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Home My WebLink AboutCO 747CONSERVATION ORDER 747 Docket Number: CO -18-001 Pool Rules, Greater Moose's Tooth 1. February 28, 2018 ConocoPhillips Alaska, LLC application for Pool Rules for Greater Moose's Tooth (Appendix 1 and disk held in Confidential Storage) 2. March 4, 2018 Notice of hearing, affidavit of publication, email distribution, mailings 3. April 2, 2018 Email 4. April 3, 2018 Transcript, sign in sheet and presentation 5. June 7, 2018 ConocoPhillips Alaska, LLC filed request for reconsideration STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION 333 West 7th Avenue Anchorage Alaska 99501 Re: THE APPLICATION OF ConocoPhillips ) Docket Number: CO -18-001 Alaska, Inc. for an order for classification of a new ) Conservation Order No. 747 oil pool and to prescribe pool rules for development ) Greater Moose's Tooth Unit of the proposed Lookout Oil Pool within the Greater ) Greater Moose's Tooth Field Moose's Tooth Unit, Greater Moose's Tooth Field, ) Greater Moose's Tooth -Lookout Oil Lookout Oil Pool ) Pool North Slope Borough, Alaska May 29, 2018 IT APPEARING THAT: 1. By application received February 28, 2018, ConocoPhillips Alaska, hic. (CPAI), as operator of the Greater Moose's Tooth Unit (GMTU) and on behalf of the Working Interest Owners (WIOs), requested an order defining a new oil pool, the Lookout Oil Pool (LOP), within the GMTU 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 April 3, 2018. On March 4, 2018, 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. 3. No comments on the application were received. 4. The hearing commenced at 10:00 a.m. on April 3, 2018. Testimony was received from representatives of CPAI. 5. The record was closed at the end of the hearing. FINDINGS: 1. Owners and Landowners: Surface Owners of the LOP are Kuukpik Corporation and the Bureau of Land Management (BLM). Subsurface Owners of the LOP are Arctic Slope Regional Corporation and BLM. CPAI and Anadarko Petroleum Corp are the working interest owners. 2. Qperator: CPAI is operator of the leases in the proposed Affected Area, defined below. 3. Affected Area: As currently mapped, the planned Affected Area lies onshore, North Slope, Alaska, within the existing GMTU (Figure 1, below). The Affected Area for CPAI's proposed LOP lies southwest of the Colville River Unit. LOP will be the first oil development that lies entirely within the National Petroleum Reserve—Alaska (NPR -A). 4. Exploration and Delineation History: The LOP was first penetrated in 2001 by CPAI's Lookout No. 1 (Lookout -1) exploratory well in Section 36, Township 11 North, Range 2 East, Umiat Meridian (U.M.). In 2002, CPAI drilled and tested the Lookout -2 exploratory well that lies one mile to the northeast within the same pool. During a four-day test, Lookout -2 produced at a reported rate of 3,351 barrels of oil per day (BOPD), 7 million cubic feet of gas per day (MMCFD), and 158 barrels of water per day (BWPD). The oil gravity measured 40° API. ' At the time of the application, sale of Anadarko's leasehold interest to CPAI was pending government approval. CO 747 May 29, 2018 Page 2 of 10 i T11JR2E• .�.�.�ti 1 ! i I 1 i j r j 1 i LU rL - 1 ZI 1 1 j 1 1 j 1 j ............ Greater Mooser ! Tooth Unit sa i 1 LO KOUT.2 1 j za 27ON i i ! Colvil - -C UGO OU.T 1 -- - - 1 River - a Unit 33 1 I j 1 ! 11NRIE ! 1 -. MIT RE1`-(.�} \i MT6 �. M76 Well Pad Q Proposed Lookout Oil Pool Boundary le Q Lookout Reservoir - Q Proposed Lookout Participating Area ® Kuukpik surface ASRC subsurface LLQ LLI GMTV Tracts 11 tP Z a 7 k_,i Unit Boundaries I CPA[ Leases ConocoPhillips �� 1a Alaska Is 1a Proposed Lookout -- — 0 0.5 1 1.5 z Oil Pool Area 23 Miles 1/2512018 Figure 1. Proposed Affected Area In 2002, CPAI drilled the Mitre -1 exploratory well approximately 1.5 miles to the southwest of Lookout -1. Mitre -1 was not tested. CPA►'s current interpretation indicates Mitre -1 lies outside of the LOP. CO 747 May 29, 2018 Page 3 of 10 Pool Identification: As proposed, the LOP encompasses the Upper Jurassic -aged, shallow marine, Alpine C and D sandstones. These reservoir sandstones unconformably overlie Jurassic -aged Kingak Shale Formation and underlie Cretaceous -aged Miluveach Shale Formation. CPAI proposes that the LOP be defined as the accumulation of hydrocarbons common to, and correlating with, the interval in Lookout -1 from 7,833 to 8,000 feet measured depth (MD), which is equivalent to -7,763 to -7,930 feet true vertical depth subsea (TVDss). A type log is shown in Figure 2, below. The LOP is a stratigraphic oil accumulation. M -J C O O a O 0 Y O O J Lookoutl 2001 Figure 2. Proposed Lookout Oil Pool �Ia WAS 0 RON I.1 � trt, M RO �m .c Ix lH Wm' IN 1 Mr,n IW IY uf^, YI •, 106 o a A ISC NM.- IM 7833' m 77 3' ss', 7871' g 8 1 s m i s 0 8000' no 79 0' s Figure 2. Proposed Lookout Oil Pool CO 747 May 29, 2018 Page 4 of 10 6. Geology: a. Stratigraphy: CPAI's proposed LOP consists of late Jurassic -aged shelf deposits comprising sandstones within the Alpine C member and interbedded shale, sands and siltstones within the overlying Alpine D member. Within the proposed development area, the LOP ranges in gross thickness from 129 feet in the Lookout -1 well to 65 feet in the Lookout -2 well. Rock quality varies from sideritic siltstones to medium -grained, glauconitic, quartz arenites. Porosity values range from 12 to 26 percent with permeabilities ranging from 1 to 300 millidarcies. Average water saturation estimate for the reservoir siltstones and sandstones is 30 percent. b. Structure: The overall structure of the proposed pool dips to the southwest. There is one set of seismically mapped normal faults present in the proposed development area, an early Cretaceous -aged, north-northeast trending system. Vertical displacements along these faults range from 0 to 70 feet and they may act as barriers to flow. c. Trap Configuration and Seals: Well log and seismic information indicate that the proposed pool accumulation is trapped by stratigraphic elements. The Alpine C sandstone represents transgressive sands infilling paleo- topographic low areas created by incision of the regionally extensive Upper Jurassic Unconformity (UJU). Shales of the underlying Kingak Formation and overlying Miluveach Formation provide seals for the Alpine reservoir. Overlying shales of the Kalubik, HRZ and Torok formations contained within the Fish Creek Slump provide additional reservoir seals. Total thickness of the overlying confining zone varies from about 600 to over 1,200 feet. The Alpine D sandstone underlies the Miluveach Formation and overlies the Alpine C sandstone. The Alpine D is within the proposed pool interval, but it is not expected to contribute to pay and is not being relied upon to provide a seal for injection operations. d. Reservoir Compartmentalization: A long -tern interference test between Lookout -1 and Lookout -2 confirms reservoir connectivity over most of the reservoir. However, local compartmentalization may be present due to northeast -trending faults. e. Permafrost Base: The base of the permafrost is interpreted to lie between -800 and -1,200 feet TVDss within the proposed development area. Reservoir Fluid Contacts: No gas or water contacts have been encountered within the LOP. None of the exploratory or development wells drilled within the Colville River Unit to the east or within the Greater Moose's Tooth Unit have encountered an oil -water contact in the Jurassic -aged reservoir. 8. Water Salinity Calculations: In the GMTU, several wells have been logged from surface through the reservoir zone. Calculated water salinity ranges from 13,000 to 31,000 parts per million (ppm) total dissolved solids throughout the Cretaceous and older stratigraphic sequences. CO 747 May 29, 2018 Page 5 of 10 9. Reservoir Fluid Properties 0,813 feet TVDss Datum): Initial reservoir pressure Reservoir temperature Gas -oil ratio API gravity Bubble point pressure Oil formation volume factor Oil viscosity Gas formation volume factor 10. In -Place and Recoverable Oil Volumes: Hydrocarbon Resources 3,775 psig 176° F 1,385 scf/bbl 42.5° F 3,237 psig 1.77 rb/stbo 0.22 cp 0.78 bbl/mscf (at saturation pressure) Original Oil in Place (OOIP) Primary Recovery (20% OOIP) Primary+ Waterflood (45% OOIP) Primary + Waterflood + EWAG (60% OOIP) Estimated Volume (MMSTB) 70-150 14-30 31-67 42-90 11. Reservoir Development Drilling Plan: CPAI currently plans to develop this oil reservoir from GMT6 Drill Site utilizing four horizontal production and five horizontal injection wells with possible pilot holes providing additional reservoir data and assisting in horizontal well placement. One injector and one producer, located in the thickest portion of the reservoir, are planned to be dual -lateral wells. Wells will trend northwest, along the maximum principal stress direction, to improve water flood performance. Wells will be arranged end-to-end to form alternating rows of producers and injectors in a line -drive flood pattern. Well spacing will be approximately 2,200 feet. The in -zone or horizontal production intervals of the wells will range in length from 3,500 to 12,000 feet. Development drilling commenced with the spud of GMTU MT6-03 well on March 21, 2018 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. Since lengthy horizontal wells require extended shut-in periods to achieve stabilized bottom - hole pressures, CPAI proposes the following alternative pressure survey methods: i. Open -hole wireline formation fluid pressure measurements, ii. Cased hole pressure buildups with bottom -hole pressure measurement, iii. hijector surface pressure fall-off, static pressure surveys following extended shut-in periods, or CO 747 May 29, 2018 Page 6 of 10 iv. Bottom -hole pressures calculated from wellhead pressure and fluid levels in the tubing of a stabilized shut-in injector. Pressures will be referenced to a datum of -7,850 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 C40 marker in the Colville Group and cemented to the surface. Two intermediate casing strings will be run. The first will have its shoe set in the Fish Creek Slump shales and the second will be set just above or just into the Alpine C sandstone at an inclination of approximately 850. Formation integrity tests will be conducted after drilling out of the casing shoes. CPAI expects to develop the reservoir using horizontal wells with uncemented solid liners including pre -perforated pups. External swell packers may be used to isolate out of pay excursions and/or fault crossings. Both injection and production wells will likely be completed with 4-V2 inch tubing to minimize hydraulic friction. Producers will initially be gas lifted but other artificial lift mechanisms may be used as the field matures to optimize drawdown. CPAI does not intend to fracture stimulate the wells. 15. Waivers: CPAI requested the following waivers: a. Well Spacing: Spacing restrictions of 20 AAC 25.055 be waived for development wells in the proposed LOP 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 Exemption: an exemption from the GOR limits of 20 AAC 25.240 to accommodate water -alternating -gas -injection for oil recovery. 16. 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. 112 issued on October 12, 2016. CONCLUSIONS: I. Pool Rules are appropriate for CPAI's development of the proposed LOP within the GMTV. 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 ownership changes hands. 4. Water and water -alternating -gas injection into the LOP will preserve reservoir energy and increase ultimate recovery. 5. There are no freshwater aquifers in the affected area of the LOP. 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 747 May 29, 2018 Page 7 of 10 7. Filing the proposed submittals, rather than those required by 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 gas -oil ratio (GOR) limitation waiver is appropriate because the LOP 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 will be pre - produced to ensure adequate reservoir voidage to accommodate water injection. During this period there may be wells that exceed the GOR limits. NOW THEREFORE IT IS ORDERED: Development and operation of the GMTU 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 11 North, Range 2 East Sections 13-14: All Sections 23-26: All Sections 35-36: All Township 11 North, Range 3 East Sections 17-19: All Sections 29-32: All Township 10 North, Range 2 East Section 1: All Section 2: NEI/4 Township 10 North, Range 3 East Section 6: All 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 Lookout Oil Pool. Rule 2 Pool Definition The Lookout Oil Pool is defined as the accumulation of oil common to and correlating with the interval within the Lookout -1 well between the measured depths of 7,833 and 8,000 feet on the resistivity log recorded in exploratory well Lookout -1. (See Figure 2, above.) CO 747 May 29, 2018 Page 8 of 10 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 Lookout Oil Pool 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 Lookout Oil Pool 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 Lookout Oil Pool 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 production or 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 9, 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 -7,850 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 Lookout Oil Pool are exempt from the Gas -Oil Ratio 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. Rule 8 Annual Reservoir Review a. An annual reservoir surveillance report must be filed by April 151 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; CO 747 May 29, 2018 Page 9 of 10 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 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 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. 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 Lookout Oil Pool 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. CO 747 May 29, 2018 Page 10 of 10 Rule 11 Administrative Action Upon proper application, or its own motion, and unless notice and public hearing are otherwise required, the Commission my 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. DONE at Anchorage, Alaska and dated May 29, 2018. 1 1 Hollis S. French Daniel eamolmt, Jr.y. Foers Chair, Commissioner Commissioner rsston��' �ottggo 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 I0days is a denial of reconsideration. If the AOGCC denies reconsideration, upon denial, this order or decision and the denial of reconsideration are FINAL and may be appealed to superior court. The appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision denying reconsideration, UNLESS the denial is by inaction, in which case the appeal MUST be filed within 40 days after the date on which the application for reconsideration was filed. If the AOGCC grants an application for reconsideration, this order or decision does not become final. Rather, the order or decision on reconsideration will be the FINAL order or decision of the AOGCC, and it may be appealed to superior court. That appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision on reconsideration. In computing a period of time above, the date of the event or default after which the designated period begins to run is not included in the period; the last day of the period is included, unless it falls on a weekend or state holiday, in which event the period runs until 5:00 p.m. on the next day STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION 333 West 7th Avenue Anchorage Alaska 99501 Re: THE APPLICATION OF ConocoPhillips ) Docket Number: CO -18-001 Alaska, Inc. for an order for classification of a new ) Conservation Order No. 747 oil pool and to prescribe pool rules for development ) Greater Moose's Tooth Unit of the proposed Lookout Oil Pool within the Greater ) Greater Moose's Tooth Field Moose's Tooth Unit, Greater Moose's Tooth Field, ) Greater Moose's Tooth -Lookout Oil Lookout Oil Pool ) Pool North Slope Borough, Alaska May 29, 2018 IT APPEARING THAT: 1. By application received February 28, 2018, ConocoPhillips Alaska, Inc. (CPAI), as operator of the Greater Moose's Tooth Unit (GMTU) and on behalf of the Working Interest Owners (WIOs), requested an order defining a new oil pool, the Lookout Oil Pool (LOP), within the GMTU 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 April 3, 2018. On March 4, 2018, 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. 3. No comments on the application were received. 4. The hearing commenced at 10:00 a.m. on April 3, 2018. Testimony was received from representatives of CPAI. 5. The record was closed at the end of the hearing. FINDINGS: 1. Owners and Landowners: Surface Owners of the LOP are Kuukpik Corporation and the Bureau of Land Management (BLM). Subsurface Owners of the LOP are Arctic Slope Regional Corporation and BLM. CPAI and Anadarko Petroleum Corp are the working interest owners', 2. Operator: CPAI is operator of the leases in the proposed Affected Area, defined below. 3. Affected Area: As currently mapped, the planned Affected Area lies onshore, North Slope, Alaska, within the existing GMTU (Figure 1, below). The Affected Area for CPAI's proposed LOP lies southwest of the Colville River Unit. LOP will be the first oil development that lies entirely within the National Petroleum Reserve—Alaska (NPR -A). 4. Exploration and Delineation History: The LOP was first penetrated in 2001 by CPAI's Lookout No. 1 (Lookout -1) exploratory well in Section 36, Township 11 North, Range 2 East, Umiat Meridian (U.M.). In 2002, CPAI drilled and tested the Lookout -2 exploratory well that lies one mile to the northeast within the same pool. During a four-day test, Lookout -2 produced at a reported rate of 3,351 barrels of oil per day (BOPD), 7 million cubic feet of gas per day (MMCFD), and 158 barrels of water per day (BWPD). The oil gravity measured 40° API. At the time of the application, sale of Anadarko's leasehold interest to CPAI was pending government approval. CO 747 May 29, 2018 Page 2 of 10 T12 T11 1 i 1 i 1 i i 1 1 �f 1 1 1 — — 1 1 1 iF. 1 Greater Mooses Tooth Unit l 9A jj 2 I 21 1 i i 25 127 1 1 Colvil 1 -- - i River - Unit 1 Figure 1. Proposed Affected Area In 2002, CPAI drilled the Mitre -I exploratory well approximately 1.5 miles to the southwest of Lookout -I. Mitre -1 was not tested. CPAI's current interpretation indicates Mitre -1 lies outside of the LOP. \\1 i - - - - T11 NR3E 1sa � - - -- 1 MITRE 1. \ M 1 B ! MT6 Well Pad Q Proposed Lookout Oil Pool Boundary Q Lookout Reservoir Q Proposed Lookout ParsdpaangArea - ® Kuukpik SurlawASRC Subsurface W w U GMTV Trade n 12Ir 11� tUnil Boundaries 4-1 o z – –' CPAI Leawa _ N ✓ ContxoPhillips 15 .14 Alaska Proposed Lookout – ---– --.-- 0 0.5 1 1.5 2 Oil Pool Area 21, ==Miles 3 1 112512018 Figure 1. Proposed Affected Area In 2002, CPAI drilled the Mitre -I exploratory well approximately 1.5 miles to the southwest of Lookout -I. Mitre -1 was not tested. CPAI's current interpretation indicates Mitre -1 lies outside of the LOP. CO 747 May 29, 2018 Page 3 of 10 5. Pool Identification: As proposed, the LOP encompasses the Upper Jurassic -aged, shallow marine, Alpine C and D sandstones. These reservoir sandstones unconformably overlie Jurassic -aged Kingak Shale Formation and underlie Cretaceous -aged Miluveach Shale Formation. CPAI proposes that the LOP be defined as the accumulation of hydrocarbons common to, and correlating with, the interval in Lookout -1 from 7,833 to 8,000 feet measured depth (MD), which is equivalent to -7,763 to -7,930 feet true vertical depth subsea (TVDss). A type log is shown in Figure 2, below. The LOP is a stratigraphic oil accumulation. Figure 2. Proposed Lookout Oil Pool CO 747 May 29, 2018 Page 4 of 10 6. Geoloev: a. Stratigraphy: CPAI's proposed LOP consists of late Jurassic -aged shelf deposits comprising sandstones within the Alpine C member and interbedded shale, sands and siltstones within the overlying Alpine D member. Within the proposed development area, the LOP ranges in gross thickness from 129 feet in the Lookout -1 well to 65 feet in the Lookout -2 well. Rock quality varies from sideritic siltstones to medium -grained, glauconitic, quartz arenites. Porosity values range from 12 to 26 percent with permeabilities ranging from 1 to 300 millidarcies. Average water saturation estimate for the reservoir siltstones and sandstones is 30 percent. b. Structure: The overall structure of the proposed pool dips to the southwest. There is one set of seismically mapped normal faults present in the proposed development area, an early Cretaceous -aged, north-northeast trending system. Vertical displacements along these faults range from 0 to 70 feet and they may act as barriers to flow. c. Trap Configuration and Seals: Well log and seismic information indicate that the proposed pool accumulation is trapped by stratigraphic elements. The Alpine C sandstone represents transgressive sands infilling paleo- topographic low 'areas created by incision of the regionally extensive Upper Jurassic Unconformity (UJU). Shales of the underlying Kingak Formation and overlying Miluveach Formation provide seals for the Alpine reservoir. Overlying shales of the Kalubik, HRZ and Torok formations contained within the Fish Creek Slump provide additional reservoir seals. Total thickness of the overlying confining zone varies from about 600 to over 1,200 feet. The Alpine D sandstone underlies the Miluveach Formation and overlies the Alpine C sandstone. The Alpine D is within the proposed pool interval, but it is not expected to contribute to pay and is not being relied upon to provide a seal for injection operations. d. Reservoir Compartmentalization: A long-term interference test between Lookout -1 and Lookout -2 confirms reservoir connectivity over most of the reservoir. However, local compartmentalization may be present due to northeast -trending faults. e. Permafrost Base: The base of the permafrost is interpreted to lie between -800 and -1,200 feet TVDss within the proposed development area. Reservoir Fluid Contacts: No gas or water contacts have been encountered within the LOP. None of the exploratory or development wells drilled within the Colville River Unit to the east or within the Greater Moose's Tooth Unit have encountered an oil -water contact in the Jurassic -aged reservoir. 8. Water Salinity Calculations: In the GMTU, several wells have been logged from surface through the reservoir zone. Calculated water salinity ranges from 13,000 to 31,000 parts per million (ppm) total dissolved solids throughout the Cretaceous and older stratigraphic sequences. CO 747 May 29, 2018 Page 5 of 10 9. Reservoir Fluid Properties (-7,813 feet TVDss Datum): Initial reservoir pressure Reservoir temperature Gas -oil ratio API gravity Bubble point pressure Oil formation volume factor Oil viscosity Gas formation volume factor 10. hi -Place and Recoverable Oil Volumes: Hydrocarbon Resources 3,775 psig 176° F 1,385 scf/bbl 42.5° F 3,237 psig 1.77 rb/stbo 0.22 cp 0.78 bbl/mscf (at saturation pressure) Original Oil in Place (OOIP) Primary Recovery (20% OOIP) Primary + W aterflood (45% OOIP) Primary + Waterflood + EWAG (60% OOIP) Estimated Volume (MMSTB) 70-150 14-30 31-67 42-90 11. Reservoir Development Drilling Plan: CPAI currently plans to develop this oil reservoir from GMT6 Drill Site utilizing four horizontal production and five horizontal injection wells with possible pilot holes providing additional reservoir data and assisting in horizontal well placement. One injector and one producer, located in the thickest portion of the reservoir, are planned to be dual -lateral wells. Wells will trend northwest, along the maximum principal stress direction, to improve water flood performance. Wells will be arranged end-to-end to form alternating rows of producers and injectors in a line -drive flood pattern. Well spacing will be approximately 2,200 feet. The in -zone or horizontal production intervals of the wells will range in length from 3,500 to 12,000 feet. Development drilling commenced with the spud of GMTU MT6-03 well on March 21, 2018 12, Reservoir Management: CPAI plans to develop the reservoir as a water- and water-altemating- 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. Since lengthy horizontal wells require extended shut-in periods to achieve stabilized bottom - hole pressures, CPAI proposes the following alternative pressure survey methods: i. Open -hole wireline formation fluid pressure measurements, ii. Cased hole pressure buildups with bottom -hole pressure measurement, iii. Injector surface pressure fall-off, static pressure surveys following extended shut-in periods, or CO 747 May 29, 2018 Page 6 of 10 iv. Bottom -hole pressures calculated from wellhead pressure and fluid levels in the tubing of a stabilized shut-in injector. Pressures will be referenced to a datum of -7,850 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 beset below the C40 marker in the Colville Group and cemented to the surface. Two intermediate casing strings will be run. The first will have its shoe set in the Fish Creek Slump shales and the second will be set just above or just into the Alpine C sandstone at an inclination of approximately 85°. Formation integrity tests will be conducted after drilling out of the casing shoes. CPAI expects to develop the reservoir using horizontal wells with uncemented solid liners including pre -perforated pups. External swell packers may be used to isolate out of pay excursions and/or fault crossings. Both injection and production wells will likely be completed with 4-1/2 inch tubing to minimize hydraulic friction. Producers will initially be gas lifted but other artificial lift mechanisms may be used as the field matures to optimize drawdown. CPAI does not intend to fracture stimulate the wells. 15. Waivers: CPAI requested the following waivers: a. Well Spacing: Spacing restrictions of 20 AAC 25.055 be waived for development wells in the proposed LOP 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 Exemption: an exemption from the GOR limits of 20 AAC 25.240 to accommodate water -alternating -gas -injection for oil recovery. 16. Meterma 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. 112 issued on October 12, 2016. CONCLUSIONS: 1. Pool Rules are appropriate for CPAI's development of the proposed LOP within the GMTU. 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 ownership changes hands. 4. Water and water -alternating -gas injection into the LOP will preserve reservoir energy and increase ultimate recovery. 5. There are no freshwater aquifers in the affected area of the LOP. 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 747 May 29, 2018 Page 7 of 10 7. Filing the proposed submittals, rather than those required by 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 gas -oil ratio (GOR) limitation waiver is appropriate because the LOP 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 will be pre - produced to ensure adequate reservoir voidage to accommodate water injection. During this period there may be wells that exceed the GOR limits. NOW THEREFORE IT IS ORDERED: Development and operation of the GMTU 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 11 North, Range 2 East Sections 13-14: All Sections 23-26: All Sections 35-36: All Township 11 North, Range 3 East Sections 17-19: All Sections 29-32: All Township 10 North, Range 2 East Section 1: All Section 2: NEIA Township 10 North, Range 3 East Section 6: All 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 Lookout Oil Pool. Rule 2 Pool Definition The Lookout Oil Pool is defined as the accumulation of oil common to and correlating with the interval within the Lookout -1 well between the measured depths of 7,833 and 8,000 feet on the resistivity log recorded in exploratory well Lookout -1. (See Figure 2, above.) CO 747 May 29, 2018 Page 8 of 10 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 Lookout Oil Pool 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 Reauirements 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 Lookout Oil Pool 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 Lookout Oil Pool 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 production or 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 9, 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 -7,850 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 Lookout Oil Pool are exempt from the Gas -Oil Ratio 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. 