information, and routine operations are accomplished remotely from the ACF control room. The following facilities are located at MT7: • 2-Phase test separator with gas metering, liquid metering and Phase -Dynamics metering for oil and water fractions of the liquid 3-Phase production separator with metering for oil, gas, and water Production Heater • Pipe Racks for 36 wells on 20 foot center spacing Modules for emergency shutdown (ESD), pigging, fuel gas, chemical injection, remote electrical interface module (REIM) and switchgear Production wells selectively flow to either the production separator via the production header or to the test separator via the test header. Test separator fluids flow into the production separator before leaving the drillsite. At the outlet of the production separator, the total drillsite oil, water, and gas streams are measured prior to being commingled in a new 20 inch cross-country flowline to the ACF where GMTU production is commingled with CRU production. Dry gas used for both fuel and gas lift will arrive via a 6 inch line. Injection wells selectively connect to either the water injection header or the enriched gas injection header. Water injection arrives via a new 14 inch flowline connecting MT6, MT7, and CD5 drillsites to the ACF. Expected water injection arrival pressure at MT7 is approximately 2,650 psi. Enriched gas injection arrives via a new 8 inch flowline connecting MT7 to the existing line from MT6 and CD5. Expected enriched gas arrival pressure at MT7 is approximately 4,000 psi. The pipeline rates of both dry gas and enriched gas are measured at the CD5 pad prior to arriving at the MT7 drillsite. Production Processing ROP production will be commingled with production from other GMTU and CRU pools prior to processing at ACF. Stabilized oil production will be delivered to the Alpine Pipeline and then on to the Trans -Alaska Pipeline System (TAPS). GMTU and CRU wells connected to the ACF will be managed and prioritized to maximize oil production rate in conformance with facility limits. ROP gas production will be processed in the ACF. ROP will provide its share of ACF fuel and flare requirements and some gas will be returned to GMTU (ROP + LOP) in the form of dry gas for either gas lift and drillsite fuel or in the form of enriched gas for enhanced recovery purposes. When GMTU gas production is greater than GMTU gas usage requirements, this excess gas production will be injected into CRU pools for enhanced recovery purposes. On a cumulative basis, GMTU gas production is expected to be greater than GMTU usage requirements, resulting in a net injection into CRU pools. It is anticipated that there will be periods, particularly when initiating enriched gas injection cycles in ROP wells, and possibly for startup, that GMTU gas production is less than, or deficient from, total GMTU gas requirements, and a sale of gas from CRU to GMTU will be required to cover the deficiency. For waterflood enhanced oil recovery, the initial plan is to provide seawater to the ROP for waterflood injection to maintain reservoir pressure and enhance oil recovery. In the future, produced water from the ACF may also be injected in the ROP. CPAI Application for Pool Rules, Rendezvous Oil Pool April 12, 2021 Page 24 of 53 ROP water production is expected to be very low until breakthrough of water injection occurs. ROP water production, after delivery to ACF and commingling with water from other CRU pools, will be injected into CRU pools for enhanced recovery purposes or possibly returned to the ROP. ROP production is expected to be fully compatible with the LOP and other CRU pools' production from both a production processing and injection perspective. The ROP is a very close analog to the ACID because both pools share a similar geologic history with the same oil charge source (Lower Kingak) and comparable structural and depositional schemes. ROP water production will be a mixture of connate water and seawater or ACF produced water and it is not expected to be significantly different than LOP or ACID 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 ROP will be similar to those at LOP and other CRU pools. Metering CPAI applied to the AOGCC for approval of its approach to GMT2 production measurement on July 12, 2018. Consistent with that order, metering points for production, injection gas, and dry gas are shown in Figure 10. More specific metering details for production custody transfer of oil and gas have been provided in the GMT2 Production Separator Metering Application submitted to the AOGCC on September 24, 2020. Metering details for return gas custody transfer have been provided in the CRU Gas Metering Application submitted to the AOGCC on October 9, 2017, Production Allocation In accordance with AOGCC Other Order 148 dated December 19, 2018 and BLM Sundry Approval for Oil Measurement by Other Methods and Redundancy Verification of Oil Measurement Secondary Pressure and Temperature Instruments Greater Moose's Tooth Unit (Rendezvous) dated July 1, 2019, ROP production will receive an allocation factor of one (1.0). Other Order 148 also permits the waiver of the requirements of 20 AAC 25.228 to allow for fiscal allocation of production from GMT2 to be based on a metering system that does not meet custody transfer quality standards. Production allocation to individual production wells in the ROP will be performed in the same manner as other North Slope fields. Wells will be tested at least monthly and the well tests will be used to create performance curves to determine the daily theoretical production from each well. An allocation factor comparing actual total daily ROP production sales to the sum of individual well theoretical rates will be used to adjust theoretical well production to allocated well production. CPAI Application for Pool Rules, Rendezvous Oil Pool April 12, 2021 Page 25 of 53 0 :-e® Q GMTI IrgeWW C� O . ,.. GMT1 Pr Rand... GMT2 Dry Gas InjeMn Injectbn and Gas