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Home My WebLink AboutAIO 040AREA INJECTION ORDER 40 Docket Number: AIO -19-013 Pool Rules, Greater Moose’s Tooth 1. February 28, 2018 ConocoPhillips Alaska, LLC application for Area Injection Order for Greater Moose’s Tooth (Appendix 1 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 6. October 15, 2021 Application to continue water-only injection for MT6-09 (PTD 218-134) 7. April 23, 2021 Request for administrative amendments to Lookout Oil Pool (AIO 40.002) 8. December 1, 2021 Emails between CPAI and AOGCC 9. May 26, 2021 CPAI request to reinstate AIO 18A with modifications (AIO 40.003) 10. July 22, 2022 Request to cancel Area Injection Order (AIO 40.001 Canceled) 11. January 15, 2025 AIO 7 Proposed language change (AIO 40.005) ORDERS STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION 333 West 7th Avenue Anchorage Alaska 99501 Re: THE APPLICATION OF ConocoPhillips ) Docket Number: AIO-18-013 Alaska, Inc. for an order authorizing underground ) Area hijection Order No. 40 injection of fluids for enhanced oil recovery in 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 -Lookout Oil Pool North Slope Borough, Alaska May 29, 2018 IT APPEARING THAT: 1. By application received February 28, 2018, ConocoPhillips Alaska, Inc. (CPAs, as operator of the Greater Moose's Tooth Unit (GMTU) and on behalf of the Working Interest Owners (WIOs), requested an order authorizing underground injection of fluids for enhanced oil recovery purposes in the proposed Lookout Oil Pool (LOP), within the GMTV. 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 arc the working intcrest owners. 2. Operator: CPAI is operator of the leases in the proposed Affected Area, which is 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 (CRU), which is operated by CPAI. 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 1 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 400 API. At the time of the application, sale of Anadarko's leasehold interest to CPAI was pending government approval. AIO 40 May 29, 2018 Page 2 of 9 i 12NR2E i i ct i w i zl l--' j 1 3P. • �j �.� 1 1 1 Greater i Mooses22 - 1 Tooth Unit :BA; 1 i LOOK OUT2 1 22 2% 1 E 1 i Colvil to, oUT'i� - ------ River toA� Unit N 15 14 13 I — o os t is z (23 i Miles Figure 1. Proposed Affected Area F11NR3E i i MT6 Well Pad Q Proposed Lookout Oil Pool Boundary Q Lookout Reservoir Q Proposed Lookout Participating Area ® Kuukpik Surface ASRC Subsurface U GMTU Tracts k . j Unit Boundaries CPAI Leases ConocoPhillips Proposed Lookout Oil Pool 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. AIO 40 May 29, 2018 Page 3 of 9 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 A1O 40 May 29, 2018 Page 4 of 9 6. Geology: a. Stratigraphy: CPAI's proposed LOP consists of late Jurassic -aged shelf deposits comprised of 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 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 Greater Moose's Tooth Unit, 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. AIO 40 May 29, 2018 Page 5 of 9 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: 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) Hydrocarbon Resources Estimated Volume (MMSTB) Original Oil in Place (OOIP) 70-150 Primary Recovery (20% OOIP) 14-30 Primary+ Waterflood (45% OOIP) 31-67 Primary + Waterflood + EWAG (60% OOIP) 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 assist 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. Wellbore Design: 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 fust 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 and well branches with uncemented solid liners including pre -perforated pups. External swell packers may be used to isolate out -of - pay excursions and fault crossings. Both injection and production wells will likely be completed with 4-'/z 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. To facilitate wireline access on the highly deviated injection wells, CPAI proposes to install packer/isolation equipment more than 200 feet MD above the top of the injection interval. The packer/isolation equipment would not be installed above the upper confining interval, and the outer casing will be cemented with a sufficient volume of cement to ensure that cement extends a minimum of 300 feet MD above the packer/isolation equipment. 13. 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 AIO 40 May 29, 2018 Page 6 of 9 balanced to maintain reservoir pressure at or near the original measured pressure. Development will target a 1.0 voidage-replacement ratio. 14. Proposed Injection Fluids: CPAI proposes that the following fluids be authorized for injection into the LOP for EOR purposes: a. Source water from the Kuparuk seawater treatment plant; b. Produced water from all present and yet -to -be defined oil pools within the GMTU and CRU; c. Enriched hydrocarbon gas (blend of CRU and GMTU lean gas enriched with indigenous heavy gas components); d. Lean gas from the Alpine Central Facility; e. Fluids used during hydraulic stimulation; f. Tracer survey fluids to monitor reservoir performance (chemical, radioactive, etc.); g. Fluids used to improve near wellbore injectivity (acid or similar treatment); h. Fluids used to seal wellbore intervals which negatively impact recovery efficiency (cement, resin, etc.); i. Fluids associated with freeze protection (diesel, crude, glycol, methanol, etc.); and j. Standard oilfield chemicals (corrosion inhibitor, scale inhibitor, etc.). 15. Fluid Compatibility: The primary and miscellaneous fluids listed above are expected to be compatible with the LOP as has been shown by performance in the adjacent and analogous Alpine Oil Pool. 16. Scale Deposition: Moderate scale formation in the production wells has been experienced in the CRU due to the mixing of seawater and connate formation water. It is possible this could occur in the LOP producers as well, and scale inhibition treatments will be performed as necessary. 17. Injection Volumes: Injection volume will be managed to maintain the voidage-replacement ratio in the LOP at approximately 1:1. Total fluid -injection rates are anticipated to range between 10 and 25 thousand barrels of water per day and 5 to 25 million cubic feet of gas per day. 18. Injection Pressures: Injection pressure will be managed to prevent the injection -pressure gradient from exceeding 0.81 psi/ft to ensure fractures are not initiated or propagated in the confining intervals. Due to pump and compressor limitations at the ACF and fictional losses in the pipelines, the maximum surface injection pressure is anticipated not to exceed 2,650 psi for water and 4,000 psi for gas. 19. Fracture modelling: Fracture -gradient analysis calibrated with rock mechanical properties from core data and leak -off tests in the upper confining interval indicate that the fracture gradient exceeds 0.85 psi/ft. 20. Formation Water Ouality: An analysis of the formation water is not possible, because, to date, it has not been encountered within the LOP. 21. Confinement in Offset Wells: The Lookout -1 and Lookout -2 wells were drilled within the proposed affected area. Lookout -2 was drilled, completed, tested, and plugged and abandoned in the spring of 2002. The Lookout -1 well is currently suspended with a downhole plug set in the tubing. 22. Waivers: CPAI requested a waiver of the injection well packer setting depth requirements of 20 AAC 25.412(b), which requires a packer be set within 200 feet MD of the top of the perforated/open injection interval. Due to the highly deviated nature of the proposed injection wells complying with the packer setting depth regulation would preclude accessing the packer/isolation equipment with wire line tools. CPAI requests a waiver to allow the packer/isolation equipment to be set more than 200 feet MD above the injection interval but not above the overlying confining interval and AIO 40 May 29, 2018 Page 7 of 9 that the outer casing would be cemented with a sufficient volume of cement to ensure a minimum of 300 feet MD of cement is above the packer/isolation equipment setting depth. CONCLUSIONS: 1. An Area Injection Order is necessary for the proposed development of the LOP to allow for enhanced oil recovery injection operations. 