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: 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; CO 747 May 29, 2018 Page 9 of 10 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 Casin¢ 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 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. 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 Comminaline. Measurement and Allocation a. Production from Lookout Oil Pool maybe commingled on the surface with production from other pools within the GMTU and the CRU. b. Wells must be tested at least monthly. CO 747 May 29, 2018 Page 10 of 10 Rule 11 Administrative Action Upon proper application, or its own motion, and unless notice and public hearing are otherwise required, the Commission my 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. DONE at Anchorage, Alaska and dated May 29, 2018. //signature on file// //signature on file// //signature on file// Hollis S. French Daniel T. Seamount, Jr. Cathy P. Foerster Chair, Commissioner Commissioner Commissioner 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 most 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 areFINAL and may be appealed to superior court. The appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision denying reconsideration, UNLESS the denial is by inaction, in which case the appeal MUST be filed within 40 days after the date on which the application for reconsideration was filed. If the AOGCC grants an application for reconsideration, this order or decision does not become final. Rather, the order or decision on reconsideration will be the FINAL order or decision of the AOGCC, and it may be appealed to superior court. That appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision on reconsideration. In computing a period of time above, the date of the event or default after which the designated period begins to run is not included in the period; the last day of the period is included, unless it falls on a weekend or state holiday, in which event the period runs until 5:00 pm. on the next day Colombie, Jody J (DOA) From: Colombie, Jody J (DOA) Sent: Tuesday, May 29, 2018 2:42 PM To: Bixby, Brian D (DOA); Brooks, Phoebe L (DOA); Carlisle, Samantha J (DOA); Colombie, Jody 1 (DOA); Cook, Guy D (DOA); Davies, Stephen F (DOA); Earl, Adam G (DOA); Erickson, Tamara K (DOA); Foerster, Catherine P (DOA); French, Hollis (DOA); Frystacky, Michal (DOA); Guhl, Meredith D (DOA); Herrera, Matthew F (DOA); Jones, Jeffery B (DOA); Kair, Michael N (DOA); Laubenstein, Lou (DOA); Loepp, Victoria T (DOA); Martin, Teddy J (DOA); McLeod, Austin (DOA); McPhee, Megan S (DOA); Mumm, Joseph (DOA sponsored); Noble, Robert C (DOA); Paladijczuk, Tracie L (DOA); Pasqua[, Maria (DOA); Regg, James B (DOA); Rixse, Melvin G (DOA); Roby, David S (DOA); Schwartz, Guy L (DOA); Seamount, Dan T (DOA); Wallace, Chris D (DOA); AK, GWO Projects Well Integrity, AKDCWeIIIntegrityCoordinator, Alan Bailey; Alex Demarban; Alicia Showalter; Allen Huckabay; Andrew VanderJack; Ann Danielson; Anna Lewallen; Anna Raff; Barbara F Fullmer, bbritch; bbohrer@ap.org; Ben Boettger; Bill Bredar; Bob Shavelson; Bonnie Bailey; Brandon Viator; Brian Havelock, Bruce Webb; Caleb Conrad; Candi English; Cody Gauer; Cody Terrell; Colleen Miller, Connie Downing; Crandall, Krissell; D Lawrence; Dale Hoffman; Danielle Mercurio; Darci Horner, Dave Harbour; David Boelens; David Duffy, David House; David McCaleb; David Pascal; ddonkel@cfl.rr.com; Diemer, Kenneth J (DNR); DNROG Units (DNR sponsored); Donna Ambruz; Ed Jones; Elizabeth Harball; Elowe, Kristin; Elwood Brehmer; Evan Osborne; Evans, John R (LDZX); Brown, Garrett A (DNR); George Pollock, Gordon Pospisil; Greeley, Destin M (DOR); Gretchen Stoddard; gspfoff; Hurst, Rona D (DNR); Hyun, James J (DNR); Jacki Rose; Jason Brune; Jdarlington Qarlington@gmail.com); Jeanne McPherren; Jerry Hodgden; Jill Simek; Jim Shine; Jim Watt; Jim White Oim4thgn@gmail.com); Young, Jim P (DNR); Joe Lastufka; Radio Kenai; Burdick, John D (DNR); Easton, John R (DNR); Larsen, John M (DOR); Jon Goltz; Chmielowski, Josef (DNR); Joshua Stephen; Juanita Lovett; Judy Stanek, Kari Moriarty; Kasper Kowalewski; Kazeem Adegbola; Keith Torrance; Keith Wiles; Kelly Sperback; Frank, Kevin J (DNR); Kruse, Rebecca D (DNR); Kyla Choquette; Gregersen, Laura S (DNR); Leslie Smith; Lori Nelson; Luke Keller; Marc Kovak; Dalton, Mark (DOT sponsored); Mark Hanley (mark.hanley@anadarko.com); Mark Landt; Mark Wedman; Michael Bill; Michael Calkins; Michael Moora; Michael Quick; Michael Schoetz; Mike Morgan; M1 Loveland; Motteram, Luke A; Mueller, Marta R (DNR); Nathaniel Herz; knelson@petroleumnews.com; Nichole Saunders; Nick Ostrovsky; NSK Problem Well Supv, Patty Alfaro; Paul Craig; Decker, Paul L (DNR); Paul Mazzolini; Pike, Kevin W (DNR); Randall Kanady; Renan Yanish; Richard Cool; Robert Brelsford; Robert Tirpack; Robert Warthen; Ryan Gross; Sara Leverette; Scott Griffith; Shahla Farzan; Shannon Donnelly; Sharon Yarawsky; Skutca, Joseph E (DNR); Smith, Kyle S (DNR); Stephanie Klemmer; Stephen Hennigan; Stephen Ratcliff; Sternicki, Oliver R; Moothart, Steve R (DNR); Steve Quinn; Suzanne Gibson; Sheffield@aoga.org; Tanisha Gleason; Ted Kramer; Teresa Imm; Tim Mayers; Todd Durkee; Tom Maloney; Tyler Senden; Umekwe, Maduabuchi P (DNR); Vern Johnson; Vinnie Catalano; Well Integrity; Well Integrity; Weston Nash; Whitney Pettus; Aaron Gluzman; Aaron Sorrell; Ajibola Adeyeye; Alan Dennis; Andy Bond; Bajsarowicz, Caroline J; Bruce Williams; Casey Sullivan; Corey Munk; Don Shaw, Eppie Hogan; Eric Lidji; Garrett Haag; Smith, Graham O (DNR); Heusser, Heather A (DNR); Fair, Holly S (DNR); Jamie M. Long; Jason Bergerson; Jesse Chielowski; Jim Magill; Joe Longo; John Martineck; Josh Kindred; Keith Lopez; Laney Vazquez, Lois Epstein; Longan, Sara W (DNR); Marc Kuck; Marcia Hobson; Matt Armstrong; Melonnie Amundson; Franger, James M (DNR); Morgan, Kirk A (DNR); Umekwe, Maduabuchi P (DNR); Pat Galvin; Patricia Bettis; Pete Dickinson; Peter Contreras; Rachel Davis; Richard Garrard; Richmond, Diane M; Robert Province; Ryan Daniel; Sandra Lemke; Pollard, Susan R (LAW); Talib Syed; Tina Grovier (tmgrovier@stoel.com); William Van Dyke Subject: CO 747 - CPA - Greater Moose's Tooth Unit Attachments: co747.pdf Please see attached. Re: THE APPLICATION OF ConocoPhillips Alaska, ) Docket Number: CO -18-001 Inc. for an order for classification of a new oil pool ) Conservation Order No. 747 and to prescribe pool rules for development of the ) Greater Moose's Tooth Unit proposed Lookout Oil Pool within the Greater ) Greater Moose's Tooth Field Moose's Tooth Unit, Greater Moose's Tooth Field, ) Greater Moose's Tooth -Lookout Oil Lookout Oil Pool ) Pool North Slope Borough, Alaska May 29, 2018 Jody J. Co(ombie AOGCC Specia(Assistant Alaska Oi(and Gas Conservation Commission 333 West 7" Avenue Anchorage, Alaska 99501 Office: (907) 793-1221 Fax. (907) 276-7542 CONFIDENT/AMY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission )AOGCC), State of Alaska and is for the sole use of the intended recipientls). If may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending if to you, contact Jody Colombie at 907.793.1221 or iodv.colombie®alaska.gov. Bernie Karl Gordon Severson Penny Vadla K&K Recycling Inc. 3201 Westmar Cir. 399 W. Riverview Ave. P.O. Box 58055 Anchorage, AK 99508-4336 Soldotna, AK 99669-7714 Fairbanks, AK 99711 George Vaught, Jr. Darwin Waldsmith Richard Wagner P.O. Box 13557 P.O. Box 39309 P.O. Box 60868 Denver, CO 80201-3557 Ninilchik, AK 99639 Fairbanks, AK 99706 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION 333 West 7th Avenue Anchorage Alaska 99501 Re: THE APPLICATION OF ConocoPhillips ) Docket Number: CO -18-001 Alaska, hic. for an order for classification of a new ) Conservation Order No. 747 Corrected oil pool and to prescribe pool rules for development ) Greater Moose's Tooth Unit of the proposed Lookout Oil Pool within the Greater ) Greater Moose's Tooth Field Moose's Tooth Unit, Greater Moose's Tooth Field, ) Greater Moose's Tooth -Lookout Oil Lookout Oil Pool ) Pool North Slope Borough, Alaska May 29, 2018 Corrected July 24, 2018 IT APPEARING THAT: 1. By application received February 28, 2018, ConocoPhillips Alaska, Inc. (CPAI), as operator of the Greater Moose's Tooth Unit (GMTU) and on behalf of the Working Interest Owners (WIOs), requested an order defining a new oil pool, the Lookout Oil Pool (LOP), within the GMTU 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 April 3, 2018. On March 4, 2018, 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. 3. No comments on the application were received. 4. The hearing commenced at 10:00 a.m. on April 3, 2018. Testimony was received from representatives of CPAI. 5. The record was closed at the end of the hearing. FINDINGS: I . Owners and Landowners: Surface Owners of the LOP are Kuukpik Corporation and the Bureau of Land Management (BLM). Subsurface Owners of the LOP are Arctic Slope Regional Corporation and BLM. CPAI and Anadarko Petroleum Corp are the working interest owners'. 2. Oneratoi: CPAI is operator of the leases in the proposed Affected Area, defined below. 3. Affected Area: As currently mapped, the planned Affected Area lies onshore, North Slope, Alaska, within the existing GMTU (Figure 1, below). The Affected Area for CPAI's proposed LOP lies southwest of the Colville River Unit. LOP will be the fust oil development that lies entirely within the National Petroleum Reserve—Alaska (NPR -A). 4. Exploration and Delineation History: The LOP was first penetrated in 2001 by CPAI's Lookout No. 1 (Lookout -1) exploratory well in Section 36, Township 11 North, Range 2 East, Umiat Meridian (U.M.). In 2002, CPAI drilled and tested the Lookout -2 exploratory well that lies one mile to the northeast within the same pool. During a four-day test, Lookout -2 produced at a reported rate of 3,351 barrels of oil per day (BOPD), 7 million cubic feet of gas per day (MMCFD), and 158 barrels of water per day (BWPD). The oil gravity measured 40° API. ' At the time of the application, sale of Anadarko's leasehold interest to CPAI was pending government approval CO 747 July 24, 2018 Page 2 of 10 i i i ... _._. .i - Greater j Mooses Tooth Unit l sa; Figure 1. Proposed Affected Area In 2002, CPAI drilled the Mitre -1 exploratory well approximately 1.5 miles to the southwest of Lookout -1. Mitre -1 was not tested. CPAI's current interpretation indicates Mitre -1 lies outside of the LOP. River Unit -JiiiiiiiiL" q. GMTU Tracts Unit Boundaries 'I 1 017 F CPAI Leases ConocoPhillips Alaska Proposed Lookout Oil Pool Area Figure 1. Proposed Affected Area In 2002, CPAI drilled the Mitre -1 exploratory well approximately 1.5 miles to the southwest of Lookout -1. Mitre -1 was not tested. CPAI's current interpretation indicates Mitre -1 lies outside of the LOP. CO 747 July 24, 2018 Page 3 of 10 5. Pool Identification: As proposed, the LOP encompasses the Upper Jurassic -aged, shallow marine, Alpine C and D sandstones. These reservoir sandstones unconformably overlie Jurassic -aged Kingak Shale Formation and underlie Cretaceous -aged Miluveach Shale Formation. CPAI proposes that the LOP be defined as the accumulation of hydrocarbons common to, and correlating with, the interval in Lookout -1 from 7,833 to 8,000 feet measured depth (MD), which is equivalent to -7,763 to -7,930 feet true vertical depth subsea (TVDss). A type log is shown in Figure 2, below. The LOP is a stratigraphic oil accumulation. L -J 0 0 a O 0 0 0 J Lookoutl INT" np [R) ISI i......., c., I'M 1:20] ay. I50 833' m s 2001 I Figure 2. Proposed Lookout Oil Pool CO 747 July 24, 2018 Page 4 of 10 6. Geology: a. Stratigraphy: CPAI's proposed LOP consists of late Jurassic -aged shelf deposits comprising sandstones within the Alpine C member and interbedded shale, sands and siltstones within the overlying Alpine D member. Within the proposed development area, the LOP ranges in gross thickness from 129 feet in the Lookout -1 well to 65 feet in the Lookout -2 well. Rock quality varies from sideritic siltstones to medium -grained, glauconitic, quartz arenites. Porosity values range from 12 to 26 percent with permeabilities ranging from 1 to 300 millidarcies. Average water saturation estimate for the reservoir siltstones and sandstones is 30 percent. b. Structure: The overall structure of the proposed pool dips to the southwest. There is one set of seismically mapped normal faults present in the proposed development area, an early Cretaceous -aged, north-northeast trending system. Vertical displacements along these faults range from 0 to 70 feet and they may act as barriers to flow. c. Trap Configuration and Seals: Well log and seismic information indicate that the proposed pool accumulation is trapped by stratigraphic elements. The Alpine C sandstone represents transgressive sands infilling paleo- topographic low areas created by incision of the regionally extensive Upper Jurassic Unconformity (UJU). Shales of the underlying Kingak Formation and overlying Miluveach Formation provide seals for the Alpine reservoir. Overlying shales of the Kalubik, HRZ and Torok formations contained within the Fish Creek Slump provide additional reservoir seals. Total thickness of the overlying confining zone varies from about 600 to over 1,200 feet. The Alpine D sandstone underlies the Miluveach Formation and overlies the Alpine C sandstone. The Alpine D is within the proposed pool interval, but it is not expected to contribute to pay and is not being relied upon to provide a seal for injection operations. d. Reservoir Compartmentalization: A long-term interference test between Lookout -1 and Lookout -2 confirms reservoir connectivity over most of the reservoir. However, local compartmentalization may be present due to northeast -trending faults. e. Permafrost Base: The base of the permafrost is interpreted to lie between -800 and -1,200 feet TVDss within the proposed development area. Reservoir Fluid Contacts: No gas or water contacts have been encountered within the LOP. None of the exploratory or development wells drilled within the Colville River Unit to the east or within the Greater Moose's Tooth Unit have encountered an oil -water contact in the Jurassic -aged reservoir. 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 (ppm) total dissolved solids throughout the Cretaceous and older stratigraphic sequences. CO 747 July 24, 2018 Page 5 of 10 9. Reservoir Fluid Properties 0,813 feet TVDss Datum): Initial reservoir pressure Reservoir temperature Gas -oil ratio API gravity Bubble point pressure Oil formation volume factor Oil viscosity Gas formation volume factor 10. In -Place and Recoverable Oil Volumes: Hydrocarbon Resources 3,775 psig 176° F 1,385 scf/bbl 42.5° F 3,237 psig 1.77 rb/stbo 0.22 cp 0.78 bbl/mscf (at saturation pressure) Original Oil in Place (OOIP) Primary Recovery (20% OOIP) Primary+ Waterflood (45% OOIP) Primary + Waterflood + EWAG (60% OOIP) Estimated Volume (MMSTB) 70-150 14-30 31-67 42-90 it. Reservoir Development Drilling Plan: CPAI currently plans to develop this oil reservoir from GMT6 Drill Site utilizing four horizontal production and five horizontal injection wells with possible pilot holes providing additional reservoir data and assisting in horizontal well placement. One injector and one producer, located in the thickest portion of the reservoir, are planned to be dual -lateral wells. Wells will trend northwest, along the maximum principal stress direction, to improve water flood performance. Wells will be arranged end-to-end to form alternating rows of producers and injectors in a line -drive flood pattern. Well spacing will be approximately 2,200 feet. The in -zone or horizontal production intervals of the wells will range in length from 3,500 to 12,000 feet. Development drilling commenced with the spud of GMTU MT6-03 well on March 21, 2018 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. Since lengthy horizontal wells require extended shut-in periods to achieve stabilized bottom - hole pressures, CPAI proposes the following alternative pressure survey methods: i. Open -hole wireline formation fluid pressure measurements, ii. Cased hole pressure buildups with bottom -hole pressure measurement, iii. Injector surface pressure fall-off, static pressure surveys following extended shut-in periods, or CO 747 July 24, 2018 Page 6 of 10 iv. Bottom -hole pressures calculated from wellhead pressure and fluid levels in the tubing of a stabilized shut-in injector. Pressures will be referenced to a datum of -7,850 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 C40 marker in the Colville Group and cemented to the surface. Two intermediate casing strings will be run. The first will have its shoe set in the Fish Creek Slump shales and the second will be set just above or just into the Alpine C sandstone at an inclination of approximately 85°. Formation integrity tests will be conducted after drilling out of the casing shoes. CPAI expects to develop the reservoir using horizontal wells with uncemented solid liners including pre -perforated pups. External swell packers may be used to isolate out of pay excursions and/or fault crossings. Both injection and production wells will likely be completed with 4-V2 inch tubing to minimize hydraulic friction. Producers will initially be gas lifted but other artificial lift mechanisms may be used as the field matures to optimize drawdown. CPAI does not intend to fracture stimulate the wells. 15. Waivers: CPAI requested the following waivers: a. Well Spacing: Spacing restrictions of 20 AAC 25.055 be waived for development wells in the proposed LOP 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 Exemption: an exemption from the GOR limits of 20 AAC 25.240 to accommodate water -alternating -gas -injection for oil recovery. 16. 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. 112 issued on October 12, 2016. CONCLUSIONS: 1. Pool Rules are appropriate for CPAI's development of the proposed LOP within the GMTV. 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 ownership changes hands. 4. Water and water -alternating -gas injection into the LOP will preserve reservoir energy and increase ultimate recovery. There are no freshwater aquifers in the affected area of the LOP. 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 747 July 24, 2018 Page 7 of 10 7. Filing the proposed submittals, rather than those required by 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 gas -oil ratio (GOR) limitation waiver is appropriate because the LOP 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. NOW THEREFORE IT IS ORDERED: Development and operation of the GMTU 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 11 North, Range 2 East Sections 13-14: All Sections 23-26: All Sections 35-36: All Township I 1 North, Range 3 East Sections 17-19: All Sections 29-32: All Township 10 North, Range 2 East Section 1: All Section 2: NEI/4 Township 10 North, Range 3 East Section 6: All 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 Lookout Oil Pool. Rule 2 Pool Definition The Lookout Oil Pool is defined as the accumulation of oil common to and correlating with the interval within the Lookout -1 well between the measured depths of 7,833 and 8,000 feet on the resistivity log recorded in exploratory well Lookout -1. (See Figure 2, above.) CO 747 July 24, 2018 Page 8 of 10 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 Lookout Oil Pool 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 Lookout Oil Pool 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 Lookout Oil Pool 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 production or 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 -7,850 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 Lookout Oil Pool are exempt from the Gas -Oil Ratio 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. Rule S Annual Reservoir Review a. An annual reservoir surveillance report must be filed by April I" 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; CO 747 July 24, 2018 Page 9 of 10 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; 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 Casin¢ 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 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 prig, and (2) that the outer annulus pressure at operating temperature will be below 1,000 psig. 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 Commin2lin2, Measurement and Allocation a. Production from Lookout Oil Pool 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. CO 747 July 24, 2018 Page 10 of 10 Rule 11 Administrative Action Upon proper application, or its own motion, and unless notice and public hearing are otherwise required, the Commission my 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. DON Anchorage, and d ed July 24, 2018 nunc pro tunc May 29, 2018. CL2 Hollis S. French Daniel T. Segiiount, Jr. Cathy Chair, Commissioner Commissioner Commis 1ING 1110 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 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 Lookout Oil Pool within the Greater Moose's Tooth Unit, Greater Moose's Tooth Field, Lookout Oil Pool IT APPEARING THAT: Docket Number: CO -18-001 Conservation Order No. 747 Corrected Greater Moose's Tooth Unit Greater Moose's Tooth Field Greater Moose's Tooth -Lookout Oil Pool North Slope Borough, Alaska May 29, 2018 Corrected July 24, 2018 1. By application received February 28, 2018, ConocoPhillips Alaska, hic. (CPAI), as operator of the Greater Moose's Tooth Unit (GMTU) and on behalf of the Working Interest Owners (WIOs), requested an order defining a new oil pool, the Lookout Oil Pool (LOP), within the GMTU 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 April 3, 2018. On March 4, 2018, 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. 3. No comments on the application were received. 4. The hearing commenced at 10:00 a.m. on April 3, 2018. Testimony was received from representatives of CPAI. 5. The record was closed at the end of the hearing. FINDINGS: 1. Owners and Landowners: Surface Owners of the LOP are Kuukpik Corporation and the Bureau of Land Management (BLM). Subsurface Owners of the LOP are Arctic Slope Regional Corporation and BLM. CPAI and Anadarko Petroleum Corp are the working interest owners'. 2. Operator: CPAI is operator of the leases in the proposed Affected Area, defined below. 3. Affected Area: As currently mapped, the planned Affected Area lies onshore, North Slope, Alaska, within the existing GMTU (Figure 1, below). The Affected Area for CPAI's proposed LOP lies southwest of the Colville River Unit. LOP will be the first oil development that lies entirely within the National Petroleum Reserve—Alaska (NPR -A). 4. Exploration and Delineation History: The LOP was first penetrated in 2001 by CPAI's Lookout No. 1 (Lookout -1) exploratory well in Section 36, Township I1 North, Range 2 East, Umiat Meridian (U.M.). In 2002, CPAI drilled and tested the Lookout -2 exploratory well that lies one mile to the northeast within the same pool. During a four-day test, Lookout -2 produced at a reported rate of 3,351 barrels of oil per day (BOPD), 7 million cubic feet of gas per day (MMCFD), and 158 barrels of water per day (BWPD). The oil gravity measured 40° API. ' At the time of the application, sale of Anadarko's leasehold interest to CPAI was pending government approval. CO 747 July 24, 2018 Page 2 of 10 Figure 1. Proposed Affected Area In 2002, CPAI drilled the Mitre -1 exploratory well approximately 1.5 miles to the southwest of Lookout -1. Mitre -1 was not tested. CPAI's current interpretation indicates Mitre -1 lies outside of the LOP. T12l RH .�.�.�ti i Tll R2E� i i i W i 1 Z. 2 1 _. ... 1 i 1 i5 1 j le 1 1 1 i Greater 1 Mouses L2 1 Tooth Unit 'sa; i i i LOOK01/T.2� ----1- 2e y 1 1 28 2i 1 1 Colvil i K Ti — — - --- i—River- iver6Ok 6 Ok Unit i 53 i 3: 1 sd T11NR3E —1 - M p MT6 fp MTBWell Pad a Q Proposed Lookout Oil Pool Boundary Q Lookout Reservoir =Proposed Lookout PadiclpaengArea ® Kuukpik Surf s ASRC Subsurbw a W W GMTU TMCts 11 12 af Er ) _O �' Unit Boundaries i../ .-1 0 0 I CPAI Leases N ConoCoPllllips 15 14 13Alaska 18 Proposed Lookout 0 0.5 1 1.5 2 Oil Pool Area 23 Miles 7 112512018 Figure 1. Proposed Affected Area In 2002, CPAI drilled the Mitre -1 exploratory well approximately 1.5 miles to the southwest of Lookout -1. Mitre -1 was not tested. CPAI's current interpretation indicates Mitre -1 lies outside of the LOP. CO 747 July 24, 2018 Page 3 of 10 5. Pool Identification: As proposed, the LOP encompasses the Upper Jurassic -aged, shallow marine, Alpine C and D sandstones. These reservoir sandstones unconformably overlie Jurassic -aged Kingak Shale Formation and underlie Cretaceous -aged Miluveach Shale Formation. CPAI proposes that the LOP be defined as the accumulation of hydrocarbons common to, and correlating with, the interval in Lookout -I from 7,833 to 8,000 feet measured depth (MD), which is equivalent to -7,763 to -7,930 feet true vertical depth subsea (TVDss). A type log is shown in Figure 2, below. The LOP is a stratigraphic oil accumulation. Figure 2. Proposed Lookout Oil Pool CO 747 July 24, 2018 Page 4 of 10 6. Geology: a. Stratigraphy: CPAI's proposed LOP consists of late Jurassic -aged shelf deposits comprising sandstones within the Alpine C member and interbedded shale, sands and siltstones within the overlying Alpine D member. Within the proposed development area, the LOP ranges in gross thickness from 129 feet in the Lookout -1 well to 65 feet in the Lookout -2 well. Rock quality varies from sideritic siltstones to medium -grained, glauconitic, quartz arenites. Porosity values range from 12 to 26 percent with permeabilities ranging from 1 to 300 millidarcies. Average water saturation estimate for the reservoir siltstones and sandstones is 30 percent. b. Structure: The overall structure of the proposed pool dips to the southwest. There is one set of seismically mapped normal faults present in the proposed development area, an early Cretaceous -aged, north-northeast trending system. Vertical displacements along these faults range from 0 to 70 feet and they may act as barriers to flow. c. Trap Configuration and Seals: Well log and seismic information indicate that the proposed pool accumulation is trapped by stratigraphic elements. The Alpine C sandstone represents transgressive sands infilling paleo- topographic low areas created by incision of the regionally extensive Upper Jurassic Unconformity (UJU). Shales of the underlying Kingak Formation and overlying Miluveach Formation provide seals for the Alpine reservoir. Overlying shales of the Kalubik, HRZ and Torok formations contained within the Fish Creek Slump provide additional reservoir seals. Total thickness of the overlying confining zone varies from about 600 to over 1,200 feet. The Alpine D sandstone underlies the Miluveach Formation and overlies the Alpine C sandstone. The Alpine D is within the proposed pool interval, but it is not expected to contribute to pay and is not being relied upon to provide a seal for injection operations. d. Reservoir Compartmentalization: A long-term interference test between Lookout -1 and Lookout -2 confirms reservoir connectivity over most of the reservoir. However, local compartmentalization may be present due to northeast -trending faults. e. Permafrost Base: The base of the permafrost is interpreted to lie between -800 and -1,200 feet TVDss within the proposed development area. Reservoir Fluid Contacts: No gas or water contacts have been encountered within the LOP. None of the exploratory or development wells drilled within the Colville River Unit to the east or within the Greater Moose's Tooth Unit have encountered an oil -water contact in the Jurassic -aged reservoir. 