Lift ~ Metered at Each Well GMT2 Enrkhed Gas Injection GMT2Waterinjecuon GMT2 GMT unit i CoMXe Film Unit O CRU Dnllsi¢s • Total gas metered at CD5 before leaving CRU • Total gas will be metered again separately at GMTI and GMT2 • Production metered at GMTI and GMT2 separately through 3 phase separator before commingling • Production will be allocated back to individual wells from well tests • Gas and water injection metered at each individual well • Gas lift metered at each individual well • Red circles = AOGCC custody meters Figure 10: GMT2 Facilities and Metering, red circles are AOGCC custody meters CPAI Application for Pool Rules, Rendezvous Oil Pool April 12, 2021 Page 26 of 53 8. PROPOSED REDEZVOUS OIL POOL RULES The rules set forth apply to the following area referred to in this order: I Imiat Maridian Township Range Sections 4-5: All 8: NE1/4 T8N R1E 9:N1/2 1-3: All 4: N1/2, SE1/4 10: N112, SE1/4 11-14: All 15: NE1/4, S1/2 21: NE1/4, S112 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: N112 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 CPAI Application for Pool Rules, Rendezvous Oil Pool April 12, 2021 Page 27 of 53 3: NW1/4, S1/2 4-10: All 11: NWt/4, S1/2 12: S1/2 T1ON R2E 13-36: All 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 - Field and Pool Name The field is the Greater Moose's Tooth Field. The pool is the Rendezvous Oil Pool (ROP). Rule 2 - Pool Definition 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 in the Rendezvous No. 2 well. Rule 3 - Well Spacing There shall be no restrictions as to well spacing except that no pay shall be opened to a well within 500 feet of an external property line where the owners and landowners are not the same on both sides of the line. Rule 4 - Drilling Waivers All permit to drill applications for deviated wells within the ROP shall include a plat with a plan view, vertical section, close approach data and a directional program description in lieu of the requirements of 20 AAC 25.050(b). Rule 5 Well Logging and Sampling Requirements a. A suite of petrophysical well logs including, at a minimum, gamma ray, resistivity, neutron porosity, and density porosity logs shall be acquired across the ROP in one well from each drillsite. Gamma ray or resistivity curves shall be recorded from base of conductor to total CPAI Application for Pool Rules, Rendezvous Oil Pool April 12, 2021 Page 28 of 53 depth in each well. The AOGCC may require additional wells to be logged using one or more petrophysical logging tools. b. A mud log and cutting samples shall be obtained from the base of the conductor through the ROP in at least one well drilled from each drillsite. Rule 6 - Reservoir Pressure Monitoring a. A bottom -hole pressure survey shall be taken on each well prior to initial injection. b. The operator shall obtain the pressure surveys needed to manage properly the hydrocarbon recovery processes subject to the annual plan outlined in Rule 8 below. At a minimum, a pressure survey shall be acquired from at least one well on each drill site each year. c. The reservoir pressure datum will be -8,108 feet TVDss. d. Pressure surveys may consist of stabilized static pressure measurements at bottom -hole or be extrapolated from surface measurements (single phase fluid conditions), pressure fall -off measurements, pressure buildup measurements, multi -rate test results, drill stem test results, and open -hole formation tests or other methods approved by the AOGCC. e. A Reservoir Pressure Report, Form 10-412, shall be utilized for all surveys; all relevant data shall be attached to the report. The data submitted shall include, at a minimum, rate, pressure, depth, fluid gradient, temperature, and all other well conditions necessary for a complete analysis of each survey being conducted. f. The results and data from any special reservoir pressure monitoring tests or surveys shall also be submitted in accordance with paragraph (e) of this rule. Rule 7 - Gas -Oil Ratio Exemption Wells producing from the ROP are exempt from the gas -oil -ratio limits of 20 AAC 25.240(a) so long as the provisions of 20 AAC 25.240(b) apply. Rule 8 - Annual Reservoir Review An annual reservoir surveillance report must be filed by April 1st of each year and include future ROP development plans, reservoir depletion plans, and surveillance information for the prior calendar year, including: a. The voidage balance, by month, of produced fluids and injected fluids; b. A summary and analysis of the reservoir pressure surveys within the pool; c. The results and, where appropriate, an analysis of production and injection log surveys, tracer surveys, observation well surveys, and any other special monitoring; d. A review of pool production allocation factors and issues over the prior year; e. A review of the progress of the enhanced recovery project. Rule 9 - Annular Pressures a. At the time of installation or replacement, the operator shall conduct and document a pressure test of tubulars and completion equipment in each development well that is sufficient to demonstrate that planned well operations will not result in failure of well integrity, uncontrolled release of fluid or pressure, or threat to human safety. b. The operator shall monitor each development well daily to check for sustained pressure, except if prevented by extreme weather conditions, emergency situations, or unavoidable circumstances. Monitoring results shall be kept available for AOGCC inspections. c. The operator shall notify the AOGCC within three working days after the operator identifies a well as having (i) sustained inner annulus pressure that exceeds 2,000 psig or (ii) sustained outer annulus pressure that exceeds 1,000 psig. d. The operator shall submit in an Application for Sundry Approvals (Form 10-403) a proposal for corrective action or increased surveillance for any development well having sustained pressure that exceeds a limit set out in paragraph (c) of this rule. The AOGCC may approve the operator's