2. Reservoir simulation results show that an enriched water -alternating -gas injection project will significantly improve reserves recovery from the pool vs. primary and secondary recovery. 3. A waiver of the requirements of 20 AAC 25.412(b) to allow the packer/isolation equipment to be installed more than 200 feet MD above the perforated injection interval will provide for improved wellbore operations and not increase the risk of a loss of containment in the injection wells. 4. Reservoir voidage will be maintained at a replacement ratio of approximately 1:1. 5. Maintaining the sandface injection pressure gradient at or below 0.81 psi/ft will prevent fractures from forming or propagating in the confining intervals. 6. There are no freshwater aquifers in the Affected Area of the LOP. NOW THEREFORE IT IS ORDERED: The underground injection of fluids for pressure maintenance and enhanced recovery is authorized in the following area, subject to the following rules and 20 AAC 25, to the extent not superseded by these rules: Affected Area: Umiat Meridian (See Figure 1) Rule 1 Authorized Infection Strata for Enhanced Recovery Fluids authorized under Rule 3, below, may be injected for the purposes of pressure maintenance and enhanced hydrocarbon recovery within the Affected Area defined above into strata that are common to, and correlate with, the interval within the Lookout -1 well between the measured depths of 7,833 and 8,000 feet on the resistivity log. Rule 2 Well Construction In lieu of the packer depth requirements under 20 AAC 25.412(b), the packer/isolation equipment depth for injection wells may be located above 200 feet measured depth from above the top of the perforations/open interval, but shall not be located above the confining zone and shall have outer casing cement volume sufficient to place a minimum of 300 feet measured depth above the planned packer depth. Sections 13-14: All Township 11 North, Range 2 East Sections 23-26: All Sections 35-36: All Sections 17-19: All Township 11 North, Range 3 East Sections 29-32: All Section 1: All Township 10 North, Range 2 East Section Z: NEI/4 Township 10 North, Range 3 East Section 6: All Rule 1 Authorized Infection Strata for Enhanced Recovery Fluids authorized under Rule 3, below, may be injected for the purposes of pressure maintenance and enhanced hydrocarbon recovery within the Affected Area defined above into strata that are common to, and correlate with, the interval within the Lookout -1 well between the measured depths of 7,833 and 8,000 feet on the resistivity log. Rule 2 Well Construction In lieu of the packer depth requirements under 20 AAC 25.412(b), the packer/isolation equipment depth for injection wells may be located above 200 feet measured depth from above the top of the perforations/open interval, but shall not be located above the confining zone and shall have outer casing cement volume sufficient to place a minimum of 300 feet measured depth above the planned packer depth. A10 40 May 29, 2018 Page 8 of 9 Rule 3 Authorized Fluids for Iniection for Enhanced Recovery Fluids authorized for injection are: a. Source water from the Kuparuk seawater treatment plant; b. Produced water from all present and yet -to -be defined oil pools within the GMTU and CRU; c. Enriched hydrocarbon gas (blend of CRU and GMTU lean gas enriched with indigenous heavy gas components); d. Lean gas from the Alpine Central Facility; e. Tracer survey fluids to monitor reservoir performance; f. Fluids used to improve near wellbore injectivity; g. Fluids used to seal wellbore intervals which negatively impact recovery efficiency; h. Fluids associated with freeze protection; and i. Standard oilfield chemicals. Rule 4 Authorized Iniection Pressure for Enhanced Recove Injection pressures will be managed as not to exceed the maximum injection gradient of 0.81 psi/ft to ensure containment of injected fluids within the defined affected area and injection interval. Rule 5 Monitoring Tubing -Casing Annulus Pressure Inner and outer annulus pressure shall be monitored each day for all injection and production wells. Inner annulus, outer annulus, and tubing pressure shall be constantly monitored and recorded 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 V4 -mile radius of a Lookout Oil Pool injector shall be monitored daily. All monitoring results shall be documented and available for AOGCC inspection. Rule 6 Demonstration of Tubing/Casine Annulus Mechanical Integrity The mechanical integrity of each injection well must be demonstrated before injection begins and before returning a well to service following any workover affecting mechanical integrity. An AOGCC-witnessed MIT must be performed after injection is commenced for the fust time in a well, to be scheduled when injection conditions (temperature, pressure, rate, etc.) have stabilized. Subsequent tests must be performed at least once every four years thereafter. The AOGCC must be notified at least 24 hours in advance to enable a representative to witness an MIT. Unless an alternate means is approved by the AOGCC, mechanical integrity must be demonstrated by a tubing/casing annulus pressure test using a surface pressure of 1,500 psi or 0.25 psi/ft multiplied by the vertical depth of the packer, whichever is greater, that shows stabilizing pressure and does not change more than 10 percent during a 30 -minute period. Results of MLTs must be readily available for AOGCC inspection. Rule 7 Well Integrity and Confinement Whenever any pressure communication, leakage or lack of injection zone isolation is indicated by an injection rate, operating pressure observation, test, survey, log, or any other evidence (including outer annulus pressure monitoring of all wells within a one-quarter mile radius of where the Kuparuk River - Torok Oil Pool is not cemented), the Operator shall notify the AOGCC by the next business day and submit a plan of corrective action on a Form 10-403 for AOGCC approval. The Operator shall immediately shut in the well if continued operation would be unsafe or would threaten contamination of freshwater. A monthly report of daily tubing and casing annuli pressures and injection rates must be provided to the AOGCC for all injection wells for which well integrity failure or lack of injection zone isolation is indicated. AIO 40 May 29, 2018 Page 9 of 9 Rule 8 Notification of Improper Class 11 Iniection Injection of fluids other than those listed in Rule 3 without prior authorization is considered improper Class H injection. Upon discovery of such an event, the operator must immediately notify the AOGCC, provide details of the operation, and propose actions to prevent recurrence. This requirement is in addition to and does not relieve the operator of any other obligations under the notification requirements of any other State or Federal agency, regulation or law. Rule 9 Other Conditions If fluids are found to be fracturing the confining zone or migrating out of the approved injection stratum, the Operator must immediately shut in the injection wells and immediately notify the AOGCC. Injection may not be restarted unless approved by the AOGCC. Rule 10 Administrative Action Upon proper application, or its own motion, and unless notice and public hearing are otherwise required, the AOGCC may administratively waive the requirements of any rule stated herein or administratively amend this order as long as the change does not promote waste or jeopardize correlative rights, is based on sound engineering and geoscience principles, and will not result in an increased risk of fluid movement into freshwater. DONE at Anchorage, Alaska and dated May 29, 2018. Hollis S. FrenchT. mount, Jr. th}. koers oIL4A Chair, Commissioner Co Issioner ommission .GI✓Y 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 asilni, 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 he 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. N 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 an61 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: A10- 18-013 Alaska, Inc. for an order authorizing underground ) Area Injection Order No. 40 injection of fluids for enhanced oil recovery in 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 -Lookout Oil 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 (GMTV) and on behalf of the Working Interest Owners (WIOs), requested an order authorizing underground injection of fluids for enhanced oil recovery purposes in the proposed Lookout Oil Pool (LOP), within the GMTU. 