8. Water Salinity Calculations: In the GMTU, several wells have been logged from surface through the reservoir zone. Calculated water salinity ranges from 13,000 to 31,000 parts per million (ppm) total dissolved solids throughout the Cretaceous and older stratigraphic sequences. CO 747 July 24, 2018 Page 5 of 10 9. Reservoir Fluid Properties (-7,813 feet TVDss Datum): Initial reservoir pressure Reservoir temperature Gas -oil ratio API gravity Bubble point pressure Oil formation volume factor Oil viscosity Gas formation volume factor 10. In -Place and Recoverable Oil Volumes: Hydrocarbon Resources 3,775 psig 176° F 1,385 scf/bbl 42.50F 3,237 prig 1.77 rb/stbo 0.22 cp 0.78 bbl/mscf (at saturation pressure) Original Oil in Place (OOIP) Primary Recovery (20% OOIP) Primary+ Waterflood (45% OOIP) Primary + W aterflood + EWAG (60% OOIP) Estimated Volume (MMSTB) 70-150 14-30 31-67 42-90 11. Reservoir Development Drilling Plan: CPAI currently plans to develop this oil reservoir from GMT6 Drill Site utilizing four horizontal production and five horizontal injection wells with possible pilot holes providing additional reservoir data and assisting in horizontal well placement. One injector and one producer, located in the thickest portion of the reservoir, are planned to be dual -lateral wells. Wells will trend northwest, along the maximum principal stress direction, to improve water flood performance. Wells will be arranged end-to-end to form alternating rows of producers and injectors in a line -drive flood pattern. Well spacing will be approximately 2,200 feet. The in -zone or horizontal production intervals of the wells will range in length from 3,500 to 12,000 feet. Development drilling commenced with the spud of GMTU MT6-03 well on March 21, 2018. 12. Reservoir Management: CPAI plans to develop the reservoir as a water- and water-altemating- 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. Since lengthy horizontal wells require extended shut-in periods to achieve stabilized bottom - hole pressures, CPAI proposes the following alternative pressure survey methods: i. Open -hole wireline formation fluid pressure measurements, ii. Cased hole pressure buildups with bottom -hole pressure measurement, iii. Injector surface pressure fall-off, static pressure surveys following extended shut-in periods, or CO 747 July 24, 2018 Page 6 of 10 iv. Bottom -hole pressures calculated from wellhead pressure and fluid levels in the tubing of a stabilized shut-in injector. Pressures will be referenced to a datum of -7,850 feet TV Dss. 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 C40 marker in the Colville Group and cemented to the surface. Two intermediate casing strings will be run. The first will have its shoe set in the Fish Creek Slump shales and the second will be set just above or just into the Alpine C sandstone at an inclination of approximately 85°. Formation integrity tests will be conducted after drilling out of the casing shoes. CPAI expects to develop the reservoir using horizontal wells with uncemented solid liners including pre -perforated pups. External swell packers may be used to isolate out of pay excursions and/or fault crossings. Both injection and production wells will likely be completed with 4-'/ inch tubing to minimize hydraulic friction. Producers will initially be gas lifted but other artificial lift mechanisms may be used as the field matures to optimize drawdown. CPAI does not intend to fracture stimulate the wells. 15. Waivers: CPAI requested the following waivers: a. Well Spacing: Spacing restrictions of 20 AAC 25.055 be waived for development wells in the proposed LOP 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 Exemption: an exemption from the GOR limits of 20 AAC 25.240 to accommodate water-altemating-gas-injection for oil recovery. 16. 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. 112 issued on October 12, 2016. CONCLUSIONS: 1. Pool Rules are appropriate for CPAI's development of the proposed LOP within the GMTU. 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 ownership changes hands. 4. Water and water -alternating -gas injection into the LOP will preserve reservoir energy and increase ultimate recovery. 5. There are no freshwater aquifers in the affected area of the LOP. 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 747 July 24, 2018 Page 7 of 10 7. Filing the proposed submittals, rather than those required by 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 gas -oil ratio (GOR) limitation waiver is appropriate because the LOP will be developed as a watertlood 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. NOW THEREFORE IT IS ORDERED: Development and operation of the GMTU 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 11 North, Range 2 East Sections 13-14: All Sections 23-26: All Sections 35-36: All Township 11 North, Range 3 East Sections 17-19: All Sections 29-32: All Township 10 North, Range 2 East Section 1: All Section 2: NEI/4 Township 10 North, Range 3 East Section 6: All 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 Lookout Oil Pool. Rule 2 Pool Definition The Lookout Oil Pool is defined as the accumulation of oil common to and correlating with the interval within the Lookout -1 well between the measured depths of 7,833 and 8,000 feet on the resistivity log recorded in exploratory well Lookout -1. (See Figure 2, above.) CO 747 July 24, 2018 Page 8 of 10 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 Lookout Oil Pool 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 Lookout Oil Pool 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 Lookout Oil Pool 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 production or 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 -7,850 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 10412, 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 Lookout Oil Pool are exempt from the Gas -Oil Ratio 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. Rule 8 Annual Reservoir Review a. An annual reservoir surveillance report must be filed by April I' 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; CO 747 July 24, 2018 Page 9 of 10 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; 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 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 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 raring 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. 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 Comminatine. Measurement and Allocation a. Production from Lookout Oil Pool 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. CO 747 July 24, 2018 Page 10 of 10 Rule 11 Administrative Action Upon proper application, or its own motion, and unless notice and public hearing are otherwise required, the Commission my 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. DONE at Anchorage, Alaska and dated July 24, 2018 nunc pro tunc May 29, 2018. //signature on file// //signature on file// //signature on file// Hollis S. French Daniel T. Seamount, Jr. Cathy P. Foerster Chair, Commissioner Commissioner Commissioner AND APPEAL NOTICE As provided in AS 31.05.080(a), within 20 days after written notice of the entry of this order or decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration of the matter determined by it. If the notice was mailed, then the period of time shall be 23 days. An application for reconsideration most 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 pan 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 in 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 Colombie, Jody J (DOA) From: Colombie, Jody J (DOA) Sent: Wednesday, July 25, 2018 12:22 PM To: Bell, Abby E (DOA); Bixby, Brian D (DOA); Boyer, David L (DOA); Brooks, Phoebe L (DOA); Carlisle, Samantha J (DOA); Colombie, Jody J (DOA); Cook, Guy D (DOA); Davies, Stephen F (DOA); Earl, Adam G (DOA); Erickson, Tamara K (DOA); Foerster, Catherine P (DOA); French, Hollis (DOA); Frystacky, Michal (DOA); Guhl, Meredith D (DOA); Herrera, Matthew F (DOA); Jones, Jeffery B (DOA); Kair, Michael N (DOA); Laubenstein, Lou (DOA); Loepp, Victoria T (DOA); Martin, Teddy J (DOA); McLeod, Austin (DOA); Mcphee, Megan S (DOA); Mumm, Joseph (DOA sponsored); Noble, Robert C (DOA); Paladijczuk, Tracie L (DOA); Pasqual, Maria (DOA); Regg, James B (DOA); Rixse, Melvin G (DOA); Roby, David S (DOA); Schwartz, Guy L (DOA); Seamount, Dan T (DOA); Wallace, Chris D (DOA); AK, GWO Projects Well Integrity, AKDCWellIntegrityCoordinator; Alan Bailey, Alex Demarban; Alicia Showalter; Allen Huckabay; Andrew VanderJack; Ann Danielson; Anna Lewallen; Anna Raff; Barbara F Fullmer, bbritch; bbohrer@ap.org; Ben Boettger; Bill Bredar; Bob Shavelson; Bonnie Bailey; Brandon Viator; Brian Havelock; Bruce Webb; Caleb Conrad; Candi English; Cody Gauer; Cody Terrell; Colleen Miller, Connie Downing; Crandall, Krissell; D Lawrence; Dale Hoffman; Danielle Mercurio; Darci Horner; Dave Harbour, David Boelens; David Duffy; David House; David McCaleb; David Pascal; ddonkel@cfl.rr.com; Diemer, Kenneth J (DNR); DNROG Units (DNR sponsored); Donna Ambruz; Ed Jones; Elizabeth Harball; Elowe, Kristin; Elwood Brehmer; Evan Osborne; Evans, John R (LDZX); Brown, Garrett A (DNR); George Pollock; Gordon Pospisil; Greeley, Destin M (DOR); Greg Kvokov; Gretchen Stoddard; gspfoff, Hurst, Rona D (DNR); Hyun, James J (DNR); Jacki Rose; Jason Brune; Jdarlington Oarlington@gmail.com); Jeanne McPherren; Jerry Hodgden; Jill Simek; Jim Shine; Jim Watt; Jim White (im4thgn@gmail.com); Young, Jim P (DNR); Joe Lastufka; Radio Kenai; Burdick, John D (DNR); Easton, John R (DNR); Larsen, John M (DOR); Jon Goltz; Joshua Stephen; Juanita Lovett; Judy Stanek, Kari Moriarty; Kasper Kowalewski; Kazeem Adegbola; Keith Torrance; Keith Wiles; Kelly Sperback; Frank, Kevin J (DNR); Kruse, Rebecca D (DNR); Kyla Choquette; Gregersen, Laura S (DNR); Leslie Smith; Lori Nelson; Luke Keller; Marc Kovak; Dalton, Mark (DOT sponsored); Mark Hanley (mark.hanley@anadarko.com); Mark Landt; Mark Wedman; Michael Bill; Michael Calkins; Michael Moora; Michael Quick; Michael Schoetz; Mike Morgan; MJ Loveland; Motteram, Luke A; Mueller, Marta R (DNR); Nathaniel Herz; knelson@petroleumnews.com; Nichole Saunders; Nick Ostrovsky; NSK Problem Well Supv; Patty Alfaro; Paul Craig; Decker, Paul L (DNR); Paul Mazzolini; Pike, Kevin W (DNR); Randall Kanady; Renan Yanish; Richard Cool; Robert Brelsford; Robert Tirpack; Robert Warthen; Ryan Gross; Sara Leverette; Scott Griffith; Shahla Farzan; Shannon Donnelly, Sharon Yarawsky; Skutca, Joseph E (DNR); Smith, Kyle S (DNR); Spuhler, Jes J (DNR); Stephanie Klemmer; Stephen Hennigan; Stephen Ratcliff; Sternicki, Oliver R, Moothart, Steve R (DNR); Steve Quinn; Suzanne Gibson; sheffield@aoga.org; Tanisha Gleason; Ted Kramer; Teresa Imm; Terry Caetano; Tim Mayers; Todd Durkee; Tom Maloney; Tyler Senden; Umekwe, Maduabuchi P (DNR); Vern Johnson; Vinnie Catalano; Well Integrity; Well Integrity; Weston Nash; Whitney Pettus; Aaron Gluzman; Aaron Sorrell; Ajibola Adeyeye; Alan Dennis, Andy Bond; Bajsarowicz, Caroline J; Bruce Williams; Casey Sullivan; Corey Munk, Don Shaw, Eppie Hogan; Eric Lidji; Garrett Haag; Smith, Graham O (DNR); Heusser, Heather A (DNR); Fair, Holly S (DNR); Jamie M. Long; Jason Bergerson; Jesse Chielowski; Jim Magill; Joe Longo; John Martineck; Josh Kindred; Keith Lopez; Laney Vazquez; Lois Epstein; Longan, Sara W (DNR); Marc Kuck; Marcia Hobson; Matt Armstrong; Melonnie Amundson; Franger, James M (DNR); Morgan, Kirk A (DNR); Umekwe, Maduabuchi P (DNR); Pat Galvin; Pete Dickinson; Peter Contreras; Rachel Davis; Richard Garrard; Richmond, Diane M; Robert Province; Ryan Daniel; Sandra Lemke; Scott Pins; Pollard, Susan R (LAW); Talib Syed; Tina Grovier (tmgrovier@stoel.com); William Van Dyke; Zachary Shulman Subject: Corrected AIO 40 and CO 747 (CPA) Attachments: co747 corrected.pdf; aio40 corrected.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 Lookout Oil Pool within the Greater Moose's Tooth Unit, Greater Moose's Tooth Field, Lookout Oil Pool Re: THE APPLICATION OF ConocoPhillips Alaska, Inc. for an order authorizing underground injection of fluids for enhanced oil recovery in the proposed Lookout Oil Pool within the Greater Moose's Tooth Unit Jody J. CoCombie AOGCC SpeciaC Assistant Ai(aska OiCandGas Conservation Commission 333 West 711 Avenue .?anchorage, .Alaska 99501 Office: (907) 793-1221 Fax: (907) 276-7542 Docket Number: CO -18-001 Conservation Order No. 747 Corrected Greater Moose's Tooth Unit Greater Moose's Tooth Field Greater Moose's Tooth -Lookout Oil Pool North Slope Borough, Alaska May 29, 2018 Corrected July 24, 2018 Docket Number: AIO-18-013 Area Injection Order No. 40 Greater Moose's Tooth Unit Greater Moose's Tooth Field Greater Moose's Tooth -Lookout Oil Pool North Slope Borough, Alaska May 29, 2018 Corrected July 24, 2018 CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Jody Colombie at 907.793.1221 or iodv. colombie@alaska.gov. Bernie Karl Gordon Severson Penny Vadla M Recycling Inc. 3201 Westmar Cir. 399 W. Riverview Ave. P.O. Box 58055 Anchorage, AK 99508-4336 Soldotna, AK 99669-7714 Fairbanks, AK 99711 George Vaught, Jr. Darwin Waldsmith Richard Wagner P.O. Box 13557 P.O. Box 39309 P.O. Box 60868 Denver, CO 80201-3557 Ninilchik, AK 99639 Fairbanks, AK 99706 THE STATE oALASKA� GOVERNOR BILL WALKER July 24, 2018 Mr. Stephen Thatcher Manager, WNS Development North Slope Operations and Development ConocoPhillips Alaska, Inc. PO Box 100360 Anchorage, AK 99510 Re: Docket Numbers: CO -18-001 and AIO-18-013 Request for Reconsideration Conservation Order No. 747 and Area Injection Order No. 40 Dear Mr. Thatcher: Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.alaska.gov By letter dated June 7, 2018, 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 Lookout Oil Pool (LOP) in the Greater Moose's Tooth Unit. CPAI's request is granted in part. The only rejected proposed change is CPAI's request to remove the word "production" from Rule 9d of Conservation Order No. 747, which prescribes when the operator must notify the AOGCC of a sustained casing pressure issue, so that the rule would apply to all wells and not just producers. CPAI's assertion that the rule is typically applied to both producers and injectors is incorrect because injection wells have their own notification requirements as dictated by the Area Injection Order. The notification requirement for injection wells in the LOP is in Rule 7 of Area Injection Order No. 40: "[w]henever any pressure communication, leakage or lack of injection zone isolation is indicated by an injection rate, operating pressure observation, test, survey, log, or any other evidence (including outer annulus pressure monitoring of all wells within a one-quarter mile radius of where the Lookout Oil Pool is not cemented), the Operator shall notify the AOGCC by the next business day ..." Because different notification requirements apply to producers and injectors, the AOGCC modified the sustained casing pressure notification language in the conservation order to make it clear that the rule applies only to producers and not to injectors. Request for Reconsideration Docket Numbers: CO -18-001 and A10-1 8-013 July 24, 2018 Page 2 of 2 As such, the AOGCC is rejecting CPAI's proposed change to Rule 9d of Conservation Order No. 747. As stated earlier all other recommendations in CPAI's letter will be adopted and corrected orders issued. Sincerely, Hollis S. French Chair, Commissioner This decision is 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 decision 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. 5 ConocoPhillips June 7, 2018 Alaska Oil and Gas Conservation Commission 333 W. 7th Ave #100 Anchorage, Alaska, 99501-3539 RE: Request for Reconsideration Conservation Order No. 747, Lookout Oil Pool, North Slope, AK Area Injection Order No, 40, Lookout Oil Pool, North Slope, AK Dear Commissioners: Stephen Thatcher Manager, WNS Development North Slope Operations and Development ConocoPhillips Alaska, Inc. ATO -1770 700 G Street Anchorage, AK 99501 phone 907.263.4464 JUN 0 7 2016 ConocoPhillips Alaska, Inc. ("ConocoPhillips") appreciates the Commission's timely issuance of the orders referenced above. To correct a few minor issues in the orders, ConocoPhillips respectfully requests reconsideration of the orders for the following items: • Conservation Order Conclusion 8 states that injectors will be pre -produced. We currently do not plan on pre -producing injectors. We may pre -produce injectors but that is not our plan. Accordingly, we request that the sentence describing pre -production of injectors be modified to provide that injectors "may" be pre -produced. We have no concerns with the language in the corresponding Rule 7. • Conservation Order Rule 5 requires that a gamma ray and resistivity log be run from conductor to TD. This would be a significant departure from regulation 20 AAC 25.071 which states that a gamma ray or a resistivity log be run. We request that Rule 5 be consistent with 20 AAC 25.071 allowing the option of gamma ray or resistivity. Although we often run both logs, some situations allow us to run only one log with accompanying cost savings and no practical loss in necessary information. • Conservation Order Rule 6b references Rule 9 and this should be Rule 8. • Conservation Order Rule 9d, specifies a production well in the first sentence. This rule has typically been applied to both production and injection wells. To make the rule applicable to both production and injection wells, ConocoPhillips requests the word 'production' in 'production well' should be deleted in the first sentence to read as follows: o If the operator identifies sustained pressure in the inner annulus of a preddstien well that exceeds .... • Area Injection Order Rule 5 has conflicting requirements stating that tubing and annulus pressures be 'monitored each day' in the first sentence of the rule and 'constantly monitored' in the second sentence. Although ConocoPhillips does plan on installing equipment to constantly monitor well tubing and annuli pressures, this equipment can fail and require the fallback of the Request for Reconsideration of Conservation Order No. 747 and Area Injection Order No. 40 Page 2 of 2 daily manual inspections and recording which are performed regardless of whether the equipment is working or not. Also, ConocoPhillips does not believe there should be a requirement to install such equipment as it is costly and may not always be necessary. Additionally, if there is extreme weather, emergency, or other unavoidable conditions, the daily inspection requirement should not apply. Consequently, ConocoPhillips requests that the same rule applied in Area Injection Orders 28, 30, and 35 be used in the Lookout AIO. Consistent with the referenced orders, ConocoPhillips requests the AIO Rule 5 be amended to provide: �, predastien-wells- Inner annulus, outer annulus, and tubing_,.pressure,..,,.,..T, shall be senGn stant}y monitored and recorded at least daily, except if prevented by extreme weather condition, emergency situations, or similar unavoidable circumstances for all injection and production wells. The outer annulus pressures of all wells that are not cemented across the Lookout Oil Pool and are located within a %-mile radius of a Lookout Oil Pool injector shall be monitored daily. All monitoring results shall be documented and available for AOGCC inspection. • Area Injection Order Rule 7 has a reference to the Kuparuk River -Torok Oil Pool and this should be the Lookout Oil Pool. Please contact John Cookson (265-6547) if you have questions or would like to discuss this request for reconsideration. Regards, Stephen Thatcher Manager, WINS Development North Slope Operations and Development m AOGCC 4/3/2018 ITMO: APPLICATIONS OF CONOCOPHILLIPS AK Docket No. CO 18-001 & A1018-013 ALASKA OIL AND GAS CONSERVATION COMMISSION Before Commissioners: Hollis French, Chair Daniel T. Seamount Cathy Foerster In the Matter of the Applications of ) ConocoPhillips Alaska, Inc., to establish ) pool rules for Lookout Oil Pool in the ) Greater Mooses Tooth Unit and issue an ) Area Injection Order to authorize a water ) alternating enriched gas injection process ) for enhanced oil recovery purposes in the ) Lookout Oil Pool. ) Dockets No.: CO 18-001 AIO 18-013 ALASKA OIL and GAS CONSERVATION COMMISSION Anchorage, Alaska April 3, 2018 10:00 o'clock a.m. PUBLIC HEARING Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email: while@gci.net AOGCC 4/3/2018 ITMO: APPLICATIONS OF CONOCOPHILLIPS AK Docket No. CO 18-001 & A1018-013 Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email: mhile@gci.net Page 2 1 TABLE OF CONTENTS 2 Opening remarks by Chair French 03 3 Remarks by Mr. Cookson 06 4 Remarks by Ms. Doherty 07 5 Remarks by Mr. Noel 09 6 Remarks by Mr. Versteeg 10 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: mhile@gci.net AOGCC 4/3/2018 ITMO: APPLICATIONS OF CONOCOPHILLIPS AK Docket No. CO 18-001 & A1018-013 Page 3 1 P R O C E E D I N G S 2 (On record - 10:00 a.m.) 3 CHAIR FRENCH: I'll go ahead and call the 4 meeting to order. It's April 3rd, the year 2018, it's 5 10:00 o'clock in the morning. We're at 333 West 6 Seventh Avenue in Anchorage, Alaska. This is the 7 headquarters of the Alaska Oil and Gas Conservation 8 Commission. To my right is Commissioner Cathy 9 Foerster, to my left is Commissioner Dan Seamount, I'm 10 Hollis French, I'm the Chair of the Commission. 11 Today we have before us docket numbers CO 18- 12 001 and AIO 18-013, which pertain to the Lookout Pool, 13 Greater Mooses Tooth Unit, application for pool rules 14 and an area injection order. 15 ConocoPhillips Alaska, Incorporated by 16 applications both dated on February 28th, 2018, 17 requests that the Alaska Oil and Gas Conservation 18 Commission establish pool rules for their proposed 19 Lookout Oil Pool in the Greater Mooses Tooth Unit and 20 issue an injection order to authorize a water 21 alternating enriched gas injection process for enhanced 22 oil recovery purposes in the proposed LOP, the Lookout 23 Pool. 24 Computer Matrix will be recording the 25 proceedings, you can get a copy of the transcript from Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net AOGCC 4/3/2018 ITMO: APPLICATIONS OF CONOCOPHILLIPS AK Docket No. CO 18-001 & A1018-013 Page 4 1 Computer Matrix Reporting. 2 We have four people signed up to testify today. 3 Any other parties planning to testify? 4 (No comments) 5 CHAIR FRENCH: I don't see any hands. 6 The Commissioners will ask questions during the 7 testimony, we all -- we may also take a recess to 8 consult with staff to determine whether additional 9 information or clarifying questions are necessary. If 10 a member of the audience has a question that he or she 11 feels should be asked, please submit that question in 12 writing to Jody Colombie, she will provide the question 13 to the Commissioners and if we feel that asking the 14 question will assist us in making our determinations we 15 will ask it. 16 For those testifying please keep in mind that 17 you must speak into the microphone so that those in the 18 audience and the court reporter can hear your 19 testimony. Also please remember to reference your 20 slides so that someone reading the public record can 21 follow along. For example refer to slides by their 22 numbers if numbered or by their titles if not numbered. 23 We just have a couple of ground rules on what's 24 allowed relative to testimony. First all testimony 25 must be relevant to the purposes of the hearing that I Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net AOGCC 4/3/2018 ITMO: APPLICATIONS OF CONOCOPHILLIPS AK Docket No. CO 18-001 & A1018-013 Page 5 1 outlined a few minutes ago and to the statutory 2 authority of the AOGCC. Anyone desiring to testify may 3 do so, but if testimony drifts off subject we will 4 limit the testimony. Additionally, testimony may not 5 take the form of cross examination, as I said before 6 the Commissioners will be asking the questions. And 7 finally testimony that is disrespectful or 8 inappropriate will not be allowed. 9 Commissioner Foerster or Seamount, anything to 10 add before we start the hearing? 11 COMMISSIONER SEAMOUNT: I have none. 12 COMMISSIONER FOERSTER: Nope. 13 CHAIR FRENCH: All right then. Let's go ahead 14 and get started. I see we have some folks here at the 15 table prepared to testify. Why don't we start by 16 swearing you all in and then we'll have you introduce 17 yourselves. 18 If you would raise your right hand. 19 (Oath administered) 20 IN UNISON: I do. 21 CHAIR FRENCH: Excellent. Let's just -- let's 22 go from my left to right. If you'd introduce yourself, 23 sir. 24 MR. COOKSON: (Indiscernible - away from 25 microphone)..... Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net AOGCC 4/3/2018 ITMO: APPLICATIONS OF CONOCOPHILLIPS AK Docket No. CO 18-001 & A1018-013 Page 6 1 CHAIR FRENCH: Microphone on. 2 COMMISSIONER FOERSTER: Push the button. 3 MR. COOKSON: Thank you. That works. 4 CHAIR FRENCH: Green light. Very good. 5 JOHN COOKSON 6 previously sworn, called as a witness on behalf of 7 ConocoPhillips Alaska, testified as follows on: 8 DIRECT EXAMINATION 9 MR. COOKSON: Okay. We have -- I'm John 10 Cookson. We're on slide number 2. This just presents 11 the presenter's biography. 12 CHAIR FRENCH: Sure. 13 MR. COOKSON: So my name's John Cookson, I'm 14 employed by ConocoPhillips Alaska, production engineer. 15 I have a bachelor's and master's degrees in petroleum 16 engineering from Colorado School of Mines. I have 32 17 years experience, 16 of those are on the North Slope 18 working fields like Kuparuk, Prudhoe, Point Thomson and 19 Alpine. And I wish to be accepted as an expert witness 20 in production engineering. 21 CHAIR FRENCH: All right. Let's stop for a 22 moment and take up that question. Any questions for 23 Mr. Cookson about his qualifications to be an expert 24 witness in production engineering, Commissioner 25 Foerster or Commissioner Seamount. Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email sahile@gci.net AOGCC 4/3/2018 ITMO: APPLICATIONS OF CONOCOPHILLIPS AK Docket No. CO 18-001 & A1018-013 Page 7 1 COMMISSIONER FOERSTER: I'm very familiar with 2 Mr. Cookson and I have no problem..... 3 CHAIR FRENCH: Commissioner Seamount. 4 COMMISSIONER FOERSTER: .....recognizing him as 5 a production engineering expert. 6 COMMISSIONER SEAMOUNT: I have no comments, 7 objections or questions of Mr. Cookson being designated 8 a production -- an expert at production engineering. 9 CHAIR FRENCH: And so it shall be. Thank you, 10 Mr. Cookson. 11 MR. COOKSON: Thank you. 12 JENNIFER DOHERTY 13 previously sworn, called as a witness on behalf of 14 ConocoPhillips Alaska, testified as follows on: 15 DIRECT EXAMINATION 16 MS. DOHERTY: Good morning. My name is 17 Jennifer Doherty. I work for ConocoPhillips Alaska. 18 I'm a development geologist. I have a BS in geology 19 from James Madison University in Virginia. I have an 20 MS in geology from the University of Texas at Austin. 21 I have 18 years of industry experience, 11 years in 22 Alaska working both the Kuparuk and Alpine fields. And 23 I request the -- permitted to be an expert witness in 24 geology. 25 CHAIR FRENCH: Let's take up that question. Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net AOGCC 4/3/2018 ITMO: APPLICATIONS OF CONOCOPHILLIPS AK Docket No. CO 18-001 & A1018-013 1 Any questions for Ms. Doherty regarding her expert 2 qualifications in the field of geology? 3 COMMISSIONER FOERSTER: I have none. 4 CHAIR FRENCH: Commissioner Seamount. 5 COMMISSIONER SEAMOUNT: Ms. Doherty, where is 6 James Madison University? 7 MS. DOHERTY: It's in Harrisonburg, Virginia. 8 COMMISSIONER SEAMOUNT: Virginia. Okay. I 9 thought it was on the east coast. Also do you have 10 experience in seismic data, interpreting seismic lines, 11 things like that? 12 MS. DOHERTY: I do. 13 COMMISSIONER SEAMOUNT: Okay. So you're also 14 an exploration geologist? 15 MS. DOHERTY: I suppose I have worked in 16 exploration in the past. I have interpreted seismic 17 both for development and exploration. 