proposal or require other actions or surveillance, including a mechanical integrity test or other approved diagnostic tests. The operator shall give sufficient notice of the testing schedule to allow the AOGCC to witness the test. e. If the operator identifies sustained pressure in the inner annulus of a development well that exceeds 45 percent of the burst pressure rating of the well's production casing for inner annulus pressure, or CPAI Application for Pool Rules, Rendezvous Oil Pool April 12, 2021 Page 29 of 53 sustained pressure in the outer annulus that exceeds 45 percent of the burst pressure rating of the well's surface casing for outer annulus pressure, the operator shall notify the AOGCC within three working days and take corrective action. Unless well conditions require the operator to take emergency corrective action before AOGCC approval can be obtained, the operator shall submit in an Application for Sundry Approvals (Form 10-403) a proposal for corrective action. The AOGCC may approve the operator's proposal or require other corrective action, including a mechanical integrity test or other diagnostic tests. The operator shall give the AOGCC sufficient notice of the testing schedule to allow the AOGCC to witness the tests. Except as otherwise approved by the Commission under (d) or (e) of this rule, before a shut-in well is placed in service, any annulus pressure must be relieved to a sufficient degree: (1) that the inner annulus pressure at operating temperature will be below 2,000 psig, and (2) that the outer annulus pressure at operating temperature will be below 1,000 psig. A well subject to (c) but not (e) of this rule may reach an annulus pressure at operating temperature that is described in the operator's notification to the AOGCC under (c) of this rule, unless the AOGCC prescribes a different limit. For purposes of this rule, i. inner annulus means the space in a well between tubing and production casing; ii. outer annulus means the space in a well between production casing and surface casing; and iii. sustained pressure means pressure that (A) is measurable at the casing head of an annulus, (B) is not caused solely by temperature fluctuations, and (C) has not been applied intentionally. H Rule 10 - Production Surface Commingling, Measurement and Allocation a. Production from ROP maybe commingled on the surface with production from the other pools within the GMTU as well as with production from the CRU. b. Wells must be tested monthly. Rule 11 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 Pool Rules, Rendezvous Oil Pool April 12, 2021 Page 30 of 53 List of Acronyms Alaska Oil and Gas Conservation Commission (AOGCC) Alpine Central Facility (ACF) Arctic Slope Regional Corporation (ASRC) Area Injection Order (AIO) Barrel (BBL) Bear Tooth Unit (BTU) Blowout Prevention Equipment (BOPE) Bureau of Land Management (BLM) Centipoise (cP) Colville Delta 5 (CD5) Colville River Unit (CRU) ConocoPhillips Alaska, Inc. (CPAI) Conservation Order (CO) Emergency Shutdown (ESD) Enhanced Oil Recovery (EOR) Enriched Water Alternating Gas (EWAG) Extended Reach Drilling (ERD) Formation Integrity Test (FIT) Gas -Oil Contact (GOC) Gas Oil Ratio (GOR) Greater Moose's Tooth 1 (GMT1) Greater Moose's Tooth 2 (GMT2) Greater Moose's Tooth 2 Expansion (GMT2X) Greater Moose's Tooth Unit (GMTU) Highly Radioactive Zone (HRZ) Lookout Oil Pool (LOP) Managed Pressure Drilling (MPD) Measured Depth (MD) Millidarcy (mD) Million Barrels (MMBBLS) Million Barrels of Oil (MMBO) Million Standard Cubic Feet (MMSCF) Modular Formation Dynamics Testing (MDT) Moose's Tooth 6 (MT6) Moose's Tooth 7 (MT7) Oil -Water Contact (OWC) Original Gas -in -Place (OOIP) Original Oil -in -Place (OOIP) Participating Area (PA) Pounds Per Square Inch (PSI) Remote Electrical Interface Module (REIM) Rendezvous Oil Pool (ROP) Reservoir Barrel (RB) Standard Cubic Feet (SCF) Steerable Drilling Liner (SDL) Stock Tank Barrel (STB) Stock Tank Barrel Oil (STBO) Thousand Cubic Feet of Gas (MSCF) Trans -Alaska Pipeline System (TAPS) Trillion Cubic Feet (TCF) True Vertical Depth Subsea (TVDss) Upper Jurassic Unconformity (UJU) Working Interest Owners (WIO) CPAI Application for Pool Rules, Rendezvous Oil Pool April 12, 2021 Page 36 of 53 APPENDIX 2 — FORMATION WATER SALINITY Salinity Calculations In the Greater Moose's Tooth Unit, Rendezvous Pool 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. Well Stratigraphic Zone Depth (MD) TDS Rendezvous 2 K-3 3056-3170 ft 18,000ppm Rendezvous 2 K-2 3331-3406 ft 16,000ppm Rendezvous 2 Albian 97 3554-3640 ft 18,000ppm Rendezvous A Albian 96 3655-3699 ft 17,000ppm Spark 1 Albian 95 3820-3853 ft 24,000ppm Rendezvous 3 Albian 94 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, 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. Mitre1PB1 C-40 1700-1860ft 31,000ppm Mitre 11PB1 C-30 2248-2276 ft 27,000ppm Tiqmiaq 2 K-3 2380-2500 ft 14,000ppm Flat Top 1 K-2 3814-3840 ft 13,000ppm Flat Top 1 Albian 97 4030-4160 ft 13,000ppm Lookout 2 Albian 96 4100-4200 ft 17,000ppm Lookout 1 Albian 95 4400-4459 ft 16,000ppm Tiqmiaq 6 Albian 93 3240-3260 ft 17,000ppm 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: Rwa _ Om Rt 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 C132-11 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. CPAI Application for Pool Rules, Rendezvous Oil Pool April 12, 2021 Page 37 of 53 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 = 2.019/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 NaCI 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 Rt = 5.44ohm-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. CPAI Application for Pool Rules, Rendezvous Oil Pool April 12, 2021 Page 38 of 53 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 = 2.31 g/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 NaCl 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. 