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. Overator: CPAI is operator of the leases in the proposed Affected Area, which is 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 (CRU), which is operated by CPAI. 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.). ht 2002, CPAI drilled and tested the Lookout -2 exploratory well that lies 1 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. 1 At the time of the application, sale of Anadarko's leasehold interest to CPAI was pending government approval. AIO 40 May 29, 2018 Page 2 of 9 6 +n n 12 1 ZI j _ 1 1 ~ 1 1 i 1 i j j ie 1 j .•....... ......... Greater 1 Mooses 1 Tooth Unit i 9a \ \\ ! \� 1 `--- 1 LOOK\` 2\ \ 1 ax Golub �ioolcouri - - ---- ---- -----j- River 'en' j Unit ]3 j i 11NR3E MITRE 1, Y,1 T5 MTB well Ped a d Q Proposed Lookout Oil Pool Boundary Q lookout Reservoir Q Proposed Lookout Participating Area ® Kuukpik Surface ASRC Subsurface W W U GMTU Tracts n tz O,� Unit Boundaries Z 5�.1 o; o CPAI Leases N Conoco Phillips I5r< Alaska is Proposed Lookout — o os 1 1.5 2 Oil Pool Area Miles 112 512 01 0 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 -I lies outside of he LOP. AIO 40 May 29, 2018 Page 3 of 9 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. CPA] 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 AIO 40 May 29, 2018 Page 4 of 9 6. Geology: a. Stratigraphy: CPAI's proposed LOP consists of late Jurassic -aged shelf deposits comprised of 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 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. 7. 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 Greater Moose's Tooth Unit, 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. AIO 40 May 29, 2018 Page 5 of 9 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: 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) Hydrocarbon Resources Estimated Volume (MMSTB) Original Oil in Place (OOIP) 70-150 Primary Recovery (20% OOIP) 14-30 Primary + Waterflood (45% OOIP) 31-67 Primary+ Waterflood + EWAG (60% OOIP) 42-90 11. Reservoir Development Drilling Plan: CPAI currently plans to develop this oil reservoir from GM76 Drill Site utilizing four horizontal production and five horizontal injection wells with possible pilot holes providing additional reservoir data and assist 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. Wellbore Design: 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 and well branches with uncemented solid liners including pre -perforated pups. External swell packers may be used to isolate out -of - pay excursions and fault crossings. Both injection and production wells will likely be completed with 4-'/s 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. To facilitate wireline access on the highly deviated injection wells, CPAI proposes to install packer/isolation equipment more than 200 feet MD above the top of the injection interval. The packer/isolation equipment would not be installed above the upper confining interval, and the outer casing will be cemented with a sufficient volume of cement to ensure that cement extends a minimum of 300 feet MD above the packer/isolation equipment. 13. 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 AIO 40 May 29, 2018 Page 6 of 9 balanced to maintain reservoir pressure at or near the original measured pressure. Development will target a 1.0 voidage-replacement ratio. 14. Proposed Injection Fluids: CPAI proposes that the following fluids be authorized for injection into the LOP for EOR purposes: a. Source water from the Kuparuk seawater treatment plant; b. Produced water from all present and yet -to -be defined oil pools within the GMTU and CRU; c. Enriched hydrocarbon gas (blend of CRU and GMTU lean gas enriched with indigenous heavy gas components); d. Lean gas from the Alpine Central Facility; e. Fluids used during hydraulic stimulation; f. Tracer survey fluids to monitor reservoir performance (chemical, radioactive, etc.); g. Fluids used to improve near wellbore injectivity (acid or similar treatment); h. Fluids used to seal wellbore intervals which negatively impact recovery efficiency (cement, resin, etc.); i. Fluids associated with freeze protection (diesel, crude, glycol, methanol, etc.); and j. Standard oilfield chemicals (corrosion inhibitor, scale inhibitor, etc.). 15. Fluid Compatibility: The primary and miscellaneous fluids listed above are expected to be compatible with the LOP as has been shown by performance in the adjacent and analogous Alpine Oil Pool. 16. Scale Deposition: Moderate scale formation in the production wells has been experienced in the CRU due to the mixing of seawater and connate formation water. It is possible this could occur in the LOP producers as well, and scale inhibition treatments will be performed as necessary. 17. Injection Volumes: hrjection volume will be managed to maintain the voidage-replacement ratio in the LOP at approximately 1:1. Total fluid -injection rates are anticipated to range between 10 and 25 thousand barrels of water per day and 5 to 25 million cubic feet of gas per day. 18. Injection Pressures: Injection pressure will be managed to prevent the injection -pressure gradient from exceeding 0.81 psi/ft to ensure fractures are not initiated or propagated in the confining intervals. Due to pump and compressor limitations at the ACF and frictional losses in the pipelines, the maximum surface injection pressure is anticipated not to exceed 2,650 psi for water and 4,000 psi for gas. 19. Fracture modelling: Fracture -gradient analysis calibrated with rock mechanical properties from core data and leak -off tests in the upper confining interval indicate that the fracture gradient exceeds 0.85 psi/ft. 20. Formation Water Ouality: An analysis of the formation water is not possible, because, to date, it has not been encountered within the LOP. 21. Confinement in Offset Wells: The Lookout -1 and Lookout -2 wells were drilled within the proposed affected area. Lookout -2 was drilled, completed, tested, and plugged and abandoned in the spring of 2002. The Lookout -1 well is currently suspended with a downhole plug set in the tubing. 22. Waivers: CPAI requested a waiver of the injection well packer setting depth requirements of 20 AAC 25.412(b), which requires a packer be set within 200 feet MD of the top of the perforated/open injection interval. Due to the highly deviated nature of the proposed injection wells complying with the packer setting depth regulation would preclude accessing the packer/isolation equipment with wire line tools. CPAI requests a waiver to allow the packer/isolation equipment to be set more than 200 feet MD above the injection interval but not above the overlying confining interval and AIO 40 May 29, 2018 Page 7 of 9 that the outer casing would be cemented with a sufficient volume of cement to ensure a minimum of 300 feet MD of cement is above the packer/isolation equipment setting depth. CONCLUSIONS: 1. An Area Injection Order is necessary for the proposed development of the LOP to allow for enhanced oil recovery injection operations. 