18 COMMISSIONER SEAMOUNT: Okay. Well, I have no 19 comments or questions regarding designating you as an 20 expert witness in -- is it development geologist or 21 geology? I think it's geology. 22 MS. DOHERTY: Geology. 23 COMMISSIONER SEAMOUNT: Okay. 24 CHAIR FRENCH: You'll be a -- you'll be an 25 expert for the purposes of today's hearing, Ms. Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK99501 Fax: 907-243-1473 Email• sahilea@gci.net AOGCC 1 Doherty 4/3/2018 ITMO: APPLICATIONS OF CONOCOPHILLIPS AK Docket No. CO 18-001 & A1018-013 Page 9 2 Next up. 3 BRIAN NOEL 4 previously sworn, called as a witness on behalf of 5 ConocoPhillips, testified as follows on: 6 DIRECT EXAMINATION 7 MR. NOEL: Yes, good morning. My name's Brian 8 Noel. I'm a drilling engineer with ConocoPhillips. I 9 have a BS in geology from the University of Illinois 10 and a BS in petroleum engineering from the University 11 of Wyoming. I'm a licensed professional engineer here 12 in the state of Alaska. A long time in the industry 13 with 27 years here in the state working as an engineer. 14 I ask to be accepted as an expert in drilling 15 engineering. 16 CHAIR FRENCH: I'm sorry, in drilling 17 engineering? 18 MR. NOEL: Yes. Drilling engineering. 19 CHAIR FRENCH: very good. Thank you, Mr. Noel. 20 Any questions for Mr. Noel about his qualifications to 21 be an expert in drilling engineering? 22 COMMISSIONER FOERSTER: I'm very familiar with 23 Mr. Noel and -- and have no problems accepting him as 24 an expert in drilling engineering. 25 CHAIR FRENCH: Excellent. 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 4/3/2018 ITMO: APPLICATIONS OF CONOCOPHILLIPS AK Docket No. CO 18-001 &A1018-013 Page 10 1 Seamount, any questions or -- or objections? 2 COMMISSIONER SEAMOUNT: Mr. Noel, when were you 3 at the University of Wyoming? 4 MR. NOEL: I graduated in 191 so late 180s. 5 COMMISSIONER SEAMOUNT: Late 180s. Okay. 6 That's when I lived there. That's my second favorite 7 state. 8 MR. NOEL: I would -- I would agree with that. 9 COMMISSIONER SEAMOUNT: Okay. I have no other 10 questions or comments regarding Mr. Noel as an expert 11 witness in drilling engineering. 12 CHAIR FRENCH: Very good. 13 COMMISSIONER SEAMOUNT: But you are a geologist 14 too, right? 15 MR. NOEL: (Indiscernible - away from 16 microphone)..... 17 COMMISSIONER SEAMOUNT: Okay. Very good. 18 CHAIR FRENCH: Excellent. And finally you, 19 sir, good morning. 20 JOE VERSTEEG 21 previously sworn, called as a witness on behalf of 22 ConocoPhillips Alaska, testified as follows on: 23 DIRECT EXAMINATION 24 MR'. VERSTEEG: Good morning. My name's Joe 25 Versteeg. I'm a reservoir engineer for ConocoPhillips. Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net AOGCC 4/3/2018 ITMO: APPLICATIONS OF CONOCOPHILLIPS AK Docket No. CO 18-001 & A1018-013 Page it 1 I have a BS in petroleum engineering from the 2 University of Alaska Fairbanks and I have 21 years of 3 industry experience with 18 years in Alaska working the 4 Kuparuk, Prudhoe Bay and Alpine fields. And I would 5 request to be accepted as a -- an expert in reservoir 6 engineering. 7 CHAIR FRENCH: Very good, Mr. Versteeg. Thank 8 you. Any questions or objections to Mr. Versteeg? 9 COMMISSIONER FOERSTER: I'm very familiar with 10 Mr. Versteeg and recognize him as an expert in 11 reservoir engineering. 12 CHAIR FRENCH: Commissioner Seamount, any 13 objections? 14 COMMISSIONER SEAMOUNT: No, I have no 15 objections. I notice that Mr. Versteeg comes from my 16 favorite state and I have no objections to naming -- to 17 regarding him as an expert witness in reservoir 18 engineering. 19 CHAIR FRENCH: Excellent. Thank you. Good 20 morning to you all. I'll turn the presentation over to 21 you and let you proceed as you wish and we'll follow 22 along and ask questions as they come up. 23 MR. COOKSON: Okay. Thank you. First of all 24 we'd like to thank the Commission and the staff, 25 Commissioners and the staff, for their help Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email sahile@gci.net AOGCC 4/3/2018 ITMO: APPLICATIONS OF CONOCOPHILLIPS AK DocketNo. CO 18-001 & A1018-013 Page 12 1 establishing these orders today. 2 I'm John Cookson and we're on slide number 3. 3 This is our planned testimony for today. This 4 testimony covers both the area injection order and the 5 conservation order, we're not breaking this up into two 6 separate sessions. we have a broad overview of the 7 geologic properties that are not confidential and we do 8 have a few slides that are confidential. Those slides 9 of some Alpine C and net pay interpretations. 10 So we're on slide number 4 now and this slide 11 shows a broad overview of Lookout in the bigger scheme 12 of things. Lookout PA boundary is shown in red and the 13 Lookout drillsite is called MT6 pad. That stands for 14 Mooses Tooth and the sixth drillsite connected to the 15 Alpine support facilities. 16 Mooses Tooth's Lookout project is also known as 17 the Greater Mooses Tooth 1 project. So you'll see that 18 (indiscernible - away from microphone) this 19 presentation. 20 Lookout lies eight miles southwest of CD5, 21 that's the nearest existing drillsite, 14 miles 22 southwest of the central facilities. 23 CHAIR FRENCH: Mr. Cookson, what does -- what 24 does the green -- the green line extends -- on this 25 slide the green line extends in an unbroken fashion Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net AOGCC 4/3/2018 ITMO: APPLICATIONS OF CONOCOPHILLIPS AK Docket No. CO 18-001 & A1018-013 Page 13 1 from CD5 to -- to MT6 and then it sort of breaks up as 2 it goes out to a designation that I'll say is GMT2, 3 what does that mean? 4 MR. COOKSON: That's a work of art right there 5 that the -- the -- the green line that's the -- that is 6 the pipeline. And it and the brown line kind of 7 follows so that's the road system. And so from CD5 to 8 MT6 that's the road and pipeline that are going to be 9 in place here when this project comes online. We're 10 placing those -- the road's in place, but we're 11 finishing up the pipeline right now. 12 The GM2 project is in the planning phases and 13 that road and what -- you see that broken up session, 14 that doesn't exist yet, that's something the future 15 from MT6 out to GMT2. So that's -- that's what we're 16 planning. 17 CHAIR FRENCH: So the -- the -- the dots and 18 the dashes, the -- the green and brown sort of 19 dashes..... 20 MR. COOKSON: Right there, that..... 21 CHAIR FRENCH: .....to the southwest..... 22 MR. COOKSON: .....that does not exist. 23 CHAIR FRENCH: That's all in planning? 24 MR. COOKSON: That's all in planning. 25 CHAIR FRENCH: Okay. Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Arch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net AOGCC 4/3/2018 ITMO: APPLICATIONS OF CONOCOPHILLIPS AK Docket No. CO 18-001 & AI018-013 Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Page 14 1 MR. COOKSON: The GMT2 pad is not there, that's 2 in planning too, exactly. 3 CHAIR FRENCH: Fair enough. Thank you. 4 MR. COOKSON: So the..... 5 COMMISSIONER SEAMOUNT: Excuse me, Mr. Cookson. 6 Is that going to be a gravel road..... 7 MR. COOKSON: Yes. 8 COMMISSIONER SEAMOUNT: .....GMT2? 9 MR. COOKSON: Yes. 10 COMMISSIONER SEAMOUNT: Okay. And it's 11 interesting that your pad is way on the southern side 12 of the pool and it looks like -- what is it, about six 13 miles northsouth, the pool? 14 MR. COOKSON: The pool is -- I can tell -- 15 well, let's look here. 16 COMMISSIONER SEAMOUNT: Maybe you're going to 17 cover that later. 18 MR. COOKSON: Well, we're going to cover it, 19 but I -- we can take a look at it here real quick. 20 COMMISSIONER SEAMOUNT: I mean, why is it on 21 the edge of the pool, the pad? 22 MR. COOKSON: That is for well placement..... 23 COMMISSIONER SEAMOUNT: Okay. 24 MR. COOKSON: .....well planning purposes 25 directional. Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net AOGCC 4/3/2018 ITMO: APPLICATIONS OF CONOCOPHILLIPS AK DocketNo. CO 18-001 & A1018-013 6 COMMISSIONER SEAMOUNT: Okay. 7 CHAIR FRENCH: And just as a reminder if you 8 would when you -- we're always happy to hear from you, 9 just..... 10 MS. DOHERTY: (Indiscernible - away from 11 microphone)..... 12 CHAIR FRENCH: Yeah, that -- that's exactly 13 what I want just for the record to -- to let us know 14 who's speaking. 15 Thank you. 16 COMMISSIONER FOERSTER: It'll be easier to tell 17 you from the rest, but set a good example for them. 18 MR. COOKSON: Okay. So we got the distances. 19 The Lookout PA is entirely within the National 20 Petroleum Reserve of Alaska. So if I'm not mistaken 21 this will be the first pool that's totally within the 22 NPRA. And you can see the NPRA boundary is shown in 23 the black dotted lines. The -- this drawing shows all 24 the existing exploration wells and development wells. 25 The exploration wells are the back dots and the Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Page 15 1 MS. DOHERTY: It's also to keep it out of the 2 Fish Creek setback..... 3 COMMISSIONER SEAMOUNT: Oh. 4 MS. DOHERTY: .....(indiscernible - away from 5 microphone) surface restraints. 6 COMMISSIONER SEAMOUNT: Okay. 7 CHAIR FRENCH: And just as a reminder if you 8 would when you -- we're always happy to hear from you, 9 just..... 10 MS. DOHERTY: (Indiscernible - away from 11 microphone)..... 12 CHAIR FRENCH: Yeah, that -- that's exactly 13 what I want just for the record to -- to let us know 14 who's speaking. 15 Thank you. 16 COMMISSIONER FOERSTER: It'll be easier to tell 17 you from the rest, but set a good example for them. 18 MR. COOKSON: Okay. So we got the distances. 19 The Lookout PA is entirely within the National 20 Petroleum Reserve of Alaska. So if I'm not mistaken 21 this will be the first pool that's totally within the 22 NPRA. And you can see the NPRA boundary is shown in 23 the black dotted lines. The -- this drawing shows all 24 the existing exploration wells and development wells. 25 The exploration wells are the back dots and the Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net AOGCC 4/3/2018 ITMO: APPLICATIONS OF CONOCOPHILLIPS AK Docket No. CO 18-001 & A1018-013 Page 16 1 development wells are the purple lines. That's the -- 2 where the wells are, the lateral extensions of the 3 well. Lookout will be -- the nearest Lookout wells 4 will be approximately three miles from the nearest 5 existing wells and that would be down here. The 6 nearest wells would be the CD5 well here. 7 Okay. I'm on to the next slide, this is number 8 5. We'll talk about ownership and boundaries. And 9 this gives us, Commissioner Seamount, this shows you 10 then the length of that pool so there's..... 11 COMMISSIONER SEAMOUNT: Uh-huh. 12 MR. COOKSON: .....section on it so it's one, 13 two, three, four, five, five miles. 14 The working interest owners are ConocoPhillips 15 and Anadarko. The sale of Anadarko leasehold to 16 ConocoPhillips is pending government approval. All of 17 these leases shown on this are ConocoPhillips and 18 Anadarko held leases except for the leases in white and 19 those would include these leases up here vertically and 20 horizontally. So those leases are unleased. 21 The surface owners are Kuukpik and BLM. The 22 subsurface owners are ASRC and BLM. Notification has 23 been made to the surface owners as required by the area 24 injection order. The crosshatched leases are the 25 leases that are owned by Kuukpik and ASRC and the Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email: sahiie@gci.net AOGCC 4/3/2018 ITMO: APPLICATIONS OF CONOCOPHILLIPS AK Docket No. CO 18-001 &A1018-013 Page 17 1 leases that are not crosshatched would be BLM leases 2 CHAIR FRENCH: This is within the purple area? 3 MR. COOKSON: This is within -- well, even 4 outside here is the -- the yellow leases are BLM leases 5 and even outside the purple area..... 6 CHAIR FRENCH: I see. 7 MR. COOKSON: .....which is the pool boundary 8 and those crosshatched leases are ASRC and Kuukpik 9 leases. 10 CHAIR FRENCH: Sorry. And then the 11 crosshatched area on the white unleased area, well, 12 what is that -- what is that? 13 MR. COOKSON: That would still be Kuukpik and 14 ASRC. 15 CHAIR FRENCH: Okay. I see. I see. 16 MR. COOKSON: It's just unleased. 17 CHAIR FRENCH: Thank you. 18 MR. COOKSON: There's three wells and we'll 19 talk more of course in detail about the wells later 20 both from a geology and integrity standpoint. There's 21 three wells out here in the area, the Lookout 1 and 2, 22 it's kind of hard to see them, but they're right here 23 in the interior. Those penetrated pay and the Mitre 24 number 1 did not penetrate pay in the proposed Lookout 25 pool. Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net AOGCC 4/3/2018 ITMO: APPLICATIONS OF CONOCOPHILLIPS AK Docket No. CO 18-001 & A1018-013 Page 18 1 As far as boundaries are concerned, the violet 2 boundary is our interpretation of the zero contour line 3 for the reservoir. It could be bigger or smaller than 4 this, we'll know more after we drill the development 5 wells. 6 The blue line is participating area and that 7 has been accepted by the owners. So it's now an 8 established participating area. 9 The purple outline is the proposed pool 10 boundary and that includes each full section, 11 intersection -- intersected the reservoir outline 12 except for the Mitre 1 section. That was parsed out 13 into a quarter section so that it did not include the 14 Mitre 1 area where pay was not encountered. 15 Now we're on slide number 6, this is the 16 Lookout Timeline Summary. This -- the map here is the 17 same map we saw on the other slide, the only difference 18 is this shows some additional lease detail. Regarding 19 the timeline, the Lookout 1 and 2 and the Mitre 1 20 wells, the discovery wells, the exploration wells, 21 these were drilled back in 2001 and 2002. CD5 22 development happened in 2015 and that was a key gateway 23 project for the Lookout development, it established 24 infrastructure to the west. We're currently installing 25 -- performing the final installation at the drillsite Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net AOOCC 4/3/2018 ITMO: APPLICATIONS OF CONOCOPHILLIPS AK Docket No. CO I8-001 & A1018-013 Page 19 1 facilities and pipelines. First well, we've scudded 2 that back on March 21st, 2018. We plan on first 3 production in the fourth quarter of 2018 with two 4 wells, two production wells and one injection well. 5 We'll keep the drilling rig out there through 2019 to 6 complete a nine well drilling program. 7 Okay. This next slide shows a very high level 8 development summary. Before we get into the details, 9 all the things we discuss here on this slide -- oh, and 10 I'm on slide number 7, all the things discussed here 11 we'll get into more detail later. We have four 12 producers, five injectors for the total program. You 13 can see on this slide right here that the wells in 14 black are the producers, blue wells are injectors. 15 There's two multi -laterals. We're currently drilling 16 the first well which is the Long number well, it's a 17 producer. The well lengths will be up to 22,500 feet, 18 well spacing is 2,200 feet, the production plan is 19 water injection alternating in rich gas injection. The 20 facilities are similar to the CD5 layout except for 21 Lookout will have a production separator with metering 22 and details regarding that have been discussed at 23 several hearings. Facilities will also include four 24 pipelines, a road and bridges back to CD5. 25 COMMISSIONER SEAMOUNT: Is that well the Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net AOGCC 4/3/2018 ITMO: APPLICATIONS OF CONOCOPHILLIPS AK Docket No. CO 18-001 & A1018-013 Page 20 1 farthest to the northeast, is that a producer or -- or 2 an injector? 3 MR. COOKSON: The farthest to the northeast is 4 a producer 5 COMMISSIONER SEAMOUNT: Okay. 6 MR. COOKSON: And that'll be the last well 7 drilled, that's number 9. 8 CHAIR FRENCH: And I have a very simple 9 question, Mr. Cookson. Just being the nongeologist and 10 nonenginer, I sometimes have to ask like elementary 11 school level questions. But your diagram is very 12 interesting to me, but it just occurs that there must 13 be a large portion of the well I'm not seeing, that 14 you're showing me just the -- just the portion that's 15 in the pay zone and not the -- obviously the distance 16 from the drillsite to the beginning of the pay zone? 17 MR. COOKSON: That's correct. You're not 18 seeing..... 19 CHAIR FRENCH: Okay. 20 MR. COOKSON: .....what we sometimes call the 21 spiders..... 22 CHAIR FRENCH: Right. 23 MR. COOKSON: .....so the wells will all be 24 drilled from the MP6 pad and we're only showing you -- 25 that's a very good question actually, we're only Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Arch. AK 99501 Fax 907-243-1473 Email: sahile@gci.net AOGCC 1 showing you the pay. 4/3/2018 ITMO: APPLICATIONS OF CONOCOPHILLIPS AK Docket No. CO 18-001 & A1018-013 Page 21 2 CHAIR FRENCH: The pay. 3 MR. COOKSON: .....I'm sorry, the -- the well 4 in -- in the pay zone. We also call that..... 5 CHAIR FRENCH: Right. 6 MR. COOKSON: .....the horizontal lateral. 7 CHAIR FRENCH: Okay. Okay. That's a great 8 diagram, interesting. 9 MR. COOKSON: And it's similar -- it's similar 10 to those straight lines you saw on that previous 11 slide..... 12 CHAIR FRENCH: Uh-huh. 13 MR. COOKSON: .....that showed the purple lines 14 where they're -- all the development wells..... 15 CHAIR FRENCH: Uh-huh. 16 MR. COOKSON: .....same thing. 17 CHAIR FRENCH: Thank you. 18 MR. COOKSON: That's -- that's where we 19 intercept the pay. 20 MR. DOHERTY: This is Jennifer Doherty. We do 21 have a full spider map later in the presentation..... 22 CHAIR FRENCH: Of course. Of course. 23 MS. DOHERTY: .....in the drilling section. 24 CHAIR FRENCH: Yep. Those are -- I mean, this 25 is actually a lot easier to understand once you -- once Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net AOGCC 4/3/2018 ITMO: APPLICATIONS OF CONOCOPHILLIPS AK Docket No. CO 18-001 & A1018-013 Page 22 1 you sort of get that, the spider ones are -- are -- I'm 2 not sure my brain works that way. 3 COMMISSIONER SEAMOUNT: Like a spider. 4 CHAIR FRENCH: Something. 5 COMMISSIONER FOERSTER: Before you switch 6 presenters I have a question for you, Mr. Cookson. 7 MR. COOKSON: Ask anything. 8 COMMISSIONER FOERSTER: I will. Have you guys 9 experienced any inefficiencies, duplications of effort 10 or confusion resulting from the overlapping and 11 duplicative regulatory authority between the feds and 12 the state? 13 MR. COOKSON: The only thing I can even mention 14 regarding that is the -- we do have to submit duplicate 15 drilling applications. I don't know -- I can't attest 16 to whether that's been particularly confusing or not, 17 but that is one duplication. There will be some 18 duplications. 19 COMMISSIONER FOERSTER: Okay. Well, we can't 20 eliminate all the duplications, but if there are 21 inefficiencies or confusions or things you think are 22 problematic and solvable, I can't speak for the BLM 23 although I imagine they feel the same way, we want to 24 know about those. 25 MR. COOKSON: Yes. Thanks for bringing that Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net AOGCC 4/3/2018 ITMO: APPLICATIONS OF CONOCOPHILLIPS AK Docket No. CO 18-001 &A1018-013 Page 23 1 up. That -- that's an -- may be an important point and 2 we'll -- we'll work with you on that when we discover 3 thins that we think are cause -- where we can do 4 business better. 5 COMMISSIONER FOERSTER: There are no promises 6 that there won't be some bureaucratic glitch in one of 7 our systems that requires you just grit your teeth and 8 bear it, but where we can we -- we definitely want to 9 smooth the inefficiencies and duplications. 10 MR. COOKSON: Thank you. 11 MS. DOHERTY: This is Jennifer Doherty and we 12 are on slide 8, the Lookout oil pool. This slide -- 13 this slide shows on the left-hand side the 14 stratigraphic column that we use for the North Slope in 15 the western -- western North Slope area. And on the 16 right-hand side I show the Lookout 1 discovery well and 17 the Lookout 2 appraisal well. 18 So on the left-hand side on the stratigraphic 19 column you can see -- where's my -- there we go, you 20 can see a little gold star which highlights where the 21 Alpine C sandstone which is the reservoir that we're 22 developing at the Lookout oil pool is located in the 23 column. It is the upper Jurassic transgressive 24 sandstone that's deposited atop of the upper Jurassic 25 unconformity, also known as the UJU, which is a Computer Matrix, LLC Phone: 907-243-0668 05 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net AOGCC 4/3/2018 ITMO: APPLICATIONS OF CONOCOPHILLIPS AK Docket No. CO 18-001 &A]018-013 Page 24 1 regional unconformity surface across the area. 2 The Lookout 1 well shows the Lookout oil pool 3 section that goes from 7,833 feet MD down to 8,000 feet 4 MD. It includes -- we're proposing to include the 5 Alpine C and the Alpine D atopakik (ph) because it's a 6 continual depositional surface with very similar 7 fracture properties. And our top seal is the Miluveach 8 that sits above it and the Kalubik or sorry, the Kingak 9 that sits below it which I'll show a little bit more on 10 a later slide. This is mostly to highlight the 11 reservoir. 12 You can see that we've broken out the Lookout 1 13 well into three zones. Zone three is at our base, zone 14 two is in the middle and zone one is at the top. We 15 have 129 feet of gross interval and in the Lookout 1 16 well we have about 79 feet of net using a 15 percent 17 porosity cutoff. So mostly that removes this zone two 18 in the center as not net. we have about 20 percent 19 average -- 20 percent average porosity, approximately 20 84 millidarcy average perm and a water saturation 21 calculation of about 16.4. It's relatively low because 22 we've taken out this center section that we're counting 23 as not net. We do have a cased hole MDT in the Lookout 24 1 well that gives us a 42.5 degree API oil. 25 You'll notice that the Lookout 2 is a bit Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Arch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net AOGCC 4/3/2018 ITMO: APPLICATIONS OF CONOCOPHILLIPS AK Docket No. CO 18-001 & A101 8-013 Page 25 1 thinner. The UJU is not as deeply incised into the 2 Kingak formation here. We only have 65 feet of gross 3 interval, but we do have a higher net at 53 feet using 4 the same 15 percent porosity cutoff. We have a similar 5 porosity average of 20 percent, a little bit lower 6 average perm at only 24 millidarcies for the whole 7 interval and calculated a little bit higher water 8 saturation because while there's a much higher net the 9 reservoir quality in here does diminish a little bit 10 that increases our average water saturation over the 11 whole sand. We did have a well test, it was a four day 12 well test that produced about 4,000 barrels of oil per 13 day with a GOR of about 1,500 (indiscernible) per 14 barrel. Our calculated Kh is about 1,300 millidarcy 15 feet for the reservoir. 16 COMMISSIONER FOERSTER: Do you intend to 17 fracture stimulate these wells? 18 MS. DOHERTY: No, we do not. The only other 19 thing to cover is that the oil in the Lookout pool is 20 similar to the Alpine reservoir. It's a lower Kingak 21 source oil. 22 COMMISSIONER SEAMOUNT: And your pay will be 23 cased; is that true..... 24 MS. DOHERTY: The..... 25 COMMISSIONER SEAMOUNT: .....do you run casing Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net AOGCC 1 through the pay? 4/3/2018 ITMO: APPLICATIONS OF CONOCOPHILLIPS AK Docket No. CO 18-001 & A101 8-013 Page 26 2 MS. DOHERTY: Brian. 3 MR. NOEL: This is Brian Noel. No, it'll be a 4 solid line with perforated puffs and an open hole 5 completion. 6 COMMISSIONER SEAMOUNT: Okay. 7 MR. NOEL: .....with a minor top packer above 8 it. 9 COMMISSIONER SEAMOUNT: Like to the north, 10 right, CD1, CD2, those are open hole, right? 11 MR. NOEL: They were open hole and barefoot 12 with -- with no lingers. 13 COMMISSIONER SEAMOUNT: Oh. 14 MR. NOEL: Here we're running the liner given 15 the high productivity of these wells just to make sure 16 we have a conduit for flow in case the same would 17 collapse in chucks on us and lose connectivity. 18 COMMISSIONER SEAMOUNT: Have you had problems 19 with collapsing? 20 MR. NOEL: No, we -- we don't have very many 21 experiences with sand of this quality and strength 22 collapsing on us. 23 MS. DOHERTY: We're now on slide nine and this 24 is to show the confining intervals. So this is a 25 little bit zoomed out log of the Lookout 2 well showing Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net AOGCC 4/3/2018 ITMO: APPLICATIONS OF CONOCOPHILLIPS AK Docket No. CO 18-001 & A1018-013 Page 27 1 the upper confining interval of the Miluveach, Kalubik, 2 HN/HRZ sections which are deep marine shales and silts. 3 It has a variable thickness, minimum of 600 feet to 4 about 1,200 feet TVD. And the variability in that 5 section really comes from the presence of the Fish 6 Creek slumps above where we have thick slumped 7 intervals, we have a much thicker overburden, but there 8 places where that is thinned out. And so that would be 9 the thinner interval. Below us is the Kingak marine 10 shales and siltstones and those are approximately 1,700 11 feet thick. And that's this lower interval below the 12 Alpine C. 13 we're on slide 10, this is the Lookout oil pool 14 on the upper Jurassic or sorry, this is the Lookout oil 15 pool on the upper Jurassic unconformity depth structure 16 map. 17 COMMISSIONER SEAMOUNT: Ms. Doherty, do 18 you..... 19 MS. DOHERTY: Yes. 20 COMMISSIONER SEAMOUNT: .....do you see oil and 21 gas shows within the confining intervals? 22 MS. DOHERTY: No, we haven't generally. Let me 23 go back. The top of our confining interval would be 24 whatever the highest most shale is. So if we had -- 25 for example if there were sands that showed up lower, Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK99501 Fax: 907-243-1473 Email: sahile@gci.net AOGCC 4/3/2018 ITMO: APPLICATIONS OF CONOCOPHILLIPS AK Docket No. CO 18-001 &A1018-013 Page 28 1 we wouldn't include those in the confining zone. So 2 wherever the top of the uppermost sand or the upper 3 most shale goes to, that would be the top of the 4 confining which is why there's a variability from the 5 600 to the 1,200 feet. Because the Fish Creek slumps 6 sometimes entrains silts into them, if there are those 7 silts a little bit deeper down then we would not 8 include those in our confining zone. 9 COMMISSIONER SEAMOUNT: Are you going to talk 10 about source rock? 11 MS. DOHERTY: I was not, but the source rock is 12 the -- the lower Kingak. 13 COMMISSIONER SEAMOUNT: And do you see shows in 14 that zone, the lower Kingak? 15 MS. DOHERTY: We don't generally drill down 16 that deep. 17 COMMISSIONER SEAMOUNT: Okay. 18 MS. DOHERTY: We only usually drill -- the only 19 things that actually go all the way through the Alpine 20 C are the exploration wells and they generally stop 21 just deep enough to get a full set of logs across the 22 sand in this area. So I couldn't answer that question, 23 I haven't seen those. 24 COMMISSIONER SEAMOUNT: Okay. 25 MS. DOHERTY: Okay. We're back to slide 10, Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Arch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net AOGCC 4/3/2018 ITMO: APPLICATIONS OF CONOCOPHILLIPS AK Docket No. CO 18-001 &A1018-013 Page 29 1 the depth structure map on the UJU. So just to cover 2 -- to clear the map, what I'm showing here is the 3 structure map, down dip on the structure is down to the 4 south in our cooler colors. Our warmer colors, the 5 reds and yellows, are our highs and that's up to the 6 north. So the whole area is generally tilted down to 7 the south and you can see the incision edge, we've 8 highlighted that with our -- the white outline here as 9 the boundary, that's our zero contour on our isopack 10 which I'll show in the confidential section. But we've 11 highlighted this on the structure map. You can also 12 see that there are some red lines, those are faults 13 that we have mapped within the reservoir. The most 14 extensive fault that we have is this one right here 15 that runs just up next to the Lookout 2 and to the east 16 of Lookout 1. It has a larger throw down here to the 17 south and then as you move up it does die out within 18 the reservoir confines on the northern edge. And then 19 on the southern edge it dies out just to the south of 20 our sand in the shales of the Kingak. So it does not 21 extend very far. 22 Vertically that fault dies out just above -- we 23 can map it on the seismic just through the reservoir 24 and then it dies out at the base of the Miluveach. 