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. CPAI Application for Pool Rules, Rendezvous Oil Pool April 12, 2021 Page 39 of 53 Water sample analyses A water sample was obtained from Ti0miaq 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). Rendezvous Area Type Log — Shallow Salinity Analysis Summary Permafrost deville Group (Clay with terbedded silt & minor nds) enushuk Group (K-3 to Albian i; top sets, shallow marine, is/shales and thin fine- ained sands )rok (Albian slope & deep anne shales with inter- >dded sands) S Fili RZ/Kaiubik/Miluveach Shales Ipine C Sandstone (Target) Figure 15: Formation water salinity summary with the Rendezvous type log (Rendezvous 2) and lithology summary. CPAI Application for Pool Rules, Rendezvous Oil Pool April 12, 2021 Page 40 of 53 Appendix 3 — Annular Disposal of Drilling Waste at CD5 ConocoPhillips November 7, 2014 Cathy P. Foerster Commissioner, Chair Alaska Oil and Gas Conservation Commission 333 W. 7th Avenue, Suite 100 Anchorage, Alaska 99501.3539 Re: Annular Disposal of Drilling Waste at CD5 Dear Commissioner Foerster: Misty J Alex® WNS Dovelopmont Manager P.O. Box 100360 Anchorago, AK 99510 (907) 265-6822(phone) misty.i.alexa@conocophillips.com Hand Delivered ConocoPhillips, as operator of the Colville River Unit (CRU) on the North Slope, Is engaged in the development of a new drilisito, called CDS. This new development will make use of existing infrastructure and bring additional oil production to TAPS. ConocoPhillips plans to commence drilling in April 2015, and to see first production in December 2015. The plan for CD5 is predicated on an expectation that drilling muds and cuttings (drilling waste) will be pumped into the annuli of development wells on the pad, an Alaska Oil and Gas Conservation Commission (AOGCC) approved practice that has worked well at the CRU for many years. By this letter, ConocoPhillips is notifying AOGCC of our intent to seek authorization for annular disposal of drilling waste at CD5 under 20 AAC 25.080 when drilling begins. This notice is based on our understanding that AOGCC may wish to hold a hearing on this topic before proceeding to review applications for annular disposal authorization under the applicable regulation and according to the normal process. On January 29, 2013, ConocoPhillips provided a CD5 Drillsite Project Overview to AOGCC staff. In this meeting and in follow-up informal discussions as recently as July 16, 2014, AOGCC staff expressed caution and informed ConocoPhillips of potential future changes within the AOGCC regarding authorization for annular disposal of drilling waste. To avoid potential delay in CD5 development, ConocoPhillips seeks to identify any potential issues with respect to authorization of annular disposal. If a hearing is desired by AOGCC, ConocoPhillips strongly prefers that it be held soon for planning purposes, before drilling begins at CD5. The regulation governing annular disposal, 20 AAC 25.080, requires well -specific information in the request, and that information is not available until the well that will be used for disposal has been drilled. So. ConocoPhillips cannot request authorization for annular disposal until drilling begins at CD5. Yet for planning purposes, ConocoPhillips has a strong interest in confirming the expectation that a future request for annular disposal authorization will be considered by the AOGCC under the existing regulations and in a manner consistent CPAI Application for Pool Rules, Rendezvous Oil Pool April 12, 2021 Page 41 of 53 with past practice at other CRU drillsites. If future permitting for annular disposal at CD5 will be more restrictive, the implications could be significant and wide-ranging. Annular disposal of wastes from the drilling of development wells is an agency approved practice that dates back decades. The practice is regulated by the AOGCC as an activity incidental to the drilling of a well, outside the scope of the federal underground injection control (UIC) program. This understanding of the nature of annular disposal was documented in the Memorandum of Agreement between the AOGCC and the U.S. Environmental Protection Agency (EPA), Region 10, which was signed by the EPA on November 21, 1991, and signed by the AOGCC on November 22, 1991. Section 10 of that Memorandum provides: "The pumping away of drilling muds ... into an exploration well or stratigraphic test well, or into the annuli of any well approved in accordance with 20 AAC 25.005, is an operation incidental to the drilling of the well, and is not a disposal operation subject to regulation as a Class II well' Since then, the AOGCC has adopted regulations that provide for the authorization of annular disposal. The regulations were adopted in 1996, amended in 1999, and are codified at 20 AAC 25.080. Subsection (a) of that regulation prohibits annular disposal except as authorized by the AOGCC. Subsection (b) lists the extensive, detailed information that an operator must provide in connection with a request for authorization of annular disposal. Subsection (c) provides that the AOGCC "will authorize" annular disposal 0 the commission makes certain determinations. That subsection, 20 AAC 25.080(c), reads as follows: The commission will authorize an annular disposal operation described in the Application for Sundry Approvals, as that application has been supplemented under this section, and subject to any modifications prescribed by the commission, if the commission determines that the (1) waste will be adequately confined; (2) disposal will not (A) contaminate freshwater, except to the extent allowed under (e)(91) [presumably, (e)(1)); (B) cause drilling waste to surface; (0) impair the mechanical integrity of any well; or (D) damage a producing or potentially producing formation or impair the recovery of oil or gas from a pool; and (3) disposal will not circumvent 20 AAC 25.252 or 20 AAC 25.412. Subsection (d) of the regulation imposes presumptive limits on annular disposal, including a volume limit of 35,000 barrels per well, and a temporal limit of one