2. Reservoir simulation results show that an enriched water -alternating -gas injection project will significantly improve reserves recovery from the pool vs. primary and secondary recovery. 3. A waiver of the requirements of 20 AAC 25.412(b) to allow the packer/isolation equipment to be installed more than 200 feet MD above the perforated injection interval will provide for improved wellbore operations and not increase the risk of a loss of containment in the injection wells. 4. Reservoir voidage will be maintained at a replacement ratio of approximately 1:1. 5. Maintaining the sandface injection pressure gradient at or below 0.81 psi/ft will prevent fractures from forming or propagating in the confining intervals. 6. There are no freshwater aquifers in the Affected Area of the LOP. NOW THEREFORE IT IS ORDERED: The underground injection of fluids for pressure maintenance and enhanced recovery is authorized in the following area, subject to the following rules and 20 AAC 25, to the extent not superseded by these rules: Affected Area: Umiat Meridian (See Figure 1) Rule 1 Authorized Infection Strata for Enhanced Recovery Fluids authorized under Rule 3, below, may be injected for the purposes of pressure maintenance and enhanced hydrocarbon recovery within the Affected Area defined above into strata that are common to, and correlate with, the interval within the Lookout -1 well between the measured depths of 7,833 and 8,000 feet on the resistivity log. Rule 2 Well Construction In lieu of the packer depth requirements under 20 AAC 25.412(b), the packer/isolation equipment depth for injection wells may be located above 200 feet measured depth from above the top of the perforations/open interval, but shall not be located above the confining zone and shall have outer casing cement volume sufficient to place a minimum of 300 feet measured depth above the planned packer depth. Sections 13-14: All Township 11 North, Range 2 East Sections 23-26: All Sections 35-36: All Sections 17-19: All Township 11 North, Range 3 East Sections 29-32: All Section 1: All Township 10 North, Range 2 East Section 2: NEI/4 Township 10 North, Range 3 East Section 6: All Rule 1 Authorized Infection Strata for Enhanced Recovery Fluids authorized under Rule 3, below, may be injected for the purposes of pressure maintenance and enhanced hydrocarbon recovery within the Affected Area defined above into strata that are common to, and correlate with, the interval within the Lookout -1 well between the measured depths of 7,833 and 8,000 feet on the resistivity log. Rule 2 Well Construction In lieu of the packer depth requirements under 20 AAC 25.412(b), the packer/isolation equipment depth for injection wells may be located above 200 feet measured depth from above the top of the perforations/open interval, but shall not be located above the confining zone and shall have outer casing cement volume sufficient to place a minimum of 300 feet measured depth above the planned packer depth. AIO 40 May 29, 2018 Page 8 of 9 Rule 3 Authorized Fluids for Iniection for Enhanced Recovery Fluids authorized for injection are: a. Source water from the Kuparuk seawater treatment plant; b. Produced water from all present and yet -to -be defined oil pools within the GMTU and CRU; c. Enriched hydrocarbon gas (blend of CRU and GMTU lean gas enriched with indigenous heavy gas components); d. Lean gas from the Alpine Central Facility; e. Tracer survey fluids to monitor reservoir performance; f. Fluids used to improve near wellbore injectivity; g. Fluids used to seal wellbore intervals which negatively impact recovery efficiency; h. Fluids associated with freeze protection; and i. Standard oilfield chemicals. Rule 4 Authorized Infection Pressure for Enhanced Recovery Injection pressures will be managed as not to exceed the maximum injection gradient of 0.81 psi/ft to ensure containment of injected fluids within the defined affected area and injection interval. Rule 5 Monitorine Tubine-Casine Annulus Pressure Inner and outer annulus pressure shall be monitored each day for all injection and production wells. Inner annulus, outer annulus, and tubing pressure shall be constantly monitored and recorded 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. Rule 6 Demonstration of Tubine/Casine Annulus Mechanical Inteerity The mechanical integrity of each injection well must be demonstrated before injection begins and before returning a well to service following any workover affecting mechanical integrity. An AOGCC-witnessed MIT must be performed after injection is commenced for the first time in a well, to be scheduled when injection conditions (temperature, pressure, rate, etc.) have stabilized. Subsequent tests must be performed at least once every four years thereafter. The AOGCC must be notified at least 24 hours in advance to enable a representative to witness an MIT. Unless an alternate means is approved by the AOGCC, mechanical integrity must be demonstrated by a tubing/casing annulus pressure test using a surface pressure of 1,500 psi or 0.25 psi/ft multiplied by the vertical depth of the packer, whichever is greater, that shows stabilizing pressure and does not change more than 10 percent during a 30 -minute period. Results of MITs must be readily available for AOGCC inspection. Rule 7 Well Inteerity and Confinement Whenever any pressure communication, leakage or lack of injection zone isolation is indicated by an injection rate, operating pressure observation, test, survey, log, or any other evidence (including outer annulus pressure monitoring of all wells within a one-quarter mile radius of where the Kuparuk River - Torok Oil Pool is not cemented), the Operator shall notify the AOGCC by the next business day and submit a plan of corrective action on a Form 10403 for AOGCC approval. The Operator shall immediately shut in the well if continued operation would be unsafe or would threaten contamination of freshwater. A monthly report of daily tubing and casing annuli pressures and injection rates must be provided to the AOGCC for all injection wells for which well integrity failure or lack of injection zone isolation is indicated. AIO 40 May 29, 2018 Page 9 of 9 Rule 8 Notification of Improper Class II Injection Injection of fluids other than those listed in Rule 3 without prior authorization is considered improper Class II injection. Upon discovery of such an event, the operator must immediately notify the AOGCC, provide details of the operation, and propose actions to prevent recurrence. This requirement is in addition to and does not relieve the operator of any other obligations under the notification requirements of any other State or Federal agency, regulation or law. Rule 9 Other Conditions If fluids are found to be fracturing the confining zone or migrating out of the approved injection stratum, the Operator must immediately shut in the injection wells and immediately notify the AOGCC. Injection may not be restarted unless approved by the AOGCC. Rule 10 Administrative Action Upon proper application, or its own motion, and unless notice and public hearing are otherwise required, the AOGCC may administratively waive the requirements of any rule stated herein or administratively amend this order as long as the change does not promote waste or jeopardize correlative rights, is based on sound engineering and geoscience principles, and will not result in an increased risk of fluid movement into freshwater. 