25 Mechanically the sands are more brittle and they should Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net AOGCC 4/3/2018 ITMO: APPLICATIONS OF CONOCOPHILLIPS AK Docket No. C018-001 &Am18-013 Page 30 1 break, but as you move up we don't have the mechanical 2 stratigraphy that the -- that the Miluveach should 3 continue to fracture. So those faults die out as you 4 move up into the Miluveach at the very bottom. So we 5 do have a significant amount of Miluveach still present 6 that does not appear to be faulted. And then on the 7 bottom side it dies out very quickly at the base. 8 There are two smaller faults that are -- have a 9 very small throw. One is an antithetic fault to this 10 larger fault and then we have a small fault maps down 11 here. 1 don't show the planned wells on this, but if 12 you remember the slide previously that had the layout 13 of those, we -- our wells are drilled on either side of 14 the fault, there's three wells, injector, a producer 15 and injector on this side and injector, a producer and 16 an injector on this side. So those wells do not cross 17 the (indiscernible), the only one that does is the 18 producer that's going to be drilling right across here 19 next to Lookout 2. And we're not anticipating very 20 much throw if we see any as we cross that. We've 21 really pushed the trace on this as far as the seismic 22 has even a tiny bauble so that if we do see something 23 when we're drilling we have an idea of where that will 24 be present. But if we do see something it'll be 25 probably less than five feet, very small. We're Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK99501 Fax: 907-243-1473 Email: sahile@gci.net AOGCC 4/3/2018 ITMO: APPLICATIONS OF CONOCOPHILLIPS AK Docket No. CO I8-001 & A1018-013 8 MS. DOHERTY: It's just the way it worked out. 9 It was one of the least -- not that these wells are 10 terribly complicated, but it was the least complicated 11 of them. And we're drilling a pilot hole on that one 12 for data acquisition and so that just happened to be 13 the one that worked out best for that. 14 CHAIR FRENCH: Thank you. 15 MS. DOHERTY: Uh-huh. So this is just a cross 16 section that shows the Lookout 2, Lookout 1 here and 17 then the Mitre well, it sits outside of our Lookout 18 pool and how those correlate. So Lookout 1 and Lookout 19 2 both found a full section of oil pay in the Alpine C 20 sands. And as you can see on this cross section the 21 UJU incises very deeply into the section below the 22 Alpine C and A sands at the Mitre. And so what we have 23 here at Lookout 1 and 2 is that those sands are 24 juxtaposed up against the shale of the Kingak. Mitre 25 is not -- we're not including it within the oil pool Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Page 31 1 actually anticipating that it should die out prior to 2 that location. And then we won't have anything up here 3 in these two wells to the north. 4 CHAIR FRENCH: Ms. Doherty, it looks like that 5 well you're referring to is going to be the first well 6 drilled. Is that coincidence or is it just the way it 7 worked out? 8 MS. DOHERTY: It's just the way it worked out. 9 It was one of the least -- not that these wells are 10 terribly complicated, but it was the least complicated 11 of them. And we're drilling a pilot hole on that one 12 for data acquisition and so that just happened to be 13 the one that worked out best for that. 14 CHAIR FRENCH: Thank you. 15 MS. DOHERTY: Uh-huh. So this is just a cross 16 section that shows the Lookout 2, Lookout 1 here and 17 then the Mitre well, it sits outside of our Lookout 18 pool and how those correlate. So Lookout 1 and Lookout 19 2 both found a full section of oil pay in the Alpine C 20 sands. And as you can see on this cross section the 21 UJU incises very deeply into the section below the 22 Alpine C and A sands at the Mitre. And so what we have 23 here at Lookout 1 and 2 is that those sands are 24 juxtaposed up against the shale of the Kingak. Mitre 25 is not -- we're not including it within the oil pool Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net AOGCC 4/3/2018 ITMO: APPLICATIONS OF CONOCOPHILLIPS AK Docket No. CO 18-001 & A1018-013 Page 32 1 because it found gas in the Alpine C and that gas is 2 indicated both by a core that showed no fluorescence in 3 the Alpine C as well as a NDT (ph) that showed a gas 4 gradient. So we don't have any oil in the Alpine C at 5 Mitre and so we know it's not connected until you 6 actually have gas below the oil over at Lookout. So 7 they can't be connected. And so the interpretation is 8 because of the deep incision at the UJU down into those 9 shales that your side seal put sand on shale and that 10 the Alpine Cs are -- well, we call them Alpine C, 11 they're not actually connected between Mitre and 12 Lookout. 13 COMMISSIONER FOERSTER: So would there be a 14 potential for some more down to oil south of Mitre? 15 MS. DOHERTY: That's possible. It just depends 16 on what the structure looks like that. I guess I'm not 17 prepared to answer that question, I don't have the 18 structure map right here. 19 COMMISSIONER FOERSTER: I was just curious..... 20 MS. DOHERTY: Yeah. 21 COMMISSIONER FOERSTER: .....it's not an answer 22 -- not a question you have to worry about. 23 MS. DOHERTY: Our lowest known oil is at the 24 Lookout 1 well, it's the deepest penetration that we 25 have. And so the structure does (indiscernible) Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net UfferK! 4/3/2018 ITMO: APPLICATIONS OF CONOCOPHILLIPS AK Docket No. CO 18-001 &AI018-013 Page 33 1 further down depth from the Lookout. And however far 2 those sands actually end up being, we'll know from -- 3 from the wells down here where that edge thins out to 4 because there is some uncertainty on the interpretation 5 as you move around the edges of the container just 6 because the sands too thin and they become harder to 7 resolve on seismic. 8 MR. COOKSON: This is John Cookson again and 9 we're on slide number 12. And this slide speaks to 10 injection fluid containment. We're requesting a rule 11 similar to the Alpine oil pool for an allowable 12 injection gradient of .81 psi per foot. That pool -- 13 that rule was established about a year ago in a hearing 14 here for the Alpine pool. Jen just testified as to the 15 thick confining layer here at Lookout, somewhat thicker 16 than at Alpine I believe. And at Alpine the historical 17 performance indicates containment of injection fluids 18 so by analogy we expect to see that at Lookout. We've 19 done some detailed modeling and that also indicates the 20 injected fluids will be detained in the pool interval. 21 We perform that using GOHFER frac model which 22 is -- there's a number of industry frac models, this is 23 the one that we use frequently in-house. We built this 24 model with an Earth model based on the Lookout number 2 25 well with fracture gradients ranging from .85 psi per Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net AOGCC 4/3/2018 ITMO: APPLICATIONS OF CONOCOPHILLIPS AK Docket No. CO 18-001 & A1018-013 Page 34 1 foot in the confining layers down to .65 psi per foot 2 in the brittle Alpine C pay interval -- pool interval. 3 This model uses a vertical well model. we injected 4 water at a very high rate -- we had to inject water at 5 a high rate to get the pressure to increase in the 6 sand, in such a permeable sand so we had to -- we 7 injected water at 43,000 barrels of water per day to 8 get the pressure in the sand up to that .81 psi per 9 foot that we're asking for. And at that pressure it 10 did generate of course a fracture and that fracture is 11 (indiscernible) to be contained within the -- the pool 12 interval. 13 As far as our injection pressures out there, 14 our maximum expected water injection pressure at the 15 surface is 2,650 psi. If you take that down to bottom 16 hole in the reservoir at 7,825 tvd, that's about a mid 17 point in the reservoir, the bottom hole pressure will 18 be 6,171 psi which is a .79 psi per foot gradient. The 19 point being that under -- near maximum expected 20 injection pressures we don't have the capacity even to 21 reach that .81. With gas the pressures are lower. 22 It's higher at surface at 4,000 psi, but by the time 23 you get to the bottom hole it's a lower pressure 24 because gas is less dense than water so it's lighter so 25 it's actually -- you can see it's 800 pounds lighter, Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net AOGCC 4/3/2018 ITMO: APPLICATIONS OF CONOCOPHILLIPS AK Docket No. CO 18-001 & A1018-013 Page 35 1 5,200 psi. And again that's below that .81 psi per 2 foot. 3 This takes us now to the confidential data. 4 CHAIR FRENCH: All right. Why don't we take a 5 five minute break, we'll clear the room of..... 6 COMMISSIONER FOERSTER: Before we do that we 7 need to make a determination that we are willing to 8 accept it as confidential data. So we -- what we need 9 from you is a brief description of what the 10 confidential data is so that the people that get kicked 11 out of the room can still follow the logic of where 12 we're going in our conversation and so that we can make 13 a decision as to whether hold it confidential or not. 14 What that looks like is we want to show you a -- an 15 isopack that was based solely on our seismic and we 16 want to show you the -- you know, what I'm saying..... 17 MR. COOKSON: Yes. 18 COMMISSIONER FOERSTER: .....we just want a 19 description. 20 MR. COOKSON: Yes, you did a good job of 21 explaining it. And actually it's the -- you're 22 correct, it's a -- we have seismic here, we have a 23 seismic cross section, we show our interpretative 24 techniques that we use, we show the interpretation of 25 the seismic and describe that. And we show a net pay Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax 907-243-1473 Email: sahile@gci.net AOGCC 4/3/2018 ITMO: APPLICATIONS OF CONOCOPHILLIPS AK Docket No. CO 18-001 &A1018-013 Page 36 1 map that is based on that seismic. 2 COMMISSIONER SEAMOUNT: I'm wondering though if 3 we -- do we need to see this information in order to 4 make a decision. Do any of the Commissioners have an 5 opinion on that, I only see two slides here and we've 6 already seen a map that shows relative thicknesses. 7 What does the staff think. 8 CHAIR FRENCH: Five minute break? 9 COMMISSIONER FOERSTER: Five minute break. 10 CHAIR FRENCH: Why don't we take about a five 11 minute break and we'll analyze that question about what 12 we need here and then we'll come back and let you know. 13 So we'll be in recess for about five minutes. 14 (Off record) 15 (On record) 16 CHAIR FRENCH: .....on the record and the 17 Commission has looked at the confidential material that 18 was proffered. The staff does not believe and the 19 Commission does not believe we need that to make a 20 decision on the pool rules. So the confidential 21 material's been returned to ConocoPhillips and we'll 22 proceed without it. 23 COMMISSIONER SEAMOUNT: Though it is very 24 interesting. 25 MR. VERSTEEG: Okay. So this is Joe Versteeg Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Arch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net AOGCC 4/3/2018 ITMO: APPLICATIONS OF CONOCOPHILLIPS AK Docket No. CO 18-001 & A1018-013 Page 37 1 and we are on slide 14. And we'll just have a brief 2 overview of some of the reservoir properties and rock 3 properties and discuss the reservoir performance a 4 little bit. 5 So the initial pressure was just under 3,800 6 pounds at 3,770, 176 degrees and our bubble point 7 pressure is -- was measured at 3,237 so we're in an 8 under -saturated reservoir. Have a very high formation 9 volume factor, nice oil density and viscosity. And 10 with these favorable properties we're expecting very 11 good water flood performance. So that's really the 12 message from the properties. 13 As far as our oil in place volumes at the 14 bottom of the slide, we have a low, medium and high 15 case. You can see the volumes on the slide, 70, 80 and 16 150 million barrels in place. I expect that if we were 17 to just go off primary recovery without secondary or 18 tertiary flooding, we'd expect about 20 percent. And 19 so those -- the numbers to the right of that reflect 20 the low, medium and high volume recoveries for that 21 case, just the 20 percent case. So we know that 22 there's a very nice benefit to water flooding and we 23 think we can get up to -- with strictly water flooding 24 without the gas flood, we can get up to around 45 25 percent total recovery and that's what the numbers to Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Arch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net AOGCC 4/3/2018 ITMO: APPLICATIONS OF CONOCOPHILLIPS AK DocketNo. CO 18-001 & A101 8-013 Page 38 1 the right reflect there, a little more than doubling 2 the primary recovery. And then the last line is 3 showing our ultimate recovery with our EWAG flood so 4 alternating our water flood with gas -- slugs of gas as 5 we do in the rest of the Alpine field and the estimated 6 incremental recovery we expect from that. So we have 7 good analogs to show that we should expect to get 8 somewhere close to 60 percent. 9 This is a brief -- I'm sorry, we're on slide 10 15. This is just a brief summary of the UR performance 11 we expect. And this is - it's a simulated slim tube. 12 So slim tube is an experiment, but this was actually 13 simulation because we did not have the experimental 14 data. So you can see on the Y axis the recovery from 15 the slim tube experiment and the pore volume injected 16 on the X axis. And so we're just injecting gas in this 17 experiment and trying to -- you really don't want to 18 use the absolute values of recovery, but really trying 19 to get a relative sense of what different levels of 20 enrichment, how that benefits your recovery. And 21 enrichment is basically adding some of your 22 intermediate components to your lean gas to make the 23 gas that you inject potentially improve the qualities 24 of your oil that's in place. So you're -- basically 25 with enrichment you're adding more intermediate Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK99501 Fax: 907-243-1473 Email: sahile@gci.net AOGCC 4/3/2018 ITMO: APPLICATIONS OF CONOCOPHILLIPS AK Docket No. CO 18-001 &A1018-013 Page 39 1 components. So we're just showing the percentages of 2 enrichment down there on the scale below and you can 3 see what the affect of the 10, 15 and 20 percent 4 enrichment and what our current blend is, that's the 5 red line. 6 And then the last summary slide on the 7 reservoir section is to just have a quick overview of 8 the -- what we expect from the peak rates. As I 9 mentioned with expect nice water flood performance and 10 some favorable initial rates so we're expecting 20 to 11 30,000 barrels a day range on the initial production. 12 Again this is an annualized peak rate. A range of 20 13 to 50 million in gas. The water production of course 14 that'll come later in the life as the water flood 15 matures. So but that provides the range on what we 16 expect late in life on the water production based on 17 our simulation results. And then the lift gas demand 18 that we expect. 19 On the injection side we expect a peak of 20 anywhere from 25 to 40,000 barrels of water. And on 21 the EWAG gas flood, it just depends on how many 22 injectors we have simultaneously on at one time on gas 23 because it is an alternating flood. But it would get 24 anywhere from 20 to 20 million per day as a peak rate 25 is what we're expecting. Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net AOGCC 4/3/2018 ITMO: APPLICATIONS OF CONOCOPHILLIPS AK Docket No. CO 18-001 & A1018-013 Page 40 1 And the line at the time at the bottom there, 2 we are requesting the waiver as noted related to 3 gas/oil ratio limits. So that's as stated on the 4 slide. 5 COMMISSIONER SEAMOUNT: I had a question, Mr. 6 Versteeg, we don't have to go back to it, but on the 7 map it shows in the northeast there's a little blob out 8 there that is to the northeast of -- the farthest 9 northeast wellbore penetration. What -- do you have an 10 idea of what percentage of recoverable oil will be 11 produced from that little blob up there, any of it or 12 very small percentage or..... 13 MR. VERSTEEG: I'm not prepared to give you an 14 exact number on that, but it should be a smaller 15 percentage because we thin out in the northern section. 16 And I'll let Jennifer respond on sort of the net 17 thickness out in that area, but it would be a smaller 18 proportion of the total recovery. 19 COMMISSIONER SEAMOUNT: But you will get some 20 out of there? 21 MR. VERSTEEG: Yes. 22 COMMISSIONER SEAMOUNT: Okay. So you might 23 have some banked oil up in there. 24 MS. DOHERTY: (Indiscernible - away from 25 microphone) sorry. This is Jennifer Doherty. Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Arch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net AOGCC 4/3/2018 ITMO: APPLICATIONS OF CONOCOPHILLIPS AK Docket No. CO 18-001 &A 1018-013 Page 41 1 Depending on what we see toward the end of that last 2 well when we drill it, it is the last well that we'll 3 drill in our current nine well campaign. There's 4 always a possibility of future development up in that 5 area. It'll just have to compete with other resources 6 and because we only are putting in nine slots currently 7 and we're going to drill all those nine slots on the 8 pad, while there is space to put in more it would have 9 to justify it's..... 10 COMMISSIONER SEAMOUNT: Okay. 11 MR. NOEL: Okay. This is Brian Noel, we're 12 currently on slide 17 and I'll walk through the 13 drilling plans with the next few slides. 14 As you've already seen we're about eight miles 15 further from the CD5 pad, we're currently drilling the 16 first well and our drilling support continues to be 17 primarily from the CD1 pad at Alpine field. The next 18 few lines show you the depth of the production casing 19 and the horizontal lengths, total well departures, 20 these are all measured footages. And you can see the 21 spider map over there on the right-hand side and the 22 horizontal lines and you can also see where the 23 production casing sits if you look at the lower end of 24 the horizontal line, that little tick mark is where the 25 production casing went in. Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK99501 Fax: 907-243-1473 Email: sahile@gci.net AOGCC 4/3/2018 ITMO: APPLICATIONS OF CONOCOPHILLIPS AK Docket No. CO 18-001 & A1018-013 Page 42 1 So these are all directionally drilled wells 2 from the MT6 pad, we'll collect surveys and log data, 3 it'll all be (indiscernible) transmitted while we drill 4 the wells. We're using the typical North Slope muds 5 that we've used in the other fields, they're water 6 based muds for the surface, intermediate holes and then 7 a special drilling fluid to avoid damaging the 8 reservoir. The producers are mineral oil based and the 9 injectors will be a water based drilling fluid. 10 we'll construct these wells to be candidates 11 for annular disposal to allow us to dispose of mud and 12 cuttings here on the pad and we also have a class I 13 disposal well back on CD1 that can take mud and 14 cuttings. 15 The well designs are very similar to what we've 16 been using there in Alpine proper. The key difference 17 out here is the lower part of the overburden, the Fish 18 Creek slumps and the Miluveach shale that's proven to 19 be unstable in the exploration wells and very hard to 20 drill a hole and keep it open long enough to run casing 21 back through it. So that's our biggest challenge to 22 get to the reservoir and to help with that we are going 23 to use steerable drilling liner and also managed 24 pressured drilling to try and manage the 25 (indiscernible) of shales. Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net AOGCC 4/3/2018 ITMO: APPLICATIONS OF CONOCOPHILLIPS AK Docket No. CO 18-001 & A1018-013 Page 43 1 And moving on to slide 18, it breaks the well 2 down into the individual components of the well 3 construction. We start with a 20 inch insulated 4 conductor with thermo-siphons and the design there is 5 to try and keep that top 50 to 60 feet of the 6 permafrost frozen and help mitigate subsidence down the 7 road. So we installed a diverter onto the conductor 8 and driller surface hole, we're slightly larger casing 9 program than what we've been using on CD5. We drill a 10 16 inch hole and run 13 and three-eighths inch surface 11 casing. That's fully cemented back to surface. Once 12 that operation's complete we install the BOP, then we 13 pressure test the whole system, the blowout prevention 14 equipment as well as the casing. 15 From there we drill out that surface casing 16 shoe and conduct a formation integrity test. And then 17 we would drill ahead in the intermediate hole down to 18 the top of the Fish Creek slumps or the HRZ shales. 19 That's a 12 and a quarter inch hole section. Once that 20 interval's complete we would run nine and five-eighths 21 inch casing back to surface. We don't anticipate any 22 hydrocarbon bearing zones in this interval so we'll 23 cement the shoe with the appropriate -- per the 24 appropriate regulations. If we would encounter any 25 type of sand with hydrocarbons we can either bring the Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net AOGCC 4/3/2018 ITMO: APPLICATIONS OF CONOCOPHILLIPS AK Docket No. CO 18-001 & A1018-013 Page 44 1 cement column higher and/or run a stage (ph) tool to 2 cover those shallow zones. 3 COMMISSIONER FOERSTER: Are you going to log 4 that section? 5 MR. NOEL: Yes, we'll be logging it. 6 Once that casing shoe is cemented in place then 7 we do a second pump in test between the nine and five - 8 eighths, the 13 and three-eighths to find if we can 9 pump into that outer annulus at lower pressures than 10 the surface casing shoe test which would be one of the 11 components of the annular disposal criteria to permit 12 the well. And prior to drilling ahead we pressure the 13 inside of the nine and five-eighths casing, we drill 14 out 20 or so feet, conduct another formation integrity 15 test and then this is the interval we're calling the 16 pipe and bait section through the problem shales. So 17 we actually pick up the seven inch liner, then we pick 18 up an inner string which has our drilling assembly and 19 logging tools that stick out the end. And then we run 20 that at the bottom, we drill ahead and essentially 21 we're taking the pipe with us and lining hole as we 22 drill ahead. Once we reach the TD within the reservoir 23 sand we pull that inner string and drilling assembly 24 out, turn around and run back in and pump cement on 25 that seven inch liner. Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net AOGCC 4/3/2018 ITMO: APPLICATIONS OF CONOCOPHILLIPS AK Docket No. CO 18-001 & A1018-013 Page 45 1 As with the other prior casing intervals we do 2 another pressure test, show integrity internally then 3 drill out, do another formation, integrity test within 4 the reservoir's sand and then we would directionally 5 drill the horizontal that you've already seen shown on 6 the maps. And then once that's complete we run the 7 liner I described earlier. It's solid pipe, we run 8 perforated pub joints, they're five feet long pieces of 9 pipe with holes drilled to give us inflow into the 10 liner. Those are about every 300 feet. We run that 11 out in the open hole and then hang it off with a liner, 12 top hanger and packer. And then run our production 13 tubing which stings into the top of that. It's a four 14 and a half inch liner, four and a half inch tubing. 15 The producers will have a downhole pressure 16 gauge permanently installed so we'll have continual 17 readings of the pressure right there above the liner 18 top packer on the producers. They're gas lifted 19 producers and the injectors will have a very similar 20 completion that I've just described. We won't have the 21 downhole gauge, but we will also have the Nipaluk 22 Shallow (ph) to put an injection valve into. Given 23 that we're not near any water bodies or the ocean or 24 off shoreway, there's no plans to or regulatory 25 requirements to run the subsurface safety valves 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 4/3/2018 ITMO: APPLICATIONS OF CONOCOPHILLIPS AK Docket No. CO 18-001 & A1018-013 Page 46 1 these completions on the producers. And then our 2 wellhead is similar to what we've used on the other 3 drillsites in the western North Slope and it's a 4 horizontal tree so that surface safety valve and the 5 master valve flows out the side of the wellhead instead 6 out the top. 7 And we -- we're requesting one waiver given 8 that the directional pads and the high inclination 9 where that seven inch liner is set in the reservoir, 10 we'd like on the injectors to bring the production 11 packer more than 200 feet above the injection zone so 12 we can keep wireline access down to that packer. That 13 packer's still being set within the confining layer 14 above the sand and it's also be set in cemented pipe. 15 And then once that packer's placed we -- we do the 16 mechanical integrity test of the inner annulus as well 17 as the tubing. 18 And then for the area injection order one of 19 the criteria was mechanical conditioning existing 20 wells. 21 COMMISSIONER FOERSTER: You're on slide 19? 22 MR. NOEL: Yes. Sorry. Slide 19. There are 23 two wells that penetrate the pool as you've seen on the 24 cross sections, Lookout number 1 and Lookout number 2. 25 Lookout number 1 was a well that was suspended with Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Arch. AK99501 Fax: 907-243-1473 Email: sahile@gci.net AOGCC 4/3/2018 ITMO: APPLICATIONS OF CONOCOPHILLIPS AK Docket No. CO 18-001 & A1018-013 Page 47 1 downhole tubing plugs, kill weight fluid, back pressure 2 valve. It's on a five year inspection cycle, we were 3 last out there in 2015, everything was in good shape. 4 And Lookout number 2 after the well was completed and 5 tested it was fully P&A'd back in 2002. 6 COMMISSIONER FOERSTER: Do you have any -- what 7 are your future plans for Lookout number 1? 8 MR. NOEL: We're keeping it at the moment for 9 an observation well since it's right there in the 10 middle of the reservoir. And one we have the -- now 11 that we have the road and pad out there, you know, the 12 P&A is much easier than it would be if we had to go out 13 across the tundra with isohoods (ph). 14 There's one other well that's close by as 15 you've seen, Mitre, it's not in the pool, but that one 16 was fully abandoned back in 2002 also. 17 And then moving on to slide number 20. We are 18 requesting a finding that there are no freshwater 19 aquifers in the Lookout area. And that would help us 20 with the area injection order as well as permitting 21 every dedicated injection well for the reservoir itself 22 as well as future annular disposal sundries. 23 And with that I'll turn it back to Jenny to 24 walk you through the geology and the log analysis that 25 was done to show that we have no freshwater aquifers 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 1 this area. 4/3/2018 ITMO: APPLICATIONS OF CONOCOPHILLIPS AK Docket No. CO 18-001 & A1018-013 2 COMMISSIONER SEAMOUNT: Mr. Noel, I spent years 3 working on drilling locations with drilling engineers 4 and I notice you're both a geologist and a drilling 5 engineer. Does that leave you conflicted in any way? 6 COMMISSIONER FOERSTER: Do you get rude -- are 7 you rude to yourself is what he's saying. 