year per well. The remainder of the regulation provides for other potential conditions and Imposes specific reporting and other obligations on operators in connection with annular disposal. Annular disposal, as governed by 20 AAC 25.080, has worked well at CRU tot years. It has allowed for the efficient placement of drilling waste in a manner that avoids the use of CPAI Application for Pool Rules, Rendezvous Oil Pool April 12, 2021 Page 42 of 53 reserve pits, and avoids the risks and complications associated with hauling waste in tanker trucks and the associated transfers. The end result is that drilling fluids and cuttings that are generated in the course of drilling a well are generally disposed of in the annuli of wells on the same pad. This is a good solution for a place like the CRU, which has an extremely small gravel footprint and does not have permanent road access to landfill facilities, which is the common disposal option for drilling wastes in the Lower 48. Annular disposal helps maintain the capacity of permitted Class I and Class 11 UIC wells for disposal of substances other than drilling waste, which is especially important at CRU, where a lack of a road system severely limits alternative options in case a UIC well encounters problems. ConocoPhillips believes the incident -free history of annular disposal at CRU supports continuation of the practice at the new CD5 pad. But because the UIC wells are needed for disposal of non -drilling waste, it is important to have options for drilling waste disposal. The large amount of drilling waste slurry anticipated from CD5, if injected at a UIC dispose] well at CD1, would increase the risk of a problem at that well. If a UIC disposal well is removed from service, it poses a very real risk of having to shut down not just drilling operations but also other operations at CRU, because without road access to other waste disposal options, there may be no place to put wastes that must go in a UIC well. Authorization for annular disposal of drilling waste at CRU provides important flexibility, and the option should continue with the C05 development. Geology in the vicinity of CD5 presents a good opportunity to use annular disposal in compliance with the criteria of 20 AAC 25.080 and good oiHieid engineering practices. CD5 is premised on developing existing CRU reservoirs. ConocoPhillips has shared information on CD5 geology with AOGCC staff, and no geological Impediment to annular disposal has been identified. The AOGCC Disposal Injection Order No. 18 for the Colville River Unit expressly notes, at finding 14, that ConocoPhillips plans annular disposal of muds and cuttings at CRU, and Rule 3 of that order even requires notice to AOGCC 0 the operator expects to initiate routine disposal of drilling waste into the approved Class II well. Annular disposal of drilling mud and cuttings has been an integral and successful part of CRU development. Over 85 CRU wells have been permitted under 20 AAC 25.080 and successfully used for annular disposal in the CRU to dispose of 2,600.000 barrels of muds and cuttings. This has been a successful program because ConocoPhillips has rigorously complied with 20 AAC 25.080. A key to ensuring that drill cuttings are disposed into the intended zone is real time monitoring of the calculated bottom hole injection pressure (real time fluid density, wellhead pressure and friction calculation). The calculated BHIP is continuously monitored against the surface shoe formation integrity pressure to ensure the confining zone's integrity is not compromised. Conservation Order 443 for the Alpine Oil Pool in the Colville River Field recognizes at finding 14 that the operator intends to dispose of drilling waste in the annuli of wells authorized by the Commission, and recognizes at finding 21 that the available data indicate annular disposal can occur without causing fractures near the surface casing shoe. ConocoPhillips is not aware of any change that would make the plan for annular disposal any less viable now for CD5 than it has been for other pads at CRU. If a future request for authorization for annular disposal at C05 is considered in a manner consistent with other applications at CRU in the recent past, ConocoPhillips expects to be able to receive authorization for annular disposal. CPAI Application for Pool Rules, Rendezvous Oil Pool April 12, 2021 Page 43 of 53 However, 0 the AOGCC intends to treat an annular disposal request for CD5 differently than such requests have been treated for other CRU pads, then ConocoPhiilips would like to understand the basis for this change as early as possible. At this point, ConocoPhillips does not see any option at CD5 that could serve as a good substitute for annular disposal, so if annular disposal is preemptively precluded, the planning basis for CD5 development would have to be reconsidered. AOGCC staff has expressed a desire for a public hearing to discuss annular disposal at CD5, but a hearing is not required by the regulations, and should not be necessary in our view. ConocoPhiilips does not oppose a hearing, however, and to help progress this issue we are providing this notice and background information to give the AOGCC the opportunity to hold a hearing, if it chooses to do so, on the issue of annular disposal at CD5. If you have any questions or need further information please contact Sam Johnstone (907) 263-4617. Sincerely, Misty Alexa WNS Development Manager cc: Anadarko E&P LLC CPAI Application for Pool Rules, Rendezvous Oil Pool April 12, 2021 Page 44 of 53 Appendix 4 — Docket OTH 14-026 Annular Disposal of Drilling Waste at CD5 1'I IF .14NI P. 01ALASKA (;()VI 14NOR I411I 10ALKLIt Ms. Misty J Alcxa WNS Developinem Manager ConocoPhillips Alaska, Inc. P.O. Box 100360 Anchorage, AK 99510-0360 Alaska Oil and Gas Conservation Conunissiou :I:LM1 wcH Somadh Avrnnee Mch,uosw, Alasko 99501 3577 Moira: WU.'7/9. 