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 AND APPEAL 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 in 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 =a until 5:00 p.m. on the next day Colombie, Jody J (DOA) From: Colombie, Jody J (DOA) Sent: Tuesday, May 29, 2018 2:30 PM To: Bixby, Brian D (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; AKDCWeIIIntegrityCoordinator, Alan Bailey; Alex Demarban; Alicia Showalter; Allen Huckabay; Andrew Vandedack; 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 6im4thgn@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; 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); 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; Marie Steele; 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: AIO 40 (CPA) Attachments: aio40.pdf Please see attached. Re: THE APPLICATION OF ConocoPhillips Alaska, Inc. for an order authorizing underground injection of fluids for enhanced oil recovery in the proposed Lookout Oil Pool within the Greater Moose's Tooth Unit Jody J. Co(ombie AOGCC Speeia(Assistant A(aska OiCandGas Conservation Commission 333'West 711 Avenue Anchorage, ACaska 99501 Office: (907) 793-1221 Fax: (907) 276-7542 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 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®aloska.aov. Bernie Karl K&K Recycling Inc. P.O. Box 58055 Fairbanks, AK 99711 George Vaught, Jr. P.O. Box 13557 Denver, CO 80201-3557 Gordon Severson 3201 Westmar Cir. Anchorage, AK 99508-4336 Darwin Waldsmith P.O. Box 39309 Ninilchik, AK 99639 Penny Vadla 399 W. Riverview Ave. Soldotna, AK 99669-7714 Richard Wagner P.O. Box 60868 Fairbanks, AK 99706 MoLikd 5/29/2018 by Mcgafn Mitphtt 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 authorizing underground injection of fluids for enhanced oil recovery in the proposed Lookout Oil Pool within the Greater Moose's Tooth Unit IT APPEARING THAT: 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 1. By application received February 28, 2018, ConocoPhillips Alaska, Inc. (CPAs, as operator of the Greater Moose's Tooth Unit (GMTU) and on behalf of the Working Interest Owners (WIOs), requested an order authorizing underground injection of fluids for enhanced oil recovery purposes in the proposed Lookout Oil Pool (LOP), within the GMTU. 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. 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, which is 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 (CRU), which is operated by CPAI. LOP will be the first oil development that lies entirely within the National Petroleum Reserve—Alaska (NPR -A). 4. Exploration and Delineation Historv: 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 1 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. A10 40 July 24, 2018 Page 2 of 9 Greater Mooses Tooth Unit' 9n. I' 28 1 27 33 4 11 i ;p 15 I 14 1 13 1 3A •_•� 1 17. 1 1 1 .. ............. 1 i i i i ! 1 i 1 i ' Colvll. 1 River i i Unit 7 i 1 IF11NR3E i m r v�I MT6 Well Pad Q Proposed Lookout Oil Pool Boundary 17. Q Lookout Reservoir Q Proposed Lookout Participating Area ® Kuukpik Surface ASRC subsurface w ! GMTU Tracts M O_' Unit Boundaries o CPA] Leases N Conocomillips Alaska I Proposed Lookout — 0 0.5 1 1.5 z Oil Pool Area Zg Miles 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. A10 40 July 24, 2018 Page 3 of 9 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 A10 40 July 24, 2018 Page 4 of 9 6. Geology: a. Stratigraphy: CPAI's proposed LOP consists of late Jurassic -aged shelf deposits comprised of 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 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. 7. 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 Greater Moose's Tooth Unit, 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. AIO 40 July 24, 2018 Page 5 of 9 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: 3,775 psig 176° F 1,385 scf/bbl 42.50F 3,237 psig 1.77 rb/stbo 0.22 cp 0.78 bbl/mscf (at saturation pressure) Hydrocarbon Resources Estimated Volume (MMSTB) Original Oil in Place (OOIP) 70-150 Primary Recovery (20% OOIP) 14-30 Primary+ Waterflood (45% OOIP) 31-67 Primary + Waterflood + EWAG (60% OOIP) 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 assist 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. Wellbore Design: 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 fust 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 and well branches with uncemented solid liners including pre -perforated pups. External swell packers may be used to isolate out -of - pay excursions and 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. To facilitate wireline access on the highly deviated injection wells, CPAI proposes to install packer/isolation equipment more than 200 feet MD above the top of the injection interval. The packer/isolation equipment would not be installed above the upper confining interval, and the outer casing will be cemented with a sufficient volume of cement to ensure that cement extends a minimum of 300 feet MD above the packer/isolation equipment. 13. Reservoir Mana eg menta 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 AIO 40 July 24, 2018 Page 6 of 9 balanced to maintain reservoir pressure at or near the original measured pressure. Development will target a 1.0 voidage-replacement ratio. 14. Proposed Injection Fluids: CPAI proposes that the following fluids be authorized for injection into the LOP for FOR purposes: a. Source water from the Kuparuk seawater treatment plant; b. Produced water from all present and yet -to -be defined oil pools within the GMTU and CRU; c. Enriched hydrocarbon gas (blend of CRU and GMTU lean gas enriched with indigenous heavy gas components); d. Lean gas from the Alpine Central Facility; e. Fluids used during hydraulic stimulation; f. Tracer survey fluids to monitor reservoir performance (chemical, radioactive, etc.); g. Fluids used to improve near wellbore injectivity (acid or similar treatment); h. Fluids used to seal wellbore intervals which negatively impact recovery efficiency (cement, resin, etc.); i. Fluids associated with freeze protection (diesel, crude, glycol, methanol, etc.); and j. Standard oilfield chemicals (corrosion inhibitor, scale inhibitor, etc.). 15. Fluid Compatibility: The primary and miscellaneous fluids listed above are expected to be compatible with the LOP as has been shown by performance in the adjacent and analogous Alpine Oil Pool. 16. Scale Deposition: Moderate scale formation in the production wells has been experienced in the CRU due to the mixing of seawater and connate formation water. It is possible this could occur in the LOP producers as well, and scale inhibition treatments will be performed as necessary. 17. Injection Volumes: Injection volume will be managed to maintain the voidage-replacement ratio in the LOP at approximately 1:1. Total fluid -injection rates are anticipated to range between 10 and 25 thousand barrels of water per day and 5 to 25 million cubic feet of gas per day. 18. Injection Pressures: Injection pressure will be managed to prevent the injection -pressure gradient from exceeding 0.81 psi/ft to ensure fractures are not initiated or propagated in the confining intervals. Due to pump and compressor limitations at the ACF and frictional losses in the pipelines, the maximum surface injection pressure is anticipated not to exceed 2,650 psi for water and 4,000 psi for gas. 19. Fracture modelling: Fracture -gradient analysis calibrated with rock mechanical properties from core data and leak -off tests in the upper confining interval indicate that the fracture gradient exceeds 0.85 psi/ft. 20. Formation Water Quality: An analysis of the formation water is not possible, because, to date, it has not been encountered within the LOP. 21. Confinement in Offset Wells: The Lookout -1 and Lookout -2 wells were drilled within the proposed affected area. Lookout -2 was drilled, completed, tested, and plugged and abandoned in the spring of 2002. The Lookout -1 well is currently suspended with a downhole plug set in the tubing. 