8 MR. NOEL: No, because I understand both sides 9 I'm a more polite drilling engineer. So I have a very 10 good working relationship with our geologist. 11 MS. DOHERTY: This is Jennifer Doherty, we're 12 on slide 21. This is the Lookout area type log that 13 shows the shallow salinity analysis that was performed 14 by our petrophysicist at ConocoPhillips. Just to cover 15 the slide from the section from top to bottom, the 16 shallowest sand section that -- or the shallowest 17 section that we have in the Lookout area are the Prince 18 Creek sands. There really isn't very much sand left, 19 most of the upper Prince Creek sands have actually been 20 eroded at the surface. So mostly we're left with the 21 lower portion of the Prince Creek sands which are kind 22 of little sand stringers with silts and shales. Base 23 of permafrost is at about 1,100 feet in the Lookout 24 area. 25 And then we go into the Colville group which Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Arch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net AOGCC 4/3/2018 ITMO: APPLICATIONS OF CONOCOPHILLIPS AK Docket No. CO 18-001 & A1018-013 Page 49 1 are clays with interbedded silt and minor sands. 2 There's two zones in the Colville group that possibly 3 have sands within them. Those are the C40 and the C30. 4 The calculated water salinities in those zones are 5 31,000 PPM and 27,000 PPM respectively. 6 The next section that does have sand present in 7 the area is the Nanushuk group and that in this area is 8 the K3 down to the Albian 95. These are the top sets, 9 the shallow marine silts and shales with some thin, 10 fine grained sands. Calculated water saturations in 11 those zones range from 13,000 to 14,000 in the K3 and 12 16,000 is the highest and that's in the Albian 95 13 sands. 14 Below that we have the Torok, those are Albian 15 slope and deep marine shales with interbedded sands. 16 And those are the Albian 94 and 93 section that have 17 13,000 and 17,000 ppm calculated salinities. 18 Below that come our seals, the HRZ, Kalubik, 19 Miluveach, that's our -- the top seal and then the 20 Alpine C obviously is the target. 21 So these are the sands that we have in the 22 general Greater Mooses Tooth area and the water 23 saturations that we calculated where we have sands 24 present that are of good porosity and clean enough to 25 be -- to have a valid calculation. Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Arch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net AOGCC 4/3/2018 ITMO: APPLICATIONS OF CONOCOPHILLIPS AK Docket No. CO 18-001 & A1018-013 Page 50 1 COMMISSIONER FOERSTER: So have you encountered 2 any shallow gas hazards or do you have any likelihood 3 of any? 4 MS. DOHERTY: There's always the possibility of 5 seeing hydrocarbons in the Nanushuk. Obviously that's 6 a very interesting play right now. We haven't seen 7 anything in any of ours as of yet that indicate that 8 there's anything there. And mostly, you know, there's -- 9 you have to have two obviously, you have to have some 10 -- you actually have to have some sand. And as you can 11 see in the Lookout wells there's not really very well 12 developed sands in those zones in this area. 13 COMMISSIONER FOERSTER: But nothing shallow 14 (indiscernible - away from microphone)..... 15 MS. DOHERTY: So we're setting our surface 16 casing in this -- right at the base of the C40. So 17 everything from the C30 all the way down to the shales, 18 the top of the shales, are going to be in our first 19 intermediate. 20 COMMISSIONER FOERSTER: So as far as the 21 shallow hazard that you're worried about (indiscernible 22 - away from microphone)..... 23 MS. DOHERTY: No, there really aren't any sands 24 presents. The only sands that we do have are in the 125 Prince Creek and those are actually up in the Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net AOGCC 4/3/2018 ITMO: APPLICATIONS OF CONOCOPHILLIPS AK Docket No. CO 18-001 & A1018-013 Page 51 1 permafrost and they're frozen. So, yeah, we haven't 2 seen anything. 3 COMMISSIONER FOERSTER: Thank you. 4 COMMISSIONER SEAMOUNT: What's your -- what's 5 your calculated water saturation of the -- of the 6 Lookout sands, this Alpine sands, if that's not 7 confidential? 8 MS. DOHERTY: So the average that we calculate 9 in the pay sands at Lookout 1 was the 16 and a half 10 percent and 11 COMMISSIONER SEAMOUNT: Wow. 12 MS. DOHERTY: .....and it was 30 percent in the 13 Lookout 2 well average. And really that just comes 14 down to where -- what we're using as our cutoffs..... 15 COMMISSIONER SEAMOUNT: Right. 16 MS. DOHERTY: .....and we're including more of 17 the lower quality sands in Lookout 2, they're still 18 pay, they do have a higher water saturation that drives 19 that average up just a little bit. But it is 20 relatively low, we don't have any free water in 21 Lookout. 22 So the next slide is slide 20 [sic], this is 23 just showing the interval that we would propose to use 24 for the annular disposal if any of our wells qualified 25 for that. Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net AOGCC 4/3/2018 ITMO: APPLICATIONS OF CONOCOPHILLIPS AK Docket No. CO 18-001 & A1018-013 Page 52 1 COMMISSIONER FOERSTER: Slide 22? 2 MS. DOHERTY: Slide 22, yes. And so this just 3 shows the correlation from the Nuiqsut 1 that sits over 4 at CD5 where we're currently using the annular disposal 5 into the C30 interval. And so that -- this slide just 6 shows that that interval, the C30, does correlate and 7 continue as you move out west into the MT6 pad you can 8 see it in Lookout 2 and in Mitre as that yellow zone. 9 And then also to show the mudstone barrier which sits 10 atop that in the C50 interval. And that entire 11 interval that we would be -- that we would call our 12 mudstone barrier is below the permafrost. 13 And so again, I've noted it before, but we're 14 setting our development wells, we're currently setting 15 our casing around that 2,000 feet in the shale of the 16 C40 below that sand. So we'll be setting it right on 17 top of the C30. 18 MR. COOKSON: Okay. My name's John Cookson and 19 we're on slide 23 on a little bit of a different 20 subject. We'll talk about the Lookout facilities in 21 the hearing. So from the -- I'll start with -- here at 22 the production wells. Like at CD5 the production wells 23 can flow either to a test separator or on to 24 production, but at Lookout the difference is we have 25 this three phase separator that allows the separation Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK99501 Fax: 907-243-1473 Email: sahile@gci.net AOGCC 4/3/2018 IT'MO: APPLICATIONS OF CONOCOPHILLIPS AK Docket No. CO I8-001 & A1018-013 Page 53 1 of the oil, gas and water so that we can precisely 2 measure the oil and gas and water for custody transfer. 3 The products are re -co -mingled into a 20 inch 4 production pipeline and sent over to the Alpine central 5 facility. Production is combined there with Colville 6 River unit production and processed. The oil goes to 7 the Alpine pipeline. Return products include seawater, 8 it will at least initially be seawater, that's our 9 immediate plans for the future to affect seawater. 10 That's a 14 inch pipeline. We will receive enriched 11 gas for injection and that was described previously. 12 This is the same enriched gas that goes to other 13 Coleville River unit drillsites. We will receive dry 14 gas and that's used for gas lift and fuel gas back at 15 the drillsite. The dry gas and the enriched gas are 16 measured for custody transfer at the CD5 drillsite. 17 COMMISSIONER FOERSTER: What type of custody 18 transfer do you intend to you, standard? 19 MR. COOKSON: These are standard. So the dry 20 gas pipelines are AGA orifice meters. The oil and 21 water meters off of the three phase separator, those 22 are Coriolis meters. The gas meter off the three phase 23 separator is a AGA orifice meter. 24 COMMISSIONER FOERSTER: Don't forget to get 25 your metering approved. Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net AOGCC 4/3/2018 ITMO: APPLICATIONS OF CONOCOPHILLIPS AK Docket No. CO 18-001 & A1018-013 Page 54 1 MR. COOKSON: Yes. Yes, that's ongoing. I -- 2 we..... 3 And this is the final slide for today, it 4 addresses fluid compatibility. This is slide 24. We 5 believe that the -- both the produced and the injected 6 fluids between the Lookout oil pool and the CRU oil 7 pools should be expected and it is expected. So that 8 means that when the Lookout oil pool -- the production 9 from Lookout goes to CRU it won't cause any trouble 10 with CRU pools, it won't cause any trouble with the 11 processing. Any CRU fluids that come back to Lookout, 12 and that could be -- well, that's the enriched gas and 13 it could at some point in the distant future be 14 produced water. We don't think that will cause any 15 trouble with Lookout. And the reason for this is 16 simply analogy. The Lookout production compositions 17 are expected to be similar to the Alpine pool. And the 18 Lookout is also a very close analog to the Alpine pool 19 and both of those pools share a similar geologic 20 history, same oil charge, lower Kingak, and the same 21 rock deposition source as the Alpine A. So in summary 22 we're not expecting any problems. 23 Lookout will be operated similar to the CRU 24 pools, we'll use the same type of scale inhibitors, 25 corrosion inhibitors, standard treatments. Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net AOGCC 4/3/2018 ITMO: APPLICATIONS OF CONOCOPHILLIPS AK Docket No. CO 18-001 & A1018-013 Page 55 1 CHAIR FRENCH: So just a quick operations 2 question, Mr. Cookson. You're going to start off with 3 seawater for injection, but you think that you'll 4 transition over to produced water at some time in the 5 future? 6 MR. COOKSON: I'm not sure. I wouldn't say 7 that I think that we will, that's a possibility and we 8 leave that open. It was in the -- you know, we have 9 that list of possible fluids to inject, we included 10 both. 11 CHAIR FRENCH: Okay. But does..... 12 MR. COOKSON: Just for completeness. For 13 completeness so that when that does happen we don't 14 have to come back..... 15 CHAIR FRENCH: Sure. 16 MR. COOKSON: .....here and ask..... 17 CHAIR FRENCH: Sure. 18 MR. COOKSON: .....you guys for permission. 19 CHAIR FRENCH: Thank you. 20 MR. COOKSON: That concludes our testimony for 21 today..... 22 CHAIR FRENCH: Excellent. 23 MR. COOKSON: .....or our prepared testimony. 24 CHAIR FRENCH: Prepared testimony. Excellent. 25 Take a break or ask questions 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 4/3/2018 ITMO: APPLICATIONS OF CONOCOPHILLIPS AK Docket No. CO I8-001 &A1018-013 Page 56 1 COMMISSIONER FOERSTER: I don't know that we 2 need to take a break. 3 CHAIR FRENCH: We're good. Commissioner 4 Seamount. 5 COMMISSIONER FOERSTER: I have..... 6 COMMISSIONER SEAMOUNT: I think that was very, 7 very complete and excellent testimony. 8 COMMISSIONER FOERSTER: Well, and I'll add to 9 that that our staff was very complimentary on the 10 thoroughness or your submission and the completeness 11 and promptness of the answer that you gave to the 12 questions I asked. And I personally appreciate when 13 you identify the slides that you're talking from 14 because it does leave a record that's easy to follow 15 when people come back later and try to read the 16 transcript and reconcile it with the slides. 17 So thank you for Conoco's..... 18 MR. COOKSON: Thank you again. 19 COMMISSIONER FOERSTER: .....usual good job. 20 MR. COOKSON: Yeah, thank the Commission again. 21 And so similarly just a shout out to the AOGCC staff. 22 Similarly we had questions and we don't know how to do 23 some things and they were very prompt and got right 24 back with us. So a lot -- we received a lot of help 25 from them. Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net AOGCC 4/3/2018 ITMO: APPLICATIONS OF CONOCOPHILLIPS AK Docket No. CO I8-001 & A1018-013 Page 57 1 COMMISSIONER FOERSTER: And I'll reiterate what 2 I said earlier that it is our intent to while doing our 3 jobs correctly not to be an unnecessary burden to you 4 guys. And if we ever become such or in our efforts to 5 overlap with the BLM there are problems that are 6 reconcilable we really hope that you bring them 7 respectfully to us and allow us to attempt to address 8 them. 9 MR. COOKSON: Yeah. Thank you. This is -- 10 this will be new for all of us, right, and we haven't 11 done this yet so we'll see here. It's very exciting 12 times, we're -- you know, production's coming up here 13 pretty quick and we're just getting all the details 14 worked out of how we're going to live with this, how 15 we're going to live with both agencies and it'll be 16 learnings by all of us I would imagine. 17 COMMISSIONER FOERSTER: Well, I think I -- I'm 18 going to speak for Dan when I say that for old timers 19 who have been here when the technology was a lot more 20 elementary, it's kind of exciting to see what we're 21 able to do these days. I used to visit with my father - 22 in-law who was a retired engineer with Exxon and tell 23 him all the new things that were coming down the pipe 24 and that was 10 years ago that he died. And so every 25 -- when I listen to things I think gosh, sure would be Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net AOOCC 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 4/3/2018 ITMO: APPLICATIONS OF CONOCOPHILLIPS AK Docket No. CO 18-001 & A1018-013 Page 58 nice to tell Leroy about this. COMMISSIONER SEAMOUNT: I remember when a well was -- if a well deviated more than 15 percent people got fired. But you guys have got a good looking oil field out there. COMMISSIONER FOERSTER: Yeah. Thank you. CHAIR FRENCH: Good observation to end on. With that we will adjourn. Thank you so much. (Hearing adjourned 11:26 a.m.) (END OF REQUESTED PORTION) Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net AOGCC 4/3/2018 ITMO: APPLICATIONS OF CONOCOPHILLIPS AK Docket No.CO 18-001 &AI018-013 Page 591 1 C E R T I F I C A T E 2 UNITED STATES OF AMERICA ) )ss 3 STATE OF ALASKA ) 4 I, Salena A. Hile, Notary Public in and for the 5 State of Alaska, residing in Anchorage in said state, 6 do hereby certify that the foregoing matter in Docket 7 No. CO 18-001; AIO 18-013 was transcribed to the best 8 of our ability; 9 IN WITNESS WHEREOF I have hereunto set my hand 10 and affixed my seal this 10th day of April 2018. 11 12 Salena A. Hile 13 Notary Public, State of Alaska My Commission Expires: 09/16/2018 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: sahile@gci.net ConocoPhillips Lookout Pool Hearing Conservation & NO Orders April 3, 2018 Mr. John Cookson • ConocoPhillips, Alaska, Inc • Production Engineer • BS and MS Petroleum Engineering, Colorado School of Mines • 32 years industry experience, 16 years in Alaska working Kuparuk, Prudhoe, Point Thomson and Alpine fields • Expert Witness: Production Engineering Mr. Brian Noel • ConocoPhillips, Alaska, Inc • Drilling Engineer • BS Geology, University of Illinois • BS Petroleum Engineering, University of Wyoming • Licensed Professional Engineer, Alaska • 37 years industry experience, 27 years in Alaska working Cook Inlet and North Slope fields • Expert Witness: Drilling Engineering Mrs. Jennifer Doherty • ConocoPhillips, Alaska, Inc • Development Geologist • BS Geology—James Madison University • MS Geology — University Texas, Austin • 18 years industry experience, 11 years in Alaska working Kuparuk and Alpine fields • Expert Witness: Geology Mr. Joe Versteeg • ConocoPhillips, Alaska, Inc • Reservoir Engineer • BS Petroleum Engineering, University of Alaska -Fairbanks • 21 years industry experience, 18 years in Alaska working Kuparuk, Prudhoe, and Alpine fields • Expert Witness: Reservoir Engineering ConoAF` hillips • Project Overview (John Cookson) • Location • Ownership, pool boundary, notification • Exploration and delineation history • Development Plan • Geology (Jennifer Doherty and John Cookson) • Lookout Pool Interval • Geologic Properties •Rock properties, contacts, lithology, structure, traps, seals, faulting • Injection Containment • Alpine C Seismic and Isochore Interpretation (Confidential) • Reservoir (Joe Versteeg) • Fluid Properties, OOIP and Resource Recovery • Simulated Recovery versus PV Gas Injection • Production and Injection Rates • Well Construction (Brian Noel and Jennifer Doherty) • Drilling Plan • Well Design & Integrity • Existing Wells • Annular Disposal • Shallow Interval Geology • Shallow Interval Salinity • Production (John Cookson) • Facilities and Metering • Fluid Compatibility ConocoPhillips • Exploration Well SHL — Development Weil - ❑ Proposed Lookout PA ■ Road or Pad Pipeline CIAK Unit N A T I O N A L P E T R O L E U M R E S E R V E - A L A S K A \\��N r 11ne c Central Colc'i C\D2\\\\ 'ties River 1CDI Lookout PA Boundary ' . MT6 Pad I GMT1 Project 0 2° Q , D aye • Q�° aac Q Greater ��ti�o°cc°p Mooses Tooth Unit GMT2 iiQ� c CD4 1 ConocoPhillips Alaska Greater Mooses ToothUnit N and Colville River Unit Roads, Pads, & Pipelines 0 1 2 6000ME:= Mlles 3/20/2018 conoc. F;hillips Working Interest Owners: • 78% ConocoPhillips (Operator) • 22% Anadarko* Surface Owners: • Kuukpik • BLM Subsurface Owners: • ASRC • BLM Notification to BLM and Kuukpik per 20 AAC 25.402(c)(2) on 2-29-2015 Proposed Lookout Pool Boundary: • Includes each full section intersected by reservoir outline except for Mitre 1 section (no pay) *Sale of Anadarko leasehold to ConocoPhillips is pending government approval T12NR2E k f 1 I NR2E k ; r -- i �— I Greater Mooses Tooth Unit EA 0 17 W ,IJ NEEN,_ NIM olc /N _... I 0 0.5 1 L5 2 43 Miles Colvill River - Unit MT6WeIIPed Q Proposed LwkW Gil Pod Boundary Q Lookoul Reservoir CApprovedl Lwkmt PaMdpeling Arca ® Kuukpik Sudeca ASRC Subsurface - GMTU Treds L..i Unil BcuMeries CPAI Leases ConocoPhillips Alaska Proposed Lookout Oil Pool Area t@52618 k ConocoPhillips 1993, '95, '96 2D Seismic Acquisition in NE W NPR -A 1998 —2000 3D Seismic Acquisition 2001-2002 Drilled Lookout 1 & 2 and Mitre 1 & 1PB1 2008 GMTU Formed 2009 GMTU 1St Expansion B AA081801 -- Greater 2015 CD5 / West Alpine Development Mooses Tooth Unl 2015 GMT1/ Lookout Seismic Miles Acquisition 2016-2017 GMT1 1st Construction Season, GMT2 3D Seismic Acquisition Current -Final installation of drillsite facilities and pipelines 15A' -First well, MT6-03 spud on AA061802 March 21, 2018 -First production (two wells) and injection (one well) targeted in Q4, 2018. 2018 - mid 2019 Complete 9 -well drilling program AAov4ar r. I C 9A AA0811 i6A W W ~ ~- AA081801 -- N 1c 0 0.5 1 L5 2 Miles I 1942 3A 511. AAG ]]46 colvili '51' -- River Unit *'1 MT6 Well Pad Q Proposed Lookout Oil Pool Bouodary Q Lookout Reservoir - Q Proposed Lookout Padiapatiog Area ® Kuukpik Sudace ASRC Subsurfeco GMTU Tracts Unll Bowderles �.,. CPAI Leases Proposed Lookout Oil Pool Area J2ul2uld ConocoPhiilips Wells: • 4 Producers and 5 injectors • 2 Multi -laterals • Well Lengths 14,600' to 22,500' • Well spacing 2200' Production Plan: • Water Injection with alternating enriched gas injection Facilities: • Well pad — similar to CD5 layout • Production separator with metering • Four pipelines, road and bridges back to CD5 Lookoutl 2001 Lookout2 2002 Neutron' mlw PRSDensity" Neutron Perm Density° : aD ' RS Sonic W "' Sonic GR m.� Sw NE °° 0 LN °°° RD 1 1M orosityo GR mm 0 IS° RD y° °°Porosit I mD lAi i!.f MA 2- 7833'MD 7 63's 50 Rp zW PG o? ss 0 = I 7834' MD 7784' Ss Q W W 96 Nanus P M/as l 2�p 4 '7 01'. $ Q • 7814' Ss singAI U 8a dstone ehind c 44 • o not ogged Q U m I I N • � W Nechelik I It Kingak Fm zo Shubllk Fm. p VSs • = , � s i TRIASSIC .,. Ss rochit G . W 246 7928' -7879' y5 W z PERMIAN . W 286 W IEMSVLVANNN 320 Lisburne Gp. rn _ -- W ISSISSIPPIAN Ran 7 30' s 8000' M - Alpine C SS w a * - Primary Source (Kingak) 129' gross interval 65' gross interval 79' net pay (0 >15% cutoff) 53' net pay (0 >15% cutoff) 20% avg porn., 84 and avg. perm, 16.4% avg Sw 20% avg poro., 24 and avg. perm, 30.5% avg Sw Cased hole MDT - 42.50 oil Test (4 days) : 4000 BOPD, GOR -1500 cf/bbl Kh: -1300 and -ft ConocoPhillips Upper Confining Interval: • Deep marine shales and silts of the Fish Creek Slump, HRZ, Kalubik and Miluveach intervals • Total thickness varies from 600' to 1200+' Lower Confining Interval: • Kingak marine shales and siltstones • Approximately 1700' thick lY� v, S N •--� - 71M s f lY� D 2000 4000 6000 9000 1000oftus Cl=20ft 150000 r' ConocoPhillips cl=2on Northeast Southwest MITRE PBI LOOKOUT#2 LOOKOUT -1 V - 7' ]]W 5 5{1 _ Ml ]BW .:. g -sand - - U OnIgI2:yW'a Asa - s mm six Pom•ity NS%cutoff _ --"-m-'-_— Poraslry>15%culoH PSI p1 Nat Pay 53' NetPry i0.6 15.5 f ay. ParositY 18.8% 6p . ay. parmity 16.6% 16.0% - - - - - m.5w 30.5% 00 m.Sw 26.0% 25.6% Pormiry>15%>cutoff perm 24 and m perm 2.53 and 3.5 and Net Pey Kb 12]2 m6R K 1000' Kh $1.8 and -ft 51 and -ft 20' ay. pormlry 20.0% 1'0M wnloleuppsrnion mreav perm 0.1 and ay. BOrat 40- API 60001500 a U.d16.4% av perm 8t and ftl GDR 1600 mdNbl et Ti Kh 6636 and -K Fm Premum 3218 psis 40- API from MDT Kh -1300 md.ff cl=2on • Requesting a rule similar to Alpine Oil Pool for allowable injection gradient of .81 psi/ft *Analog Alpine historical performance indicates containment of injected fluids • Detailed modeling indicates injected fluids will be contained in the pool interval 43 MBWPD 0. .81 psi/ft pressure Injection Pressures: At Surface 2650 psi 4000 psi At 6171 psi 5219 Bottomhole 0.79 psi/ft 0.67 psi/ft 7825' tvd GOWER Frac Model w,.W Break for Confidential Data 13 Reservoir Fluid Properties (7800 feet TVDss datum) Property, Units Measured Value Initial Reservoir Pressure, psia 3770 Reservoir Temperature, OF 176 Saturation Pressure, psia 3237 Oil formation volume factor, RVB/STBO 1.77 Oil Density, 'API 42.5 Oil Viscosity, cp 0.22 Gas formation volume factor, RVB/MCF 0.78 In Place and Recoverable Resource Volumes (Pre Development) Hydrocarbon Resource Estimated Volumes, MMSTB Original Oil in Place, OOIP 70, 80,150 (low, medium, high) Primary Recovery (Er = 20% of OOIP) 14, 16, 30 (low, medium, high) Primary + Waterflood Recovery (Er = 45% of OOIP) 31, 36, 67 (low, medium, high) Primary+ Waterflood + EWAG Recovery (Er = 60% of OOIP) 42, 48, 90 (low, medium, high) ConocoF hHIips O 44 E. 70 20 - Assumed Cand4ions Pre:zure = 3750 psi Temperature _ 187 Currentlnlettant N 0 --------- ---- 0 ----- ----- 0 20 40 60 80 100 20 140 Pore Volume Injected, % P1,+ yectant rs ^f -lean Gas tCurrent CumpositionalBlend 0 VD, Enriching Fluid 15% Enriching Fluid -*- 2(r/ Enriching Fluid 160 ® Peak Annual Rates Production • Oil (MBOPD) 20-30 • Gas (MMCFPD) 20-50 • Water (MBWPD) 10-15 • Lift Gas (MMCFPD) 4-12 ® Injection • Water (MBWIPD) 25-40 • Rich Gas (MMCFPD) 10-20 Request waiver to gas -oil -ratio limits of 20 AAC 25.240(a) so long as the provisions of 20 AAC 25.240(b) applies. ConocoPhillips • Approx. 8 road miles from CD5 • Spud March 21, 2018 • Drilling support from CD1 • 9 horizontal wells (4 prod, 5 inj) • Prod casing TD's 8,800' to 12,700' • Lateral lengths 3,500' to 12,000' • Well TD's 14,600' to 22,500' • Departures 9,500' to 17,500' • Directionally drilled wells • MWD surveys and LWD open hole logs • Typical North Slope muds • Water based spud mud (surface hole) • Low solids non -dispersed (intermediate hole) • Water or mineral oil based drill -in fluid (lateral hole) • Annular disposal of mud and cuttings • Class I disposal well at CD1 • Key Focus • Wellbore stability - drilling through Fish Creek slumps and Miluveach shale • Mitigation — Liner Drilling with Managed Pressure Ea"WWM 2.0" Insulated conductor w/ thermo-siphon: • Surface 20" Insulated Conductor 80 feet, cemented to surface 16" Hole • Spud Mud — Slightly Inhibited TD —2100' MD (C-40) Q 13-3/8" Casing & Cement to Surface • Install and test BOPE • Intermediate 1• • 13-3/B"Surfa°e Casing 121/4" Hole cemented to surface GL O • LSND Mud • TO 7,500' to 11,000' (HRZ) 9-5/8" Casing Cement Shoe per AOGCC requirements 4-1/2" Tubing ° Intermediate 2: (Pipe Conveyed Section) • 8-%z" Hole • LSND Mud • 7" Liner (Steerable Drilling System) TD 8,800' to 12,700' (Alpine C) I• • Cement Shoe per AOGCC requirements 0 95/8" Casing • Run cement quality log on injectors TOC the greater of 5 and or 250 tvd above shoe • Lateral 6" Hole Mineral Oil Base (producers), Water Base (injectors) o. 0 4-%2" Liner TD —14,600' to 22,500' roc at least Sao' abov 0 Packer and the greater of 5a0 and or 250 tvd,0 • Completion above AlpineeC • Liner top packer set above Alpine C within confining zone • Gas lifted producers w/ permanent downhole pressure gauges o • Fracture stimulation not anticipated Top Alpine 7" Liner • Wellheads with horizontal tree • Request waiver to 20 AAC 25.412(b) —injection well packer set depth Tubing / Liner Completion: 1) 4-7•" Landing Nipple(3.813'I13) 2) 4-%' x 1' GLM 3) 4-59' x 1' GLM 4) Liner Top Packer Hanger 5) 4-'h" x 1' GLM 6) Liner Top Packer Hanger w/ Tie Back sleeve 7) 4-h' Landing Nipple(3725" NoGo) 8) 4=h' Blank Pipe 9) 4=h' Liner with Perf Pups 41A" Liner with Pert Pups 6" Hole 5000 —12000 R horizontal ConoaoP,Mips • Lookout 1— Suspended April 9, 2003 with downhole tubing plug, kill weight fluid, back -pressure valve in tubing hanger and VR plugs in wellhead. • On 5 year inspection cycle — most recent completed July 25, 2015 • Lookout 2 — • Plugged and abandoned completed May 5, 2002 MiTANU IN • Plugged and abandoned completed April 21, 2002 ConocoPhillips • CPAI requests a finding in the LOP Orders that no freshwater aquifers are present in the LOP area. • Request is to avoid duplicative reviews of whether there are fresh water aquifers in the LOP area in future annular disposal sundry and injection well permit to drill applications. ConocoPhillips Lookout Area Type Log — Shallow Salinity Analysis Summary Mal. i__ .11 _a.- .. ' P. • 111.. • 1 _ 11 • - - Group interbedded silt & minor sands)n Nanushuk Group (K-3 to Albian 95; Top -sets, shallow marine silts/shales and thin fine grained 11 sands) :11 Torok (Albian slope & deep marine . 111.. - .. • = 11 inter -bedded sands) .. . • ••' • • . i. Alpine C Sandstone (Target) �_ ■ —_' MEL - 121 MITRE 1P131 LOOKOUT 2 Base Permafrost at 1000' TVDSS RES EMW 8 9P9 c N � O J N � m O m oq L O m CASI r -- NUIQSUT 1 /kOOKOUT2 .460KOUT 1 ,lA1TRE 1PB1 CLOVER A GMT Unit : Colville River Unit Lookout Oil Pool 11 T - `ro Gas lift meter on each Production producer Four Production Wells COS Injection Lookout Gas Meters at CDAll I A Injection meter on each injection well Five Injection Wells Other CRU Drillsites Oil Sales to Alpine Pipeline Seawater L.ili.