1433 tax: 901216.1547 January 16,2015 www.,uKlcr.aWcto Spv CERTIFIED MAIL — RETURN RECEIPT REQUESTED 7012 3050 0001 4812 7058 Re: Docket OTH 14-026 Annular Disposal of Drilling Wasic rat CD5 Dear Ms. Alexa: Based upon the evidence presented by Conoco Philips Alaska Inc. (CPAI), at the January 5, 2015 hearing, until such time as CPAI seeks authorization for annular disposal the Alaska Oil and Gas Conservation Conunission (AOGCC) will take no further action on the matters raised in CPAI's November 7, 2014 letter to AOGCC. DONE at Anchorage, Alaska and dated January, 16, 2015. Cath . Foerster Chai , Commissioner CPAI Application for Pool Rules, Rendezvous Oil Pool April 12, 2021 Page 45 of 53 Appendix 5 — CDS-93 Annular Disposal Sundry and Approval CPAI Application for Pool Rules, Rendezvous Oil Pool April 12, 2021 Page 46 of 53 Note to File CRU CD5-93 (PTD 221-073) February 16, 2021 Re: ConocoPliflips' Application for Sundry Approval for Amular Disposal of Drilling Wastes within Well CD5-93 Request ConocoPhillips requests approval to dispose of 35,000 barrels of drilling waste in well C'RU CD5-93 Recommendation Approve ConocoPhillips' request Conclusions 1. In CD5-93. the surface casing shoe is set at 2,194' measured depth (,AID: equivalent to-2,115' true vertical depth subsea), near the base of a 450-foot thick shale-, claystone-, and siltstone-dominated interval that persists throughout the area. This interval will prevent upward migration of injected fluids. 2. There appears to be a sufficient volume of sandstone and sandy siltstone open to the annulus of this well to accept the proposed injected fluids- 3- Lower confining layers are sufficiently thick and laterally persistent to ensure injected materials remain within the disposal interval. 4. There are no potential USDA's in this area. There are no water wells within one mile of CD5-93. 5. Correlative rights will be protected. 6. The proposed disposal injection operations will not affect potential oil or gas reservoirs- 7- The volume of sediments most strongly impactedbytheproposed annular injection operation will likely lie within about 100' of the CD5-93 weeilbcre. S. Injected fluids will likely reach one or more nearby wells that have open annuli beneath their surface casing shoes. However. if this occurs. surface casing, surface casing cement (to surface), and thick laterally continuous confining layers of shale. claystone. and siltstone will ensure injected fluids remain within the disposal interval - Discussion ConocoPhillips' application was renewed along with records from Cohille River Unit CD5-93 (CD5-93). nearby development wells, and exploratory well Nuigsut 1, which is located 1-1/2 miles to the northeast - The discussion that follows is based on information, well logs, and mud logs from these wells. An index map is provided in figure 1, below. The proposed annular disposal injection interval in this well lies in the Torok and Seabee Formations within Section 7, TI IN, ME, Umiat Meridian- which is about 2 miles from the current e2derior boundary of the Colville River Unit The surface casing shoe of CD5-93 lies at 2,194' MD (-2,l l5' TVDSS), near the base of a 450-foot thick interval that is dominated by shale, claystone, and siltstone and is continuous throughout 3 Unless nds¢vivarced, aII depda pres®eed hsem ns posith'e mte:�srepreseut auassed depsh m feet All depths expressed as cep&, mtegecs tepreseai Ave rsi al depth(m feet) belo*mess sea tesvl(man lam, lmr Crater, herein termed = a v al feet subsea, whtch is abbmuted' Tt•DS5'). ,V! mi:laesua se aspressed as msm.e imeress, nidch represent true s eeticnl feet A[I hortaaatat distances as e�p¢esud asposima msegm. nfach repres�t Ceet CPAI Application for Pool Rules, Rendezvous Oil Pool April 12, 2021 Page 47 of 53 CD5-93 Annular Disposal February 16, 2021 Note to File Page 2 of 5 the area. This interval will provide upper confinement for fluids disposed in the annulus of the well (see Figure 2, below). In CD5-93, the annulus open to disposal extends downward from the surface casing shoe at 2194' N D (-2,115' TVDSS) to the top of second -stage cement for the 7-518" casing string, which is estimated to lie at 4,5361vm (-3,849- TVDSS). The portion of the open annulus that will most likely accept the injected waste is a 185-foot thick interval that contains several 1- to Moot thick beds of sandstone and sandy siltstone that lie below the surface casing shoe between about 2,332' MD (-2,250' TVDSS) and 2520' MD (-2,435' TVDSS) The aggregate thickness of these thin, potential receptor layers is about 30'_ These layers are separated by thin claystone intervals. Beneath the disposal interval are several intervals of claystone that are continuous throughout the area and will provide lower confinement for any injected wastes. COS-93 Top of r , Open :lus Second -Stage ``� Cement for t C . intermediate ,'....OS93 Crimes ♦ Surface . Casng . shoe f« CUS•93 NORTH Mast U 1 p l Interval i ! surface Casing 0-S00 feet �1 Shoe locations ♦; AL A Figure 1. CD5-93 Index hlap (The magenta -colored line deports the path of the cross-section displayed in Figure 2.) The index reap above displays trajectories for all wells drilled from the Colville River Unit CD5 Drill Site. The locations of the surface casing shoes for all well bores are depicted with green -colored triangles. The calculated top of second -stage cement for the CD5-93 intermediate casing string (4536' MD.-3.849' TVDSS) is indicated by the orange -colored semi -circle. Thirty three wells are currently open to these same strata wathin the'./4-mile radius area of review: CD5-01, CD5-02, CD5-03, CD5-04, CD5-05, CD5-06, CD5- 07, CD5-08, CD5-09, CD5-10, CD5-I1, CD5-12, CD5-17, CD5-18, C135-19, CD5-20, CD5-21, CD5-22, CD5-23, CD5-24. CD5-25. CD5-26, CD5-28, CD5-90. CD5-92. CD5-96, CD5-98. CD5-99A. CD5-313. CD5-314, CD5-314X CD5-315, and CD5-316. Figure 2, below, presents a swxmral cross-section view of CD5-93 and nearby wells CD5-19 and CD5-01, which were logged to the ground surface. Resistivity measurements indicate that the base of permafrost occurs at about-1,250' in the CD5 Drill Site area, which is about 865' above the CD5-93 surface casing shoe. CPAI Application for Pool Rules, Rendezvous Oil Pool April 12, 2021 Page 48 of 53 CD5-93 Annular Disposal Note to File February 16, 2021 Page 3 of S SW s1r1a1 s971m: w1o'.