22. Waivers: CPAI requested a waiver of the injection well packer setting depth requirements of 20 AAC 25.412(b), which requires a packer be set within 200 feet MD of the top of the perforated/open injection interval. Due to the highly deviated nature of the proposed injection wells complying with the packer setting depth regulation would preclude accessing the packer/isolation equipment with wire line tools. CPAI requests a waiver to allow the packer/isolation equipment to be set more than 200 feet MD above the injection interval but not above the overlying confining interval and A10 40 July 24, 2018 Page 7 of 9 that the outer casing would be cemented with a sufficient volume of cement to ensure a minimum of 300 feet MD of cement is above the packer/isolation equipment setting depth. CONCLUSIONS: An Area Injection Order is necessary for the proposed development of the LOP to allow for enhanced oil recovery injection operations. 2. Reservoir simulation results show that an enriched water -alternating -gas injection project will significantly improve reserves recovery from the pool vs. primary and secondary recovery. 3. A waiver of the requirements of 20 AAC 25.412(b) to allow the packer/isolation equipment to be installed more than 200 feet MD above the perforated injection interval will provide for improved wellbore operations and not increase the risk of a loss of containment in the injection wells. 4. Reservoir voidage will be maintained at a replacement ratio of approximately 1:1. 5. Maintaining the sandface injection pressure gradient at or below 0.81 psi/ft will prevent fractures from forming or propagating in the confining intervals. 6. There are no freshwater aquifers in the Affected Area of the LOP. NOW THEREFORE IT IS ORDERED: The underground injection of fluids for pressure maintenance and enhanced recovery is authorized in the following area, subject to the following rules and 20 AAC 25, to the extent not superseded by these rules: Affected Area: Umiat Meridian (See Figure 1) Rule 1 Authorized Iniection Strata for Enhanced Recovery Fluids authorized under Rule 3, below, may be injected for the purposes of pressure maintenance and enhanced hydrocarbon recovery within the Affected Area defined above into strata that are common to, and correlate with, the interval within the Lookout -1 well between the measured depths of 7,833 and 8,000 feet on the resistivity log. Rule 2 Well Construction In lieu of the packer depth requirements under 20 AAC 25.412(b), the packer/isolation equipment depth for injection wells may be located above 200 feet measured depth from above the top of the perforations/open interval, but shall not be located above the confining zone and shall have outer casing cement volume sufficient to place a minimum of 300 feet measured depth above the planned packer depth. Sections 13-14: All Township 11 North, Range 2 East Sections 23-26: All Sections 35-36: All Sections 17-19: All Township I 1 North, Range 3 East Sections 29-32: All Section 1: All Township 10 North, Range 2 East Section 2: NEI/4 Township 10 North, Range 3 East Section 6: All Rule 1 Authorized Iniection Strata for Enhanced Recovery Fluids authorized under Rule 3, below, may be injected for the purposes of pressure maintenance and enhanced hydrocarbon recovery within the Affected Area defined above into strata that are common to, and correlate with, the interval within the Lookout -1 well between the measured depths of 7,833 and 8,000 feet on the resistivity log. Rule 2 Well Construction In lieu of the packer depth requirements under 20 AAC 25.412(b), the packer/isolation equipment depth for injection wells may be located above 200 feet measured depth from above the top of the perforations/open interval, but shall not be located above the confining zone and shall have outer casing cement volume sufficient to place a minimum of 300 feet measured depth above the planned packer depth. AIO 40 July 24, 2018 Page 8 of 9 Rule 3 Authorized Fluids for Infection for Enhanced Recovery Fluids authorized for injection are: a. Source water from the Kuparuk seawater treatment plant; b. Produced water from all present and yet -to -be defined oil pools within the GMTU and CRU; c. Enriched hydrocarbon gas (blend of CRU and GMTU lean gas enriched with indigenous heavy gas components); d. Lean gas from the Alpine Central Facility; e. Tracer survey fluids to monitor reservoir performance; f Fluids used to improve near wellbore injectivity; g. Fluids used to seal wellbore intervals which negatively impact recovery efficiency; h. Fluids associated with freeze protection; and i. Standard oilfield chemicals. Rule 4 Authorized Iniection Pressure for Enhanced Recovery Injection pressures will be managed as not to exceed the maximum injection gradient of 0.81 psi/ft to ensure containment of injected fluids within the defined affected area and injection interval. Rule 5 Monitoring Tubina-Casing Annulus Pressure Inner annulus, outer annulus, and tubing pressure shall be monitored and recorded at least daily, except if prevented by extreme weather condition, emergency situation, or similar unavoidable circumstances for all injection and production wells. The outer annulus pressures of all wells that are not cemented across the Lookout Oil Pool and are located within a V4 -mile radius of a Lookout Oil Pool injector shall be monitored daily. All monitoring results shall be documented and available for AOGCC inspection. Rule 6 Demonstration of Tubing/Casing Annulus Mechanical Integrity The mechanical integrity of each injection well must be demonstrated before injection begins and before returning a well to service following any workover affecting mechanical integrity. An AOGCC-witnessed MIT must be performed after injection is commenced for the first time in a well, to be scheduled when injection conditions (temperature, pressure, rate, etc.) have stabilized. Subsequent tests must be performed at least once every four years thereafter. The AOGCC must be notified at least 24 hours in advance to enable a representative to witness an MIT. Unless an alternate means is approved by the AOGCC, mechanical integrity must be demonstrated by a tubing/casing annulus pressure test using a surface pressure of 1,500 psi or 0.25 psi/ft multiplied by the vertical depth of the packer, whichever is greater, that shows stabilizing pressure and does not change more than 10 percent during a 30 -minute period. Results of MITs must be readily available for AOGCC inspection. Rule 7 Well Integrity and Confinement Whenever any pressure communication, leakage or lack of injection zone isolation is indicated by an injection rate, operating pressure observation, test, survey, log, or any other evidence (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 and submit a plan of corrective action on a Form 10-403 for AOGCC approval. The Operator shall immediately shut in the well if continued operation would be unsafe or would threaten contamination of freshwater. A monthly report of daily tubing and casing annuli pressures and injection rates must be provided to the AOGCC for all injection wells for which well integrity failure or lack of injection zone isolation is indicated. AIO 40 July 24, 2018 Page 9 of 9 Rule 8 Notification of Improper Class II Iniection Injection of fluids other than those listed in Rule 3 without prior authorization is considered improper Class 11 injection. Upon discovery of such an event, the operator must immediately notify the AOGCC, provide details of the operation, and propose actions to prevent recurrence. This requirement is in addition to and does not relieve the operator of any other obligations under the notification requirements of any other State or Federal agency, regulation or law. Rule 9 Other Conditions If fluids are found to be fracturing the confining zone or migrating out of the approved injection stratum, the Operator must immediately shut in the injection wells and immediately notify the AOGCC. Injection may not be restarted unless approved by the AOGCC. Rule 10 Administrative Action Upon proper application, or its own motion, and unless notice and public hearing are otherwise required, the AOGCC may administratively waive the requirements of any rule stated herein or administratively amend this order as long as the change does not promote waste or jeopardize correlative rights, is based on sound engineering and geoscience principles, and will not result in an increased risk of fluid movement into freshwater. DONE at Anchorage, Alaska and dated July 24, 2018 nunc pro tunc May 29, 2018. BVIMWW Hollis S. French Chair, Commissioner Daniel T. Seamou t, Jr. Commissioner D Cathy P. Foerster Commissioner �.