�iiiLliL y Compatibility of produced and injected fluids between the Lookout Oil Pool and CRU Oil Pools is expected: ➢ Lookout production compositions are expected to be similar to the Alpine Pool and fully compatible with all CRU pools ➢ Lookout is a very close analog to the Alpine Oil Pool because both pools share a similar geologic history with the same oil charge source (Lower Kingak) and rock deposition source (Alpine A and B) ➢ Lookout water production will be a mixture of Lookout connate water and seawater or ACF produced water and it is not expected to be significantly different than Alpine Pool produced water and therefore should be fully compatible with all CRU pools ➢ Application of scale inhibitors, corrosion inhibitors and any other production treatments at Lookout will be similar to those at other CRU pools ConocoFP fillips STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION Docket Numbers: CO -18-001 and AIO-18-013 Look Out Oil Pool, Greater Moose's Tooth Unit Application for Pool Rules and Area Injection Order April 3, 2018 at 10:00 am NAME AFFILIATION Testify (yes or no) h��n ��{h�� i 3 Colombie, Jody J (DOA) From: Roby, David S (DOA) Sent: Monday, April 02, 2018 1:50 PM To: Colombie, Jody J (DOA) Subject: FW: [EXTERNAL] Lookout Jody, Please put a copy of this email in the folders for the Lookout Pool Rules and AID applications. Docket no. CO -18-001 and AID 18- 013. Thanks, Dave Roby (907)793-1232 CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding if, and, so that the AOGCC is aware of the mistake in sending it to you, contact Dave Roby at (907)793-1232 or dave.robv@alaska.aov. From: Cookson, John <John.Cookson@conocophillips.com> Sent: Monday, April 02, 2018 1:35 PM To: Roby, David S (DOA) <dave.roby@alaska.gov> Subject: RE: [EXTERNAL] Lookout Hi Dave, thanks for this info. We don't think the D will be a good seal and therefore we included it in the interval. I don't think we're expecting it to be developable. Let me know if you have any more questions. Thanks! From: Roby, David S (DOA) [mailto:dave.robv@alaska.eov] Sent: Monday, April 02, 2018 11:37 AM To: Cookson, John <John Cookson conocophillips.com> Subject: [EXTERNAL] Lookout Hi John, I checked and we have not received any comments on the pool rules or AID applications And, I've checked with Patricia and we do not need you to supplement your application with the now non -confidential geologic information. Presenting this during the hearing tomorrow will get the info into the public record. In looking through the applications again I do have one question. You're proposing defining the pool/injection interval as including the Alpine C and D sands but it appears you're only planning on developing in the C sands, which raises the question "if you're only developing the C why include the D in the pool?" I suspect the answer to this is twofold. First, you think there's potential that the D might be developable down the road as you collect more geologic information in the pool. And second, you don't consider the D to be a seal so you set the top of the pool as the base of what you consider the overlying seal. Are my suspicions correct, and if not could you let me know what your reasoning is? Thanks, Dave Roby Sr. Reservoir Engineer Alaska Oil and Gas Conservation Commission (907)793-1232 CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC(, State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Dave Roby at (907(793-1232 or dove robv@alaska.gov. 2 STATE OF ALASKA ADVERTISING ORDER NOTICE TO PUBLISHER SUBMIT INVOICE SHOWING ADVERTISING ORDER NO, CERTIFIED AFFIDAVIT OF PUBLICATION WITH ATTACHED COPY OF ADVERTISMENT. ADVERTISING ORDER NUMBER AO-18-013 FROM: AGENCY CONTACT: Jody Colombie/Samantha Carlisle Alaska Oil and Gas Conservation Commission DATE OF A.O.AGENCY PHONE: 333 West 7th Avenue 3/1/2018 (907) 279-1433 Anchors e, Alaska 99501 DATES ADVERTISEMENT REQUIRED: COMPANY CONTACT NAME: PHONE NUMBER: ASAP FAX NUMBER: 907 276-7542 TO PUBLISHER: Anchorage Daily News SPECIAL INSTRUCTIONS: 300 W. 31st Ave. Anchorage, Alaska 99503 TYPE OF ADVERTISEMENT: FV LEGAL F_ DISPLAY CLASSIFIED ` OTHER (Specify belov4 DESCRIPTION PRICE CO-18-001 and AIO-18-013 Initials of who prepared AO: Alaska Non -Taxable 92-600185 .......liiivvo......ICE ?wirvcApveitTiSliyc::: ::0?++O��RTiFILUA??iupvii:gq:;:;:; :rueilcinoy.wilHXT.Taiuctiy:op:::: yE�rtstuerytxo Department of Administration Division of AOGCC 333 West 7th Avenue Anchors a Alaska 99501 [Pap, of 1 Total of All Pa es $ REF Type Number Amount Date Comments I PVN ADN89311 2 AD—AO-18-013 3 4 FIN AMOUNT SY Act Template PGM LGR Object FY DIST LIQ I 18 A14100 3046 I8 2 3 4 5 Porch ing rity me Title: Purchasing oriry's Signature Telephone Number IA.D. a and receiving name must appear on all invoices and documents relating to this purchase. 2. The stale is registered f Ree transactions under Chapter 32, IRS code. Registration number 92-73-0006 K. Items are for the WAUSive use of the slate and not for resale. AISTRIBUTfON, 1)WumB .F.istaUQMiginal AQ. Copies' .Puhhaher (faz. id), DiVlsio¢.FisGal RecOwmg Form: 02-901 Revised: 3/1/2018 Notice of Public Hearing STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION Re: Docket Numbers: CO -18-001 and AIO-18-013 Look Out Oil Pool, Greater Moose's Tooth Unit Application for Pool Rules and Area Injection Order ConocoPhillips Alaska, Inc. (CPAI), by applications dated February 28, 2018, requests the Alaska Oil and Gas Conservation Commission (AOGCC) establish pool rules for their proposed Lookout Oil Pool (LOP) in the Greater Moose's Tooth Unit and issue an Area Injection Order to authorize a water alternating enriched gas injection process for enhanced oil recovery purposes in the proposed LOP. The AOGCC has scheduled a public hearing on the application for April 3, 2018, at 10:00 a.m. at 333 West 7d Avenue, Anchorage, Alaska 99501. In addition, written comments regarding this application may be submitted to the AOGCC, at 333 West 7' Avenue, Anchorage, Alaska 99501. Comments must be received no later than the conclusion of the April 3, 2018 hearing. If, because of a disability, special accommodations may be needed to comment or attend the hearing, contact the AOGCC at (907) 279-1433, no later than March 29, 2018. Hollis S. French Chair, Commissioner 270227 0001417558 $149.42 AFFIDAVIT OF PUBLICATION STATE OF ALASKA THIRD JUDICIAL DISTRICT Joleesa Stepetin being first duly sworn on oath deposes and says that he/she is a representative of the Anchorage 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 aforesaid 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 March 04, 2018 and that such newspaper was regularly distributed 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 his 5th day of March, 2018 oW Notary Public in and for The State of Alaska. Third Division Anchorage, Alaska MY COMMIS:q EXPIRES Alaska Oil Commission Docket Numbers: CO -18-001 and AIO-18-013 Look Out Oil Pool, Greater Moose's Tooth Unit Application for Pool Rules and Area Injection Order a oil an Area injection ordi Sa, injection process �s scheduled a public hearing on the application for April a.m. at 333 West 7th Avenue, Anchorage, Alaska 99501. gardingg this application m ast 7tfi Avenue, Anchorage, no later than the conclusion D of a disability special accommodations may be or attend the hearing, contact the AOGCC at (907) an March 29, 2018. March 4. 2018 Chair, RECEIVED, MAR 12 2018 P"iOGCC , Notary 'Public BRITNEY L.THOMPSON State of Alaska tdy Commission Expires Feb 23, 2019 Carlisle, Samantha J (DOA) From: Carlisle, Samantha J (DOA) Sent: Thursday, March 01, 2018 12:34 PM To: 'Ballantine, Tab A (LAW) (tab.ballantine@alaska.gov)'; 'Bettis, Patricia K (DOA) (patricia.bettis@alaska.gov)'; 'Bixby, Brian D (DOA)'; 'Brooks, Phoebe L (DOA) (phoebe.brooks@alaska.gov)'; Carlisle, Samantha J (DOA); 'Colombie, Jody J (DOA) Qody.colombie@alaska.gov)'; 'Cook, Guy D (DOA)'; 'Davies, Stephen F (DOA) (steve.davies@alaska.gov)'; Earl, Adam G (DOA); Erickson, Tamara K (DOA); 'Foerster, Catherine P (DOA)(cathy.foerster@alaska.gov)';'French, Hollis (DOA)';'Frystacky, Michal (michal.frystacky@alaska.gov)'; 'Guhl, Meredith (DOA sponsored) Stephen Thatcher Manager, WNS Development (meredith.guhl@alaska.gov)'; Herrera, Matthew F (DOA);'Jones, Jeffery B (DOA) conocoPhgllps Alaska, Inc. (effjones@alaska.gov)'; Kair, Michael N (DOA); Laubenstein, Lou (DOA); 'Link, Liz M P.D Box 196612 (DOA)'; Loepp, Victoria T (DOA); Mcphee, Megan S (DOA); 'Mumm, Joseph (DOA Anchorage, AK 99519-6612 sponsored) (j p .mumm ose h @alaska. ov)'; 'Noble, Robert C (DOA) g (bob.noble@alaska.gov)'; 'Paladijczuk, Tracie L (DOA)(tracie.paladijczuk@alaska.gov)'; 'Pasqual, Maria (DOA) (maria.pasqual@alaska.gov)'; 'Regg, lames B (DOA) Jim.regg@alaska.gov)'; Rixse, Melvin G (DOA);'Roby, David S (DOA) (dave.roby@alaska.gov)'; 'Schwartz, Guy L (DOA) (guy.schwartz@alaska.gov)'; 'Seamount, Dan T (DOA)(dan.seamount@alaska.gov)';'Wallace, Chris D (DOA) (chris.wallace@alaska.gov)';'AK, GWO Projects Well Integrity'; 'AKDCWellIntegrityCoordinator'; 'Alan Bailey'; 'Alex Demarban'; 'Alicia Showalter'; 'Allen Huckabay';'Andrew VanderJack';'Ann Danielson'; 'Anna Raff';'Barbara F Fullmer'; 'bbritch'; 'Becky Bohrer'; 'Ben Boettger'; 'Bill Bredar'; 'Bob'; 'Bonnie Bailey'; 'Brandon Viator'; 'Brian Havelock'; 'Bruce Webb'; 'Caleb Conrad'; 'Candi English'; 'Cody Gauer'; 'Cody Terrell'; 'Colleen Miller';'Connie Downing'; 'Crandall, Krissell';'D Lawrence';'Dale Hoffman'; 'Danielle Mercurio';'Darci Horner';'Dave Harbour'; 'David Boelens';'David Duffy';'David House';'David McCaleb';'ddonkel@cfl.rr.com'; Diemer, Kenneth (DNR); 'DNROG Units';'Donna Ambruz';'Ed Jones'; 'Elizabeth Harball';'Elowe, Kristin'; 'Elwood Brehmer'; 'Evan Osborne'; 'Evans, John R (LDZX)'; 'Garrett Brown'; 'George Pollock'; 'Gordon Pospisil'; Greeley, Destin M (DOR); 'Gretchen Stoddard';'gspfoff'; Hurst, Rona D (DNR); Hyun, James J (DNR);'Jacki Rose'; 'Jason Brune';'Jdarlington Qarlington@gmail.com)';'Jeanne McPherren';'Jerry Hodgden';'Jill Simek';'Jim Shine'; 'Jim Watt'; 'Jim White'; 'Jim Young';'Joe Lastufka';'Joe Nicks';'John Burdick';'John Easton'; 'John Larsen'; 'Jon Goltz'; 'Josef Chmielowski'; 'Joshua Stephen'; 'Juanita Lovett'; 'Judy Stanek'; 'Kari Moriarty'; 'Kasper Kowalewski'; 'Kazeem Adegbola'; 'Keith Torrance'; 'Keith Wiles';'Kelly Sperback';'Kevin Frank'; Kruse, Rebecca D (DNR);'Kyla Choquette'; 'Laura Silliphant(laura.gregersen@alaska.gov)';'Leslie Smith';'Lori Nelson'; 'Luke Keller'; 'Marc Kovak'; 'Mark Dalton'; 'Mark Hanley (mark.hanley@anadarko.com)'; 'Mark Landt'; 'Mark Wed man'; 'Michael Bill';'Michael Calkins'; 'Michael Moora';'Michael Quick'; 'Michael Schoetz'; 'Mike Morgan'; 'MJ Loveland'; 'mkm7200'; 'Motteram, Luke A'; Mueller, Marta R (DNR); 'Nathaniel Herz';'nelson';'Nichole Saunders';'Nick Ostrovsky'; 'NSK Problem Well Supv'; 'Patty Alfaro';'Paul Craig'; 'Paul Decker (paul.decker@alaska.gov)';'Paul Mazzolini'; Pike, Kevin W (DNR);'Randall Kanady'; 'Renan Yanish'; 'Richard Cool'; 'Robert Brelsford'; 'Robert Warthen'; 'Ryan Gross'; 'Sara Leverette'; 'Scott Griffith'; 'Shahla Farzan'; 'Shannon Donnelly'; 'Sharon Yarawsky'; Skutca, Joseph E (DNR); Smith, Kyle S (DN R); 'Stephanie Klemmer';'Stephen Hennigan'; 'Sternicki, Oliver R';'Steve Moothart (steve.moothart@alaska.gov)';'Steve Quinn'; 'Suzanne Gibson';'Tamera Sheffield';'Tanisha Gleason'; 'Ted Kramer'; 'Teresa Imm'; 'Tim Jones'; 'Tim Mayers'; 'Todd Durkee'; 'Tom Maloney'; 'trmjrl'; 'Tyler Senden'; Umekwe, Maduabuchi P (DNR); 'Vinnie Catalano'; 'Well Integrity'; 'Well Integrity'; 'Weston Nash'; 'Whitney Pettus'; 'Aaron Gluzman';'Aaron Sorrell'; 'Ajibola Adeyeye';'Alan Dennis'; 'Andy To: Bond'; 'Bajsarowicz, Caroline J` 'Bruce Williams'; 'Casey Sullivan'; 'Corey Munk'; 'Davis Mccraine'; 'Don Shaw'; 'Epple Hogan '; 'Eric Lidji'; 'Garrett Haag'; 'Graham Smith'; Neusser, Heather A (DNR);'Holly Fair';'Jamie M. Long'; 'Jason Bergerson';'Jesse Chielowski'; 'Jim Magill'; 'Joe Longo'; 'John Martineck'; 'Josh Kindred'; 'Keith Lopez'; 'Laney Vazquez';'Lois Epstein'; Longan, Sara W (DNR);'Marc Kuck';'Marcia Hobson'; 'Marie Steele'; 'Matt Armstrong'; 'Melonnie Amundson'; 'Mike Franger'; 'Morgan, Kirk A (DNR)'; 'Pascal Umekwe'; 'Pat Galvin'; 'Pete Dickinson'; 'Peter Contreras'; 'Rachel Davis'; 'Richard Garrard'; 'Richmond, Diane M';'Robert Province';'Ryan Daniel';'Sandra Lemke'; 'Susan Pollard';'Talib Syed';'Tina Grovier (tmg rovier@stoel.com)'; 'William Van Dyke' Subject: Notice of Public Hearing Attachments: CO -18-001 AIO-18-013 Public Hearing Notice Lookout Oil Pool pool rules and AIO.pdf Stephen Thatcher D M na r wn Devel e3� 001 and AIO-18-013 est>at LonlAoltt�ool, Greater Moose's Tooth Unit Aftft ti f340` 5"'Rules and Area Injection Order Samantha Carlisle Executive Secretary III Alaska Oil and Gas Conservation Commission 333 West 7t11 Avenue Anchorage, AK 99501 (907) 793-1223 CONFIDENTIALITY NOTICE, This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. Fhe unauthorized review. use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Samantha Carlisle at (907 793-122.4 or Simantha.CarlisletuIalaska.eov. Bernie Karl Gordon Severson Penny Vadla K&K Recycling Inc. 3201 Westmar Cir. 399 W. Riverview Ave. P.O. Box 58055 Anchorage, AK 99508-4336 Soldotna, AK 99669-7714 Fairbanks, AK 99711 George Vaught Jr. Darwin Waldsmith Richard Wagner P.O. Box 13557 P.O. Box 39309 P.O. Box 60868 Denver, CO 80201-3557 Ninilchik, AK 99639 Fairbanks, AK 99706 1 ConocoPhillips Confidential TRANSMITTAL FROM: John Cookson TO: Commissioner Hollis French ConocoPhillips Alaska, Inc. Alaska Oil and Gas Conservation Commission P.O. Box 100360 333 W. Th Ave., Suite 100 Anchorage AK 99510-0360 Anchorage, Alaska 99501-3539 RE: Lookout Oil Pool CO and AIO Applications, CRU Offtake Amendment Application, CRU Request for Administrative Amendments DATE: 02/29/2018 Transmitted: 1 CD Containing the following files: • • Lookout CO Application.pdf Lookout CO Application (confidential).pdf RECEIVE® • Lookout AIO Application.pdf • Lookout AIO Application (confidential).pdf MAR A 1 1058 • CRU Gas Offtake Amendment.pdf • CRU Request for Administrative Amendments.pdf AOGCC 3 Paper Copies of: • Lookout CO Application • Lookout CO Application (confidential) • Lookout AIO Application • Lookout AIO Application (confidential) • CRU Gas Offtake Amendment • CRU Request for Administrative Amendments Date: ConocoPhilli S February 28, 2018 Hollis French, Chair Alaska Oil and Gas Conservation Commission 333 W. 7th Ave #100 Anchorage, Alaska, 99501-3539 RE: Application for Pool Rules Lookout Oil Pool, North Slope, AK Dear Commissioner French, Stephen Thatcher Manager, WNS Development North Slope Operations and Development ConocoPhillips Alaska, Inc. ATO -1770 700 G Street Anchorage, AK 99501 phone 907.263.4464 RECEIVED MAR 01 2018 AOGCC In accordance with 20 ACC 25.520, ConocoPhillips Alaska, Inc. ("CPAI") as operator of the Greater Mooses Tooth Unit ("GMTU"), requests that the Alaska Oil and Gas Conservation Commission approve CPAI's application for a Conservation Order to classify the Lookout Oil Pool and to prescribe pool rules for development of the Lookout Oil Pool within the GMTU. Pursuant to 20 AAC 25.537, CPAI requests that Appendix 1 to this application be treated as confidential as the information is a trade secret or commercially confidential and proprietary information. CPAI requests that the hearing date for this application be scheduled as soon as possible after the 30 -day notice period has concluded. Enclosed are two printed originals of the application and a disc containing an electronic version of the application. Please contact John Cookson (265-1363) if you have questions or require additional information. Regards, Stephen Thatcher Manager, WNS Development North Slope Operations and Development Cc: Land Manager - Alaska, Anadarko E&P Onshore LLC, GMTU WIO Representative Enclosures (3) CPA] Application for Pool Rules February 28, 2018 Page 2 of 34 Conoco Phillip s APPLICATION FOR POOL RULES OF THE LOOKOUT OIL POOL February 28, 2018 1. Introduction 2. Geology 3. Reservoir 4. Reservoir Development 5. Drilling 6. Well Operations 7. Facilities 8. Proposed LOP Rules List of Figures 1. Proposed LOP Area 2. Defining Well, Lookout 1, Highlighting Pool Interval 3. Lease Map with Planned Drilling Locations and Drilling Order 4. Recovery versus PV Injected 5. Proposed Lookout Producer Well Schematic 6. Annular Disposal Interval — C-30 7. GMT1 Facilities and Metering 8. Alpine C Isochore for LOP (Confidential, Appendix 1) 9. Seismic Volume (Confidential, Appendix 1) 10. UJU Depth Structure Map with Faulting (Confidential, Appendix 1) 11. Structural Cross Section Across the Pool Area (Confidential, Appendix 1) 12. Net Pay Map with Planned Drilling Locations and Drilling Order (Confidential, Appendix 1) Appendix: 1. Confidential Information 2. Formation Water Salinity 3. Annular Disposal of Drilling Waste at CD5 4. Docket OTH 14-026 Annular Disposal of Drilling Waste at CD5 CPA[ Application for Pool Rules February 28, 2018 Page 3 of 34 1. INTRODUCTION Document Scope This application is submitted for approval by the Alaska Oil and Gas Conservation Commission ("Commission") to define the proposed Lookout oil pool ("LOP") and establish Pool Rules for the oil pool pursuant to 20 ACC 25.520. ConocoPhillips Alaska, Inc. ("CPAI"), submits this application to the Commission in its capacity as Operator of the Greater Mooses Tooth Unit ("GMTU") and on behalf of the GMTU working interest owners (WIOs). The scope of this application includes a discussion of geological and reservoir properties of the proposed LOP as they are currently understood, and CPAI's plans for reservoir development, reservoir surveillance, and well construction. This application and supporting testimony will enable the Commission to establish rules that will allow economic development of resources, promote greater ultimate recovery, and prevent waste within the LOP. This application contains confidential data and interpretation concerning the LOP which is being provided in accordance with the provisions of AS 31.05.035 and 20 ACC 25.537. Confidential data is provided in Appendix 1. Concurrent with this request, CPAI in its capacity as Operator of the GMTU and on behalf of the GMTU WIOs is also separately applying to the Commission for: (1) an Area Injection Order for the LOP: (2) for modification of CRU Gas Offtake Order 569.001 to allow Colville River Unit gas to be provided to Lookout; and (3) for modification of allowable enhanced recovery fluid rules for several CRU pools to allow injection of Lookout produced water. Pool Area and Interval The proposed area to be covered by the LOP Rules is shown in Figure 1. Lookout 1 provides the type log for the LOP shown in Figure 2. CPA] requests that the Alpine C and Alpine D intervals, as shown in the correlative section on the type log from measured depths 7,833 ft. to 8,000 ft. or true vertical depths below mean sea level of -7,763 ft. to -7,930 ft. (true vertical depth below mean seal level also termed true vertical depth subsea and represented herein by the acronym TVDss), be included in the Pool. The base of the LOP is defined by the Upper Jurassic Unconformity (UJU) as defined by the Lookout 1 well at 8000 ft. MD and a TVDss of -7930 ft.' Project Background The LOP was first assessed in 2001 and 2002 by the Lookout 1, Lookout 2 and Mitre 1 wells. See Figure 1. Lookout 1 and Lookout 2 both encountered hydrocarbons while the Mitre 1 well penetrated the interval outside of the reservoir limit. A four-day production test was conducted on Lookout 2 while interference was monitored in Lookout 1. During the test, Lookout 2 produced at a rate of approximately 4000 BOPD, 0 BWPD with a 2100 scf/stb GOR. Lookout 1 pressures over an extended monitoring period indicated good reservoir communication with Lookout 2. In 2008, the GMTU was formed. In 2015, a Record of Decision was obtained for a Supplemental Environmental Impact Statement covering the project to develop the LOP. The project to develop Lookout is known as the Greater Mooses Tooth 1 (GMT1) Project and was sanctioned in 2015. GMT1 is the first development wholly within National Petroleum Reserve, Alaska. I The information contained in this application is intended to satisfy the requirement of 20 AAC 25.517(a) that the operator of the Lookout Oil Pool submit to the Commission a plan of reservoir development and operation. CPAI Application for Pool Rules February 28, 2018 Page 4 of 34 The GMT1 Project consists of a new drill site and associated facilities located approximately 8 miles southwest of the CD5 drill site, a permanent road connecting the two drill sites, four new pipelines (produced crude, water injection, miscible injection and gas lift) and 9 horizontal wells (four producers and five injectors). An injection program of water alternating with enriched gas injection will optimize recovery from the pool. GMT1 production will be measured for custody transfer prior to being commingled on the surface with production from the Colville River Unit (CRU), and GMT1 production will then be processed at the Alpine Central Facility (ACF) in the CRU. From a geologic and reservoir perspective, the LOP is like the Alpine Oil Pool except Lookout does not have Alpine A sand present, does not include Kuparuk sands, has a lighter (higher API) oil and an associated higher solution gas -to -oil ratio. From an operations perspective, Lookout will be treated similar to CRU oil pools. Ownership GMT1 Project working interest owners are CPA[ and Anadarko E&P Onshore LLC. CPAI is the operator of the GMT1 Project, the GMTU and the CRU. CPAI and Anadarko E&P Offshore LLC each have the same working interests in both the GMT1 Project and the ACF. The Surface Owners of the LOP area are Kuukpik Corporation and the Bureau of Land Management (BLM). The Subsurface Owners of the LOP are Arctic Slope Regional Corporation (ASRC) and BLM. Figure 1 shows lands in which BLM is both the surface and subsurface owner and also shows lands where Kuukpik is the surface owner and ASRC is the subsurface owner. The Lookout Participating Area is being formed to develop the LOP. The proposed Lookout Participating Area boundary is shown in Figure 1. CPAI Application for Pool Rules February 28, 2018 Page 5 of 34 �...._,. ......T12..I � 1 i T1111 1 3 2 I Greater Mooses Tooth Unit 9A D R F i, 1 15 i 21 1 22 i 1 27 i 1 Coivill - - - !--River, oto Unit i - -- ... ..tTI1NR3E ! Q MT6 Well Pad 'MT6 i Q Proposed Lookout Oil Pool Boundary Q Lookout Reservoir Q Proposed Lookout Participating Area ® Kuukpik SurfaceASRC subsurface W w GMTU Tracts CIj 11 ,Of r 1'�;j Unit Boundaries Zo C, [ .-?CPAI Leases r " ConocoPhillips AAlaska Proposed Lookout 0 0.5 1 1.5 2 gEEEEmr=====3mmmwmc===Miles 3 Oil Pool Area 11252018 Figure 1: Proposed Lookout Pool Area CPAI Application for Pool Rules February 28, 2018 Page 6 of 34 tO L Q) i-+ i 0 CL O T Y 0 0 J Figure 2: Defining well, Lookout 1, highlighting Pool interval UJU at 8000' MD Lookoutl 2001 NAd NXJ 5 K0N 'J i1i0B 6M96 i (R75 mo (R)z Im I" G,m) 265 BBS .WO -V Oi:Ni,^t 1 a6mm Im Iw wn w O.irm. B. 1:700 1:200 9➢().Arµ) t > _ 1w Mmm 100 06 0 833' m 17763' ss� i 1 ga S � 7871' g CO n l 78 1' SS 0 i m n 1 .7 `L O 0 at n_ o o i 8000' nj 79 0' ss l Figure 2: Defining well, Lookout 1, highlighting Pool interval UJU at 8000' MD CPAI Application for Pool Rules February 28, 2018 Page 7 of 34 2. GEOLOGY Pool Identification The LOP is defined as the accumulation of hydrocarbons common to and correlating with the interval between the measured depths of 7,833 ft. and 8,000 ft. (-7,763 ft. and -7,930 ft. TVDss respectively) in the Lookout 1 well (Figure 2). It is also referred to as the Alpine Reservoir. Upper Confining Interval Deep marine shales and silts of the Fish Creek Slumps, HRZ, Kalubik and Miluveach intervals form the upper confining zone for the LOP. Total thickness varies from 550 ft. to 1200+ ft. 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 LOP is the Kingak shale. The Kingak is approximately 1700 ft. thick in the proposed area of development, consisting of marine shales and siltstones. Stratigraphy and Sedimentology The LOP in the GMT1 area is an oil accumulation formed by a stratigraphic trap of the shallow marine, Upper Jurassic Alpine C sandstone. The Alpine C sandstone unconformably overlies the Kingak Shale and underlies the Miluveach Formation. The Alpine C sands are nearshore transgressive sands infilling the paleotopography created by incision of the regionally extensive UJU. A type log of the full stratigraphic column is shown in Appendix 2. Confidential stratigraphy and sedimentology interpretation supporting this application is provided in Appendix 1. Structure Within the affected area, the top of the Alpine C lies between -7,650 feet and -8,000 ft. TVDss. There is one set of seismically mapped normal faults present in the proposed development area, an early Cretaceous aged, north-northeast trending system. Vertical displacements along these faults range from 0 to as much as 70' and may act as barriers or baffles to flow where the reservoir is almost entirely offset. Confidential structure interpretation supporting this application is provided in Appendix 1. Trap Configuration and Seals LOP in the GMT1 area is an oil accumulation formed by a stratigraphic trap of the shallow marine, Upper Jurassic Alpine C sandstone. The Alpine C sandstone unconformably overlies the Alpine A and Kingak Shale and underlies the Miluveach Formation. The Kingak formation below and Miluveach, Kalubik, HRZ and Fish Creek Slump shales above provide the seal for the Alpine C sandstone. CPAI Application for Pool Rules February 28, 2018 Page 8 of 34 Reservoir Compartmentalization A long-term interference test between Lookout 1 and Lookout 2 confirms reservoir connectivity over the majority of the reservoir. Local compartmentalization is possible in the southern portion of the incision where the reservoir is almost entirely offset by faulting. 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 or gas contacts have been encountered or interpreted within the LOP. Bottom hole fluid samples collected during modular formation dynamics testing of the discovery well, Lookout 1, indicate that the reservoir fluid is under saturated and therefore no gas cap is likely present. Laboratory measurement of homogenized bottom hole fluid samples indicate saturation pressure is approximately 3237 psia at a measured reservoir temperature of 176° F. The measured saturation pressure is more than 500 psi lower than the discovery pressure of 3775 psia at a measured depth of 7883 ft. None of the exploratory or development wells drilled within the Colville River Unit and the Greater Moose's Tooth Unit have encountered an oil -water contact (OWC) in Jurassic -aged sands. As a result, an OWC is not expected within any portion of Lookout reservoir. CPAI Application for Pool Rules February 28, 2018 Page 9 of 34 3. RESERVOIR Introduction The LOP 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. This section will summarize reservoir properties with data available from the two wells located in the LOP, Lookout 1 and Lookout 2. Core data is available from the Lookout 2 well. Reservoir Properties Reservoir fluid properties are summarized from the PVT study completed for the Lookout 1 well. Lookout reservoir and fluid properties were measured at -7,883' MD (-7813' ss TVD) and are listed below: - Initial Reservoir pressure: 3775 psia - Reservoir temperature: 176°F - GOR: 1385 scf/bbl - API gravity: 42.50 - Bubble point pressure: 3237 psia - Oil formation volume factor: 1.77 rb/stbo - Oil viscosity: 0.22 cp - Gas formation volume factor: 0.78 bbl/mscf (at saturation pressure) Reservoir rock properties are described in the Geologic Section. Original Oil -in -Place ("OOIP") The estimated original oil in place volume for the LOP is based on the well data from Lookout 1 and Lookout 2, seismic, and an interference test. Pre -development low, medium and high OOIP estimates are 70, 80 and 150 MMBO, respectively. Additional reservoir data from the planned development wells will enhance the understanding of sand distribution and may result in an update to the OOIP estimates. A net pay map for a medium OOIP scenario is shown in Figure 6 (Confidential, Appendix 1). CPAI Application for Pool Rules February 28, 2018 Page 10 of 34 4. RESERVOIR DEVELOPMENT Development Plan The LOP will be developed with horizontal production and injection wells in line drive patterns oriented with the maximum principal geomechanical stress direction. The development plan includes 5 horizontal injection wells and 4 horizontal production wells with possible pilot holes. The pilot holes will provide additional reservoir data and assist in optimization of horizontal well placement. The planned drilling locations are shown in Figure 3. Pressure support will be maintained with water and gas injection targeting a voidage replacement ratio of 1.0. An Enriched Water Alternating Gas ("EWAG") flood will be initiated early in the waterflood to improve ultimate recovery. Although the gas flood is not miscible with current injection composition, EWAG will yield incremental recovery with condensing components that will result in improved oil mobility due to oil swelling and reduced interfacial tension. Simulation work demonstrated an optimal well spacing of 2200' separation between injectors and producers. A large fault separates the southwest and southeast areas of the development area. This fault impacts the well placement strategy with individual injection and production wells along either side of the fault displacement. Due to the expected reservoir throughput, the production wells are planned as unstimulated horizontal producers. Two wells are planned with multi -lateral completions in the thicker vertical section of the reservoir. This completion strategy will ensure efficient drainage and sweep in the vertical reservoir sections separated by an interval of potential reduced rock quality. The distribution of this lower quality facies will be better understood with the pilot hole and horizontal logging data. Long horizontal injection and production wells are expected to yield efficient areal and vertical sweep due to the low oil viscosity which yields favorable waterflood mobility. EWAG will enhance displacement efficiency and assist with reservoir throughput as the waterflood matures. 