+auexr9a 2121 solwrorxuc r, zxxn9 z+sovc NE f.Pol C1iS 19 590' CNU G]S33 66D' CIN CIMOI r— e ."�; .. '<t •_. _ - .•anti __ _. . a 4" Surface ssa Casing -la�,. C % .. Cement 4 _ -3�� _. Surfacesao f� __— Surface Casing '- Casing ... 1� •faoo M permafrost `.. Cement sceaees' Cement Base at Zy�.. 777`iiiflf 'iDOo _ WEISS _1500 .15M Upper _ -Upper Corfiming —_ G_onfining ' - t Surface .MD - Interval 'Y �} interval �� Casing ♦-^� Shoe .wao _ Most Likety Disposalr— zwn Interval .300 lAV/er r Open Anmdus - Confining Leven i 3505 = Top of Cement ; 3550 4,536' MD, t"-3,849' TVDSS .. 4M Figure 2. C115-93 Area: Structural Cross-section (Depth scale represents true vertical feet. Horizontal separation footages shown between wells are the approximate distances between the surface casing shoes.) Mud togs were recorded in only two wells drilled at the CDS Drill Site. CD5-04 and CDS-313, that were drilled through the shallow, geologic section using somewhat similar drilling mud weights (typically 9.8 to 99 pounds per gallon). These mud logs suggest the shallow geologic section in the area contains predominantly methane gas. with minor amounts of ethane, propane_ and butane_ The shallowest occurrences of more significant amounts of methane encountered in these wells (arbitrarily placed at 20 units of gas --equivalent to 4.000 ppm—on the mud log) were about -1,850"and 2.000 respectively. So. the entire proposed annular disposal interval likely contains small, non-commefcial amounts of methane gas. CPAI Application for Pool Rules, Rendezvous Oil Pool April 12, 2021 Page 49 of 53 CD5-93 Ammar Disposal February 16, 2021 Note to File Page 4 of 5 Unfortunately, oil shores are not recorded on the mud logs obtained in CD5-04 and CDS-313, likely due to the use of oil -base drilling mud. In ARCO's Nmgsut 1 exploratory wvell, located about 1-112 miles to the northeast, the shallowest oil shoe° was encountered at 3.990' XM (-3,930' T4'DSS). with a second show encountered at 4,115' MD (-4,055' TVDSS). The mud logging geologists rated these shows as fair to poor in quality. These oil shows occur in thin sandstones that are encapsulated above and below by claystone and mudstone. These oil show indicate the presence of only trace to minor quantities of oil in the geologic strata that may be affected by annular disposal in CD5-93. These shows do not represent commercial quantities of oil. Supporting documentation to ConocoPhillips' annular disposal applications states: "There are no USDW aquifers in the Colville River Unit" This is correct Conclusion 3 of Area Injection Order No. 18, which governs the Alpine Oil Pool, states that there are no USDWs beneath the permafrost within the Colville River Unit. The Alaska Department of Natural Resources' Alaska ]supper web application, accessed February 16, 2021. confirm that there are no publicly recorded water wells within one mile of CD5-93. 200 Injected Fluid vs Affected Area Surrounding CRU CD5-93 Welibore {AftwVtrne; 30 0%pomoft, 50%naive B,W ftpWem", anreoWe sYWWW 30 Pttigh) 0 51000 10,am 15,000 20.000 25.000 30.000 35.000 AO ffl of majeoted Fluid tGa ism Figure 3. C105-93 .Area Lik-elc Affected by annular Injection (.Assuming uniform, piston-Ifim, radial displacement of 90% of native formation fluids) The gamma ray well log curve recorded in CD5-93 indicates that an aggregate total of about 30 true vertical feet of sandstone and sandy siitstone are present within the most likely disposal imervaL Inspection of density porosity logs from correlative strata in nearby wells suggests porosity averages about 300/a at this depth_ Based on these values, the volume of rock that will receive 35,000 barrels of injected fluids lies within a radius of about 1 20'fromthe CDS-93 wellbore, assuming uniform, radial, piston -like displacement ofhalf of the native formation fluids (Figure 3. above) The surface casing shoes of the three closest wells— CD5-07, CD5-10, and CD5-i I —are located between about 150' and 250' from the most likely disposal CPAI Application for Pool Rules, Rendezvous Oil Pool April 12, 2021 Page 50 of 53 CD5-93 Annular Disposal February 16, 2021 Note to File Page 5 of 5 interval within CD5-93. However, review of the daily drilling summaries indicates that surface casings in these three wells mere cemented to surface pith full returns. If fluids injected into CD5-93 reach uncemented annuhbeoeath the surface casing shoes in any ofthe three nearby wells, surface casing, surface casing cement and thick, laterally continuous confining layers will ensure those fluids remain within the inteuded interval- Srmmary The limited volume of rock that will be affected by this proposed annular disposal operation is situated beneath 1,250' of permafrost and is bounded above and below by continuous confining layers of shale, claystone, and siltstone. The disposal interval lies inside the Colville River Unit. far from any external property lines. so correlative rights are not a concern There are no freshwater aquifers present and there are no water wells within one mile of CD5-93_ The disposal interval does not include any potentially commercial hydrocarbon accumulations. Surface casing. surface -casing cement (to surface), and laterally continuous layers of shale, claystone. and siltstone will prevent injected fluids from migrating out of zone. I recommend approving the proposed annular disposal operations within CRU CDS-93 to the requested limit of 35,000 barrels. Steve Davies Senior Petroleums Geologist CPAI Application for Pool Rules, Rendezvous Oil Pool April 12, 2021 Page 51 of 53 Note to File CD5-93 (PTD 2200730, Sundry 321-082) Colville River Unit (Alpine Oil Pools) ConocoPhillips Alaska, Inc