- 9 As provided in AS 31.05.080(a), within 20 days after written notice of the entry of this order or decision, or such f ether 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 pan within 10 days after it is filed. Failure to act on it within 10days 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 eras 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: AIO-18-013 Alaska, Inc. for an order authorizing underground ) Area Injection Order No. 40 injection of fluids for enhanced oil recovery in 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 -Lookout Oil 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 authorizing underground injection of fluids for enhanced oil recovery purposes in the proposed Lookout Oil Pool (LOP), within the GMTU. 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. Operator: CPAI is operator of the leases in the proposed Affected Area, which is 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 (CRU), which is operated by CPAI. 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 1 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. AIO 40 July 24, 2018 Page 2 of 9 5 12 1 1 1 �2 16 i \V t t 8-1 1 ......... Greater M=oses 1 Tooth Unit i"sg ! 1 LooKO T.2\ 51 d \ 1 16 Colvii C�`kookodx'i\ -—River 33 log 1 \ 1 Unit \ -- \ 11 NR3E 15A � MI7 P{�} MT6 MIN Well Pad t' Q Proposed Lookout Oil Pool Boundary 7 7 Q Lookout Reservoir Q Proposed Lookout PartlapaUng Area ® Kuukpik SurfacsASRC Subsurface W W ( GMTU Tracts 12 N M � Of k_.,Unit Boundaries 0 0 CPAI Leases N ConocoPhillips 15 14 13 A Alaska 1e Proposed Lookout -- -- o 0.5 1 1.5 2 Oil Pool Area 23 Miles 125/2018 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. AIO 40 July 24, 2018 Page 3 of 9 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 AIO 40 July 24, 2018 Page 4 of 9 6. Geoloev: a. Stratigraphy: CPAI's proposed LOP consists of late Jurassic -aged shelf deposits comprised of 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 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 Greater Moose's Tooth Unit, 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 stmtigraphic sequences. AIO 40 July 24, 2018 Page 5 of 9 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: 3,775 psig 176° F 1,385 scf/bbl 42.50F 3,237 psig 1.77 rb/stbo 0.22 cp 0.78 bbl/mscf (at saturation pressure) Hydrocarbon Resources Estimated Volume (MMSTB) Original Oil in Place (OOIP) 70-150 Primary Recovery (20% OOIP) 14-30 Primary+ Waterflood (45% OOIP) 31-67 Primary + Waterflood + EWAG (60% OOIP) 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 assist 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. Wellbore Desien: 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 and well branches with uncemented solid liners including pre -perforated pups. External swell packers may be used to isolate out -of - pay excursions and fault crossings. Both injection and production wells will likely be completed with 4-'/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. To facilitate wireline access on the highly deviated injection wells, CPAI proposes to install packer/isolation equipment more than 200 feet MD above the top of the injection interval. The packer/isolation equipment would not be installed above the upper confining interval, and the outer casing will be cemented with a sufficient volume of cement to ensure that cement extends a minimum of 300 feet MD above the packer/isolation equipment. 13. 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 AIO 40 July 24, 2018 Page 6 of 9 balanced to maintain reservoir pressure at or near the original measured pressure. Development will target a 1.0 voidage-replacement ratio. 14. Proposed Injection Fluids: CPAI proposes that the following fluids be authorized for injection into the LOP for EOR purposes: a. Source water from the Kuparuk seawater treatment plant; b. Produced water from all present and yet -to -be defined oil pools within the GMTU and CRU; c. Enriched hydrocarbon gas (blend of CRU and GMTU lean gas enriched with indigenous heavy gas components); d. Lean gas from the Alpine Central Facility; e. Fluids used during hydraulic stimulation; f Tracer survey fluids to monitor reservoir performance (chemical, radioactive, etc.); g. Fluids used to improve near wellbore injectivity (acid or similar treatment); h. Fluids used to seal wellbore intervals which negatively impact recovery efficiency (cement, resin, etc.); i. Fluids associated with freeze protection (diesel, crude, glycol, methanol, etc.); and j. Standard oilfield chemicals (corrosion inhibitor, scale inhibitor, etc.). 15. Fluid Compatibility: The primary and miscellaneous fluids listed above are expected to be compatible with the LOP as has been shown by performance in the adjacent and analogous Alpine Oil Pool. 16. Scale Deoosition: Moderate scale formation in the production wells has been experienced in the CRU due to the mixing of seawater and connate formation water. It is possible this could occur in the LOP producers as well, and scale inhibition treatments will be performed as necessary. 17. Injection Volumes: Injection volume will be managed to maintain the voidage-replacement ratio in the LOP at approximately 1:1. Total fluid -injection rates are anticipated to range between 10 and 25 thousand barrels of water per day and 5 to 25 million cubic feet of gas per day. 18. Injection Pressures: Injection pressure will be managed to prevent the injection -pressure gradient from exceeding 0.81 psi/ft to ensure fractures are not initiated or propagated in the confining intervals. Due to pump and compressor limitations at the ACF and frictional losses in the pipelines, the maximum surface injection pressure is anticipated not to exceed 2,650 psi for water and 4,000 psi for gas. 19. Fracture modelling: Fracture -gradient analysis calibrated with rock mechanical properties from core data and leak -off tests in the upper confining interval indicate that the fracture gradient exceeds 0.85 psi/ft. 20. Formation Water Quality: An analysis of the formation water is not possible, because, to date, it has not been encountered within the LOP. 21. Confinement in Offset Wells: The Lookout -1 and Lookout -2 wells were drilled within the proposed affected area. Lookout -2 was drilled, completed, tested, and plugged and abandoned in the spring of 2002. The Lookout -1 well is currently suspended with a downhole plug set in the tubing. 22. Waivers: CPAI requested a waiver of the injection well packer setting depth requirements of 20 AAC 25.412(b), which requires a packer be set within 200 feet MD of the top of the perforated/open injection interval. Due to the highly deviated nature of the proposed injection wells complying with the packer setting depth regulation would preclude accessing the packer/isolation equipment with wire line tools. CPAI requests a waiver to allow the packer/isolation equipment to be set more than 200 feet MD above the injection interval but not above the overlying confining interval and AIO 40 July 24, 2018 Page 7 of 9 that the outer casing would be cemented with a sufficient volume of cement to ensure a minimum of 300 feet MD of cement is above the packer/isolation equipment setting depth. CONCLUSIONS: 1. An Area Injection Order is necessary for the proposed development of the LOP to allow for enhanced oil recovery injection operations. 2. Reservoir simulation results show that an enriched water -alternating -gas injection project will significantly improve reserves recovery from the pool vs. primary and secondary recovery. 3. A waiver of the requirements of 20 AAC 25.412(b) to allow the packer/isolation equipment to be installed more than 200 feet MD above the perforated injection interval will provide for improved wellbore operations and not increase the risk of a loss of containment in the injection wells. 