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 LOP. The favorable rock properties and waterflood mobility for the Lookout reservoir yield an expectation for ultimate EWAG recovery that will be in the range of 50-65% 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 EOR recovery is 12% of OOIP based on reservoir simulation at the type pattern and full field model scales. The remaining recovery is expected from pressure maintenance with waterflood support and depends on maintenance of voidage replacement. Recovery Performance The forecast of recovery performance for the LOP 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 matched to the historical Lookout performance data and used as a forecasting tool for the planned development. A standalone effort to forecast the incremental recovery from enriched gas injection was completed to match lab based recovery observations. Figure 4 shows resulting recovery with variations in gas enrichment from the 1 D simulation using the Lookout tuned Equation of State. CPAI Application for Pool Rules February 28, 2018 Page 11 of 34 The 1 D simulation results demonstrate an incremental 13% recovery at a reference throughput volume of 1.2 Pore Volume. This recovery is consistent with the fine grid pattern level simulation results which yielded 12% incremental recovery from enriched gas injection with the current sub -miscible injectant composition. The expected incremental recovery due to enriched gas injection at the current ACF composition is 12%. The upscaled field model was history matched to the extended interference test completed between the Lookout #1 and Lookout 2 wells. A deterministic field model run with the planned development wells in place and EWAG injection support yields through wellbore recovery of 61 %. This through wellbore recovery is within the expected range of 50-65% recovery. Future Development Execution of the current development plan will yield additional log data that will provide a better understanding of the sand distribution in the Lookout reservoir. This data may lead to the identification of future infill development opportunities beyond the current identified scope. Producing Gas -Oil Ratio ("GOR") Expectations CPAI requests that the requirements described in 20 AAC 25.240 be waived for the proposed LOP since the Pool plans are to implement enhanced recovery techniques. Since gas will be injected into the LOP 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 LOP average reservoir pressure will be maintained above the bubble point pressure with water injection for pressure maintenance. CPAI Application for Pool Rules February 28, 2018 Page 12 of 34 P,uplo,l anEA .oed 0 S.P.W. © Orilli gOrtl r —Inlector —Producer I=GW, LookM Rex J=Ropose0 Lookout PA f:DuakB�anws ® Kuukpk Surfax ASRC SubsuRace 0 Proposed Lookout Oil Pool BouWary --- CPAI Leases N 0 0.5 1 qinnmmmnwL:=====Miles L:...........�. Greater Mooses Tooth Unit- T10NR3E Lookout Oil Pool Development Plan Figure 3 — Lease Map with Planned Drilling Locations and Drilling Order CPAI Application for Pool Rules February 28, 2018 Page 13 of 34 100 , 90 so 0 70 E as U) 20 Assumed Condlidons pressure =3750 PSS.. 10 Temperature = 287 i torrent InJeetent h 0 20 40 60 80 100 120 140 Pore Volume Injected, % PV Jectent Is - tean cAs+ cu:tent Compositional Blend- 10%Enriching FluidEnriching Fluid- 203 Enriching Fluid Figure 4: Simulated Recovery versus PV Injected 160 CPAI Application for Pool Rules February 28, 2018 Page 14 of 34 5. DRILLING Drilling/Well Design The LOP 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. To mitigate borehole instability problems in the shales just above the reservoir, a four -hole section well design is planned. Maintaining stability of the borehole and horizontal geo-steering in the pay zone are keys to success. Figure 5 on the following page illustrates a generic Lookout producer well schematic, which is also similar to the planned injectors. For proper anchorage and to divert an uncontrolled flow, 80 feet of conductor casing will either be drilled or driven on 20 foot well centers and cemented to surface. Cement returns will be verified by visual inspection. Surface holes will be drilled and casing set below the C40 marker in the Colville Group for proper anchorage and protection from permafrost thaw and freeze back. Within the planned development area, the base of permafrost is interpreted to be approximately 800-1,200 ft. 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) The intermediate hole will be drilled in two intervals. Both sections will be directionally drilled with the first casing point being the Fish Creek Slump shales and the second casing point at approximately 85 degrees inclination just above, or just into the Alpine C sand. After drilling out both the intermediate casing and liner shoes, an FIT will be performed in accordance with 20 AAC 25.030(f). The intermediate #1 section between the proposed surface casing shoe and the top of the Fish Creek Slump Shales 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 if any hydrocarbon bearing formations are encountered in accordance with 20 AAC 25.030(d)(5). The intermediate #2 section from the Fish Creek Slumps to the Alpine C sand will be drilled via steerable drilling liner (the liner is carried into hole behind a directional drilling and logging pilot assembly that is retrieved prior to cementing). Managed pressure drilling (MPD) may also be used to minimize borehole pressure cycling and provide sufficient overbalance to hold back the mechanically unstable shale formations. The liner top of cement will extend a minimum of 500 feet measured depth or 250 feet true vertical depth, whichever is greater, above the Alpine C sand in accordance with 20 AAC 25.030(d)(5) or higher based on the production packer setting depth. Based on current knowledge of reservoir characteristics, CPAI expects to develop the LOP using horizontal wells with solid liners including pre -perforated pups. External swell packers may be added to isolate out of pay excursions and / or fault crossings along the lateral. Multi -lateral or other completion methods may be employed as conditions dictate. Both injection and production wells will be completed with 4-1/2 inch tubing to minimize hydraulic friction. CPAI Application for Pool Rules February 28, 2018 Page 15 of 34 TOC at least 300' above Packer 8 50 above Alpine C Top Al pir 7" Liner 6" Hole 5000 —12000 ft horizontal Figure 5: Proposed Lookout Producer Well Schematic Drilling Fluids The drilling fluid program designed for wells within the LOP 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 two exploration wells drilled into the Lookout pool. Water based muds will be used for the surface and two intermediate hole sections and mineral oil based drill -in fluid (DIF) will be used for the horizontal hole in the reservoir. "[ 20" Insulated Conductor Tubing /Liner Completion: kL 80 feet, cemented to surface 1) 4'/:" Landing Nipple (3.813" ID) 2) 4-X"x1"GLM 3) 4-%"x1"GLM ii 4) Liner Top Packer l Hanger 5) 4-12° x V GLM 13-3/3" Surface Casing 6) Liner Top Packer l Hanger cemented to surface w/ Tie Back sleeve GL Oz 7) 4-%' Landing Nipple (3.725" NoGo) 8) 4-h° Blank Pipe 9) 4-%." Liner with Perf Pups 4-112" Tubing 0 GL O 95/8" Casing TOC at least 500' above shoe TOC at least 300' above Packer 8 50 above Alpine C Top Al pir 7" Liner 6" Hole 5000 —12000 ft horizontal Figure 5: Proposed Lookout Producer Well Schematic Drilling Fluids The drilling fluid program designed for wells within the LOP 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 two exploration wells drilled into the Lookout pool. Water based muds will be used for the surface and two intermediate hole sections and mineral oil based drill -in fluid (DIF) will be used for the horizontal hole in the reservoir. CPAI Application for Pool Rules February 28, 2018 Page 16 of 34 Annular Disposal Disposal of drilling wastes will be proposed for GMT1 in accordance with 20 AAC 25.080 in annuli of wells with surface casing set below the permafrost. 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). Subsequently, CPA] applied for approval of annular disposal for its CD5 wells, and those applications were approved. Annular disposal is being implemented at the Lookout Oil Pool for environmental, operational and economic reasons and is in conformance with the 2004 Environmental Impact Statement, as supplemented in 2015, covering the GMT1 Project. The proposed annular disposal interval will be the C-30 and deeper in the Late Cretaceous age Seabee Formation (Figure 6). This interval contains over 2300 feet TVD of interbedded sandstone and shale and correlates to the same horizon utilized on drillsites in Colville River Unit (Alpine Field). Surface casing will be set 10-20 feet above the C-30 marker. The upper confining barrier is composed of 900 feet TVD of shale and siltstone of the Upper Cretaceous Schrader Bluff Formation. Approximately 1100 feet TVD of permafrost overlies the Schrader Bluff. The lower barrier is composed of 1700 feet TVD of shale and siltstone of the Torok Formation. No fresh water sands have been encountered in GMTU exploration wells as further described in Appendix 2 — Formation Water Salinity. CPAI requests a finding in the LOP Orders that no freshwater aquifers are present in the LOP area. This request is to avoid duplicative reviews of whether there are fresh water aquifers in the LOP 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 LOP 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 LOP because the proposed horizontal well development, via line -drive flood pattern, will yield greater recovery than a conventional vertical/slant well development plan with a minimum spacing rule. In lieu of the requirements under 20 AAC 25.055, CPAI proposes that there shall be no restrictions as to well spacing except that no pay shall be opened to a well within 500 feet of an external property line where the owners and landowners are not the same on both sides of the line. CPAI Application for Pool Rules February 28, 2018 Page 17 of 34 Figure 6: Annular Disposal Interval - C-30 'I N w 500'-600' - Annular Mudstone Barrier - Disposal .... m N Oy O _ v� iD - iso a o - e� $ $ e e o e 0 a 0 0 o a 0 0 0 0 0 o 0 0 0 0 0 0 0 0 0 0 w v m m n ry n r rmi m N J R 500'-600' nulOONNar K V Mudstone Barrie Disposal l Ca a- Tai r -i I WG FQY8 a WWVR J ka Om^ D-�D• OOw OOw OO� OOOP OOmw OOONM OONOyS O CO .I v! ) CU. a4OOnn_ O I 2 o Annular — Lu Disposa I N Wa m — _71 0 o N Z E U tI F�i.•�9 ,,. v. a N I o o ery D eo e u o S g $ $ e o e e 8 e Oo o n e n w n n n en n n n n n pajepijosuo p9jepljosuo3 AlleaM Figure 6: Annular Disposal Interval - C-30 CPAI Application for Pool Rules February 28, 2018 Page 18 of 34 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. When needed, a single packer will provide pressure isolation for the tubing -casing annulus. Wells with liners placed in the horizontal segments may utilize combination liner hanger/packers. Artificial Lift Artificial lift will be via gas lift; however, CPAI may employ other techniques Qet pump, electrical submersible pumps, etc.) to optimize reservoir pressure drawdown as the reservoir matures. Dry gas will be delivered to the drillsite at approximately 4000 psi and the pressure will be dropped down to approximately 2000 psi for the purposes of gas lift. Reservoir Surveillance CPAI requests that the 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 -7,850 ft. TVDSS. Well Work Operations Well work operations in the LOP 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 Although stimulation is not currently anticipated for LOP wells due to the high reservoir quality, stimulation techniques, including hydraulic fracturing, may be used to enhance well rates. Wellbore trajectories, cementing programs, and tubulars will be designed to accommodate hydraulic fracture stimulation techniques. Hydraulic stimulation operations will be performed in accordance with 20 AAC 25.283. Surface Safety Valves GMT1 wells will be equipped with horizontal trees. With this configuration, the surface safety valve and master valve are in the horizontal run of the well's tree. This configuration is employed in CRU wells and improves rig/well interventions while not presenting any significant increase in risk. In Docket Number OTH-17-012, CPAI received Commission approval on June 8, 2017 for a variance from 20 AAC 25.265(c)(1) for GMT1 wells to allow surface safety valves in the horizontal run of the tree rather than the vertical run as specified in the regulation. CPAI Application for Pool Rules February 28, 2018 Page 19 of 34 Required periodic inspections and testing will be conducted following notification of the Commission 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. CPAI 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 February 28, 2018 Page 20 of 34 7. FACILITIES Drill Site Facilities and Flowlines The LOP will be developed from the new MT6 drillsite which will connect to the ACF for production processing and delivery of dry gas, enriched gas, water and electricity. See Figure 7. MT6 is a 'not normally manned' drillsite; however, drillsite operators will be present on the drillsite every day except in extreme weather or other circumstances. The MT6 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 MT6: • 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 9 wells on 20 -foot center spacing • Modules for ESD, Pigging, Fuel Gas, Chemical Injection, 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 to the production separator. At the outlet of the production separator, the total drillsite oil, water and gas streams are measured prior to being commingled again in a new 20" cross-country flowline to CD5 where GMTU production is commingled with CRU production and flows on to the ACF. Injection wells selectively connect to either the water injection header or the enriched gas injection header. Water injection arrives via a new 14" flowline connecting both MT6 and CD5 drillsites to the ACF. Expected water injection arrival pressure at MT6 is approximately 2650 psi. Enriched gas injection arrives via a new 6" flowline connecting MT6 to the existing flowline at CD5. Expected enriched gas arrival pressure at MT6 is approximately 4000 psi. The pipeline rates of both dry gas and enriched gas are measured at the CD5 pad prior to arriving at the MT6 drillsite. Production Processing Lookout production will be commingled with production from other CRU pools prior to processing at ACF. Stabilized oil production will be delivered to the Alpine Pipeline and then on to TAPS. Lookout and CRU wells connected to the ACF will be managed and prioritized to maximize oil production rate in conformance with any facility limits. Lookout gas production will be processed in the ACF. Lookout will provide its share of ACF fuel and flare requirements and some gas will be returned to Lookout in the form of either dry gas for gas lift and drillsite fuel or in the form of enriched gas for enhanced recovery purposes. When Lookout gas production is greater than Lookout gas usage requirements, this excess gas production will be injected into CRU pools for enhanced recovery purposes. On a cumulative basis, Lookout gas production is expected to be greater than Lookout 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 Lookout wells, and possibly for startup, that Lookout gas production is less than, or deficient from, Lookout gas requirements, and a sale of gas from CRU to Lookout will be required to cover the deficiency. Coincident with this application, an application to the Commission is being made for CRU gas offtake to authorize CRU gas being sold for Lookout operations on an as needed basis. The initial plan is to provide seawater to Lookout for injection to maintain reservoir pressure and enhance oil recovery. In the future, produced water from the ACF may also be injected at Lookout. CPAI Application for Pool Rules February 28, 2018 Page 21 of 34 Lookout water production is expected to be very low until breakthrough of water injection occurs. Lookout 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 LOP. Coincident with this application, an application to the Commission is being made to expand rules for several CRU pools to allow injection of Lookout water in those pools. LOP production is expected to be fully compatible with production from other CRU pools from both a production processing and injection perspective. Lookout oil and gas production compositions and characteristics are expected to be similar to the Alpine Pool and fully compatible with all CRU pools. The LOP is a very close analog to the Alpine Oil Pool because both pools share a similar geologic history with the same oil charge source (Lower Kingak) and rock deposition source (Alpine A and B). Lookout water production will be a mixture of Lookout connate water and seawater or ACF produced water and it is not expected to be significantly different than Alpine Pool produced water and therefore should be fully compatible with all CRU pools. Application of scale inhibitors, corrosion inhibitors and any other production treatments at Lookout will be similar to those at other CRU pools. Metering CPAI previously applied to the Commission for approval of its approach to GMT1 production measurement. The Commission ruled on CPAI's application in Other Orders 112 and 112A. Consistent with those orders, metering points for production, injection, fuel and gas -lift are shown in Figure 7. More specific metering details for production custody transfer of oil and gas have been provided in the GMT1 Production Separator Metering Application submitted to the AOGCC on October 9, 2017. 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 112 dated October 12, 2016, Other Order 112A dated December 22, 2016, and BLM Sundry Approval for Measurement by Other Methods dated October 14, 2016, LOP production will receive an allocation factor of one (1.0). Production allocation to individual production wells in the LOP 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 LOP 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 February 28, 2018 Page 22 of 34 GMT Unit : Colville River Unit Lookout Oil Pool -------------- 1 Production Pipeline to CD5 and ACF Gas lift meter on each producer Four Production Wells Lookout Gas Meters at CD5 Injection meter on each injection well Five Injection Wells Figure 7: GMT1 Facilities and Metering Other CRU Drillsites Alpine Central __� Oil Sales to Facility Alpine Pipeline CDS Seawater Production CD5 Injection E n a TTS a 3 CPAI Application for Pool Rules February 28, 2018 Page 23 of 34 8. PROPOSED LOOKOUT OIL POOL RULES The rules set forth apply to the following area referred to in this order: vT11N, R2E Section 13-14 all Section 23-24 all Section 25-26 all Section 35-36 all T11N, R3E Section 17-19 all Section 29-32 all T1 ON, R2E Section 1 all Section 2 NE 1/4 T1 ON, R3E Section 6 all Rule 7 - Field and Pool Name The field is the Greater Mooses Tooth Field. Hydrocarbons underlying the affected area and within the herein defined intervals of the Kingak formation constitute the oil reservoir named the Lookout Oil Pool. Rule 2 - Pool Definition The Lookout Oil Pool is the accumulation of hydrocarbons common to, and correlating with, the interval between the measured depths of 7,833' and 8,000' in the Lookout No. 1 exploration 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 Lookout Oil Pool 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 Safety Valve Systems a. Surface safety valves located within the horizontal run of a well's tree satisfy the requirements of 20 AAC 25.265 (c)(1). b. Water and gas injection wells (except disposal) must meet the requirements of 20 AAC 25.265 (d) (5). Rule 6 - Reservoir Pressure Monitoring a. A bottom -hole pressure survey shall be taken on each well prior to initial production or 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 9, 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 -7,850 ft. 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 CPAI Application for Pool Rules February 28, 2018 Page 24 of 34 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 Lookout Oil Pool 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 Lookout Oil Pool 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 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 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. f. 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. CPAI Application for Pool Rules February 28, 2018 Page 25 of 34 g. 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 Lookout Oil Pool may be commingled on the surface with production from the other pools within the Greater Mooses Tooth Unit as well as with production from the Colville River Unit. b. Wells must be tested monthly. Rule 11 Administrative Action Upon proper application, or its own motion, and unless notice and public hearing are otherwise required, the Commission my 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 February 28, 2018 Page 26 of 34 Appendix 2 — Formation Water Salinity Salinity Calculations In the Greater Mooses Tooth Unit, Lookout Field 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. Sands penetrated include: K-3, Albian 97, Albian 96, Albian 95, Albian 94, Albian 93 and Albian 92 with depths ranging from 2300 ft to 4600 ft TVDSS. Salinity calculations made on the available intervals resulted in the following. Well Stratigraphic Zone Depth TDS Mitre 1BP1 C-40 1700-1860 ft 31,000ppm Mitre1PB1 C-30 2248-2276 ft 27,000ppm Tirimiaq 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 Rendezvous 3 Albian 94 3916-4045 ft 13,000ppm Tigmiaq 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 an 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 CD2 -11 Qannik well. This Qannik well is the analog for the wells used for this study. Formation data from the CD2 -11 shows m to be 1.8, hence range of 1.8-2.0 was used for the analysis that follows. For very shallow unconsolidated formation intervals, C40 and C30, an m value of 2 was used in the calculations. Well: Mitre 1PB1 Formation: C40 (Well depth 1700-1860ft) Calculation: Rt is taken from LWD resistivity tool and Porosity comes from the density log Rt = 1.86ohm-m, Raw density = 2.01g/cc, m = 2, Porosity = (2.65-2.01)/(2.65-1) = 0.388v/v. The calculation yields an 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. CPA] Application for Pool Rules February 28, 2018 Page 27 of 34 The calculation yields an Rwa equal to 0.267. Using chart Gen -9 from Schlumberger chart books with a formation temperature of 62degF, gives a salinity of 27,000 ppm NaCl equivalent. Well: Tinmiaq 2 Formation: K3 (Well depth 2380-2500ft) Calculation: Rt is taken from Array Induction tool and Porosity comes from the density log. Rt = 3.75ohm-m, Raw density = 2.15g/cc, m =1.8, Porosity = (2.65-2.15)/(2.65-1) = 0.303v/v. The calculation yields an 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 an 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 an 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 an 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 an Rwa equal to 0.310. Using chart Gen -9 from Schlumberger chart books with a formation temperature of 89.7degF, gives a salinity of 16,000 ppm NaCl equivalent. Well: Rendezvous 3 Formation: Albian 94 (Well depth 3916-4045ft) Calculation: Rt is taken from LWD resistivity tool and Porosity comes from the density log Rt = 6.05ohm-m, Raw density = 2.31g/cc, m =1.8, Porosity = (2.65-2.31)/(2.65-1) = 0.206v/v. The calculation yields an 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. CPAI Application for Pool Rules February 28, 2018 Page 28 of 34 The calculation yields an 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. Water sample Analyses A water sample was obtained from Tigmiaq 6 well during a production test. The tested interval is 3440- 3460ft (Albian 93 interval) and lab measured salinity is 15,000ppm (conductivity of 25200ps/cm). Lookout Area Type Log — Shallow Salinity Analysis Summary Lookout No. 1 Log 16,000ppm 13,000ppm C-30 Albian 96 Albian 95 Albian 94 300 600 500 900 i000 120 1500 1800 2000- 2100 2700 3000 300° 3500 LIZ., 6300 6900 1 70DO 7200 750oV.7, 12612 Prince Creek Sands Base Permafrost Coleville Group (Clay with interbedded silt & minor sands) Nanushuk Group (K-3 to Albian 95; Top -sets, shallow marine, silts/shales and thin fine grained sands) Torok (Albian slope & deep marine shales with inter -bedded sands) FCS Fill (Base of slope turbidite sands and silts) HRZ/Kalubik/Miluveach Shales Alpine C Sandstone (Target) CPA[ Application for Pool Rules February 28, 2018 Page 30 of 34 Appendix 3 — Annular Disposal of Drilling Waste at CD5 Misty Alexa WNS Dovelopment Manager P.O. Box 100360 Anchorago, AK 99510 (907)2856822(phone) ConocoPhillips misty.J. atoxa wcorwcophittq+s.com November 7, 2014 Hand Delivered 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: ConocoPhillips, as operator of the Colville River Unit (CRU) on the North Slope, Is engaged in the development of a new drillsite, called CD5. This new developmentwill 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 C05 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 February 28, 2018 Page 31 of 34 with past practice at other CRU drillsites. If future permitting for annular disposal at CDs 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 Il 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 if 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)j; (B) cause drilling waste to surface; (C) 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 for years. It has allowed for the efficient placement of drilling waste in a manner that avoids the use of CPA[ Application for Pool Rules February 28, 2018 Page 32 of 34 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 disposal 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 CD5 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 oilfield 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 if the operator expects to initiate routine disposal of drilling waste into the approved Class 11 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 SHIP 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 CD5 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 February 28, 2018 Page 33 of 34 However, if the AOGCC intends to treat an annular disposal request for CD5 differently than such requests have been treated for other CRU pads, then ConocoPhillips 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. ConocoPhillips 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, Mistyy Alexa WNS Development Manager cc: Anadarko E&P LLC CPAI Application for Pool Rules February 28, 2018 Page 34 of 34 Appendix 4 — Docket OTH 14-026 Annular Disposal of Drilling Waste at CD5 '1'l u: srAre of..AXLASKA. GONINNOR 1311.1. WALKER Ms. Misty J Alexa WNS Development Manager ConocoPhillips Alaska, Inc. P.O. Box 100360 Anchorage, AK 99510-0360 January 16, 2015 CERTIFIED MAIL — RETURN RECEIPT REQUESTED 7012 3050 00014812 7058 Re: Docket OTI-I 14-026 Annular Disposal of Drilling Waste at CD5 Dear Ms. Alexa: Alaska Oil and Gas Conservation Conunissiou 333 WeU Seventh Avenue; Atwbomfla, Alasl:o 91/501 -357 2 Main: 907.279.1433 Fox: 907.176.7542 :v.v W.na{Il'l;.l AaS::a.00v 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 Gil and Gas Conservation Commission (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. 1119 4e-1911� Cath '. Foerster Chaff , Commissioner