ConocoPhillips has made application to authorize annular disposal in the subject weft. This document examines the pertinent information for the well and recommends approval of ConocoPhillips' request. — No unusual events were reported while drilling the surface hole of the well (CD5-93). — 10 3/4" Surface casing was cemented to surface successfully with no losses experienced. Cement report put excess cement to surface of 54 bbis with 400 bbi Class G cement pumped. No problems reported- - On the initial Formation Integrity Test (FIT) for the surface casing shoe dated 1/18/2021, the pressure slope rises smoothly with test stopping at 1.5 bbl pumped and 810 psi to yield the desired 16.7 ppg EMW. The pressure declined slightly from 810 to 700 psi (15.75 ppg EMW) during the 10 minute shut in period with the 1.0 bbl being bled back. The initial FIT indicates that the surface casing shoe is well cemented. An open hole injectivity test was completed on 1/29/2021 prior to running and cementing the 7.625" casing with a depth of the casing shoe of 2195 It MD/ 2188 ft TVD and an open hole to est 4961 R MD yielding a 13.4 ppg EMW. The test showed pressure rising steadily with the slight tangent change at the 13.4 ppg EMW and a sharp break over point at approximately 13.67 ppg EMW. — The 7.625" casing was run and successfully cemented with a two stage job and shoe of 14525 ft. First stage cement was pumped and was estimated as 14525 to TOC 11650 ft MD_ Cement toot at 6050 ft was opened and the 2`a stage pumped without problems with that TOC estimated at 4536 ft MD. A "SonicScope Top of Cement" evaluation log processed on 2/1/2021 was run from 2475 ft MD to TO and shows a TOC of 11650 ft with improving cement to shoe. The sonic tool ran out of memory passing up at 4600 ft but indicated good cement from 6050 to approx. 4600 ft —There are multiple wells currently drilled or planned to be drilled within ''/. mile radius of CD5- 93 and the CPAI application contains supporting cementing and LOT well information and mentions that well and cementing information is already on file with AOGCC. The surface shoe of CD5-11 is closest, about 164' distant. AD is already prolific on CD5 and it is expected to continue with additional CD5 wells. CPA[ is therefore constructing the CD5 wells to be compliant with AD regulations Examination of the cementing information and LOT data did not reveal anything to preclude granting CPAI's request_ Based on examination of the submitted information, I recommend approval of ConocoPhillips' request for the subject well. Chris Waltace Sr. Petroleum Engineer AOGCC February 16, 2021 C-1UserslsjcarbsleWppDataTocallKicrosoR\Windoii�sTR etCachelContent.OutlookO37BF41,VQ1 10216 CDS-93 note to file.doc CPAI Application for Pool Rules, Rendezvous Oil Pool April 12, 2021 Page 52 of 53 Appendix 6 — MT6-05 Annular Disposal Sundry and Approval THE STATE OfALASKA GOVERNOR BILL WALKER Chip Alvord Drilling Manager ConocoPhillips Alaska, Inc. PO Box 100360 Anchorage, AK 99510 Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage, Alaska 99501 Main: 907.297.1433 Fax: 907.276.7542 www.00gcc.aIoska. gov Re: Greater Mouses Tooth Field, Lookout Oil Pool, MT6-05 Permit to Drill Number: 218-045 Sundry Number: 318-395 Dear Mr. Alvord: Enclosed is the approved application for the sundry approval relating to the above referenced well. Please note the conditions of approval set out in the enclosed form. Per 20 AAC 25.080, only drilling waste may be disposed within the 9-5/8" X 13-3/8" annulus of well MT6-05. As provided in AS 31.05.080, within 20 days after written notice of this 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. A request for reconsideration is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. Sincerely, 1 Hollis S. French Chair, Commissioner DATED this 1 day of November, 2018. CPA] Application for Pool Rules, Rendezvous Oil Pool April 12, 2021 Page 53 of 53 FIECENED STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION SEP 1 2010 ANNULAR DI SPOS LAPPLICATION 60110 AOGLC 1. Dpmew 3. Parma b Dr10 Nrnc M-M ConoeoPlMlllps Alaska a. API Number: 50.103.213771-00.00 2. Addma: S. Was P.O. Bo* 1002e0, A,deape. Abeks MT"s 8. Rob: CoMile River Unb- Alone Pod 7. gABrty recoNedi area S. Slrenyaplac desalpbom a) All with rAmM ars grader mib: a) IrdWv9l avpoeed to open amWis: WIT-03, MT8-08 Taok and Seabee lemeaboa slugs, sllsbrd and sandslone b) Waab roeeaag ma: b) wager ealewWM ore rho: Band Iayern baaa Oro Me marke, b the $resew fowadm Nab C)CdNnement rho SClfader Wllnb,T61011pn1YaiaG MU{aer Wlderand amae away nd deraWaa a vm,w0ln TamR Fameaen %ease a genre barrier 9. Oepdu b Wee olperamheet 10. Hydrocubar aenan aeeae waa a reaMrg mm: approoMlaley 1,200' MD and 119V ND None I L Prevtwa volume dapoeW Jr, Weeks and dab: 12, Eatlmeled iii derdgr. 13 rdWmus enWpWd peeawa W agree Nab deaeWas ralge Rom desel lc 12wga feet 14. Enameled vokew to be deposed wth k6 request ter. Fa&b b be deemed: 35,OD0 bble. Types or waste may be drdlNg mud, drWi g outage, reserve pit Pulds, oamert. canlerriwbd "hig mud. cmnple ian fk0s, desel. fame0nn Wade associated wlm tue t8. Eadmated sued dab: ad ofdtklkt9 a well, dill rip wash Auks, o, m rMsega dorreate weal, water, any t-Ocp18 added water needed to fa State pumps gof drlNrtgmud or dn6g cutin0s, and omer substances that the co ninlagunerdetermines on appiksdon are wastes asaodeled with Vas adof drilling awall parmited under ZO AAC 25A05, 17.AMdananb: Well SabmaaO Cnduds MDaM 74D) O I.larbm Bad Lop ldagWrod) ❑ F7TI7.W ve OT Graph O' surf CWrg Cemedlne Gala L)' Ober 9 nrovbw WWWdmtai kir new ered,d davem Ml/e la(n1 andCD2 1B. I haatry oaMy UWI Are forpolig b ktn ail cared b the bestdu,ybwxbA7e. senak"! ' TW&. / Relied Pha,e Noma: CWp ANad manbec 28"120 Gab: Ie 2al6i Commisslun Use Orilly Ca,dbbaa of appmeat lOTnvbW and apprev t Sibeas form /O ' gz3 nerd leaked: Approval number. OMM&n ev Approved by. colifimm m ENE commmi l OWr. Fore, Was Har. W2004 bubreftimmipftle DUPLICATE