4. Reservoir voidage will be maintained at a replacement ratio of approximately 1:1. 5. Maintaining the sandface injection pressure gradient at or below 0.81 psi/ft will prevent fractures from forming or propagating in the confining intervals. 6. There are no freshwater aquifers in the Affected Area of the LOP. NOW THEREFORE IT IS ORDERED: The underground injection of fluids for pressure maintenance and enhanced recovery is authorized in the following area, subject to the following rules and 20 AAC 25, to the extent not superseded by these rules: Affected Area: Umiat Meridian (See Figure 1) Rule 1 Authorized Injection Strata for Enhanced Recovery Fluids authorized under Rule 3, below, may be injected for the purposes of pressure maintenance and enhanced hydrocarbon recovery within the Affected Area defined above into strata that are common to, and correlate with, the interval within the Lookout -1 well between the measured depths of 7,833 and 8,000 feet on the resistivity log. Rule 2 Well Construction In lieu of the packer depth requirements under 20 AAC 25.412(b), the packer/isolation equipment depth for injection wells may be located above 200 feet measured depth from above the top of the perforations/open interval, but shall not be located above the confining zone and shall have outer casing cement volume sufficient to place a minimum of 300 feet measured depth above the planned packer depth. Sections 13-14: All Township 11 North, Range 2 East Sections 23-26: All Sections 35-36: All Sections 17-19: All Township 11 North, Range 3 East Sections 29-32: All Section 1: All Township 10 North, Range 2 East Section 2: NEI/4 Township 10 North, Range 3 East Section 6: All Rule 1 Authorized Injection Strata for Enhanced Recovery Fluids authorized under Rule 3, below, may be injected for the purposes of pressure maintenance and enhanced hydrocarbon recovery within the Affected Area defined above into strata that are common to, and correlate with, the interval within the Lookout -1 well between the measured depths of 7,833 and 8,000 feet on the resistivity log. Rule 2 Well Construction In lieu of the packer depth requirements under 20 AAC 25.412(b), the packer/isolation equipment depth for injection wells may be located above 200 feet measured depth from above the top of the perforations/open interval, but shall not be located above the confining zone and shall have outer casing cement volume sufficient to place a minimum of 300 feet measured depth above the planned packer depth. AIO 40 July 24, 2018 Page 8 of 9 Rule 3 Authorized Fluids for Iniection for Enhanced Recovery Fluids authorized for injection are: a. Source water from the Kupamk seawater treatment plant; b. Produced water from all present and yet -to -be defined oil pools within the GMTU and CRU; c. Enriched hydrocarbon gas (blend of CRU and GMTU lean gas enriched with indigenous heavy gas components); d. Lean gas from the Alpine Central Facility; e. Tracer survey fluids to monitor reservoir performance; f. Fluids used to improve near wellbore injectivity; g. Fluids used to seal wellbore intervals which negatively impact recovery efficiency; h. Fluids associated with freeze protection; and i. Standard oilfield chemicals. Rule 4 Authorized Infection Pressure for Enhanced Recove Injection pressures will be managed as not to exceed the maximum injection gradient of 0.81 psi/ft to ensure containment of injected fluids within the defined affected area and injection interval. Rule 5 Monitoring Tubing -Casing Annulus Pressure Inner annulus, outer annulus, and tubing pressure shall be monitored and recorded at least daily, except if prevented by extreme weather condition, emergency situation, or similar unavoidable circumstances for all injection and production wells. The outer annulus pressures of all wells that are not cemented across the 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. Rule 6 Demonstration of Tubing/Casing Annulus Mechanical Integrity The mechanical integrity of each injection well must be demonstrated before injection begins and before returning a well to service following any workover affecting mechanical integrity. An AOGCC-witnessed MIT must be performed after injection is commenced for the first time in a well, to be scheduled when injection conditions (temperature, pressure, rate, etc.) have stabilized. Subsequent tests must be performed at least once every four years thereafter. The AOGCC must be notified at least 24 hours in advance to enable a representative to witness an MIT. Unless an alternate means is approved by the AOGCC, mechanical integrity must be demonstrated by a tubing/casing annulus pressure test using a surface pressure of 1,500 psi or 0.25 psi/ft multiplied by the vertical depth of the packer, whichever is greater, that shows stabilizing pressure and does not change more than 10 percent during a 30 -minute period. Results of MITs must be readily available for AOGCC inspection. Rule 7 Well Integrity and Confinement Whenever any pressure communication, leakage or lack of injection zone isolation is indicated by an injection rate, operating pressure observation, test, survey, log, or any other evidence (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 and submit a plan of corrective action on a Form 10-403 for AOGCC approval. The Operator shall immediately shut in the well if continued operation would be unsafe or would threaten contamination of freshwater. A monthly report of daily tubing and casing annuli pressures and injection rates must be provided to the AOGCC for all injection wells for which well integrity failure or lack of injection zone isolation is indicated. AIO 40 July 24, 2018 Page 9 of 9 Rule 8 Notification of Improper Class II Iniection Injection of fluids other than those listed in Rule 3 without prior authorization is considered improper Class II injection. Upon discovery of such an event, the operator must immediately notify the AOGCC, provide details of the operation, and propose actions to prevent recurrence. This requirement is in addition to and does not relieve the operator of any other obligations under the notification requirements of any other State or Federal agency, regulation or law. Rule 9 Other Conditions If fluids are found to be fracturing the confining zone or migrating out of the approved injection stratum, the Operator must immediately shut in the injection wells and immediately notify the AOGCC. Injection may not be restarted unless approved by the AOGCC. Rule 10 Administrative Action Upon proper application, or its own motion, and unless notice and public hearing are otherwise required, the AOGCC may administratively waive the requirements of any rule stated herein or administratively amend this order as long as the change does not promote waste or jeopardize correlative rights, is based on sound engineering and geoscience principles, and will not result in an increased risk of fluid movement into freshwater. DONE at Anchorage, Alaska and dated July 24, 2018 nunc pro tune May 29, 2018. �SYJ'Oil. gry0p //signature on file// //signature on file// //signature on file// Hollis S. French Daniel T. Seamount, Jr. Cathy P. Foerster Chair, Commissioner Commissioner Commissioner ~SSR°4rroeco`9g As provided in AS 31.05.080(x), within 20 days after written notice of the entry of this order or decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration of the matter determined by it. If the notice was mailed, then the period of time shall be 23 days. An application for reconsideration must set out the respect in which the order or decision is believed to be erroneous. The AOGCC shall grant or refuse the application for reconsideration in whole or in part within 10 days after it is filed. Failure to act on it within 10 -days is a denial of reconsideration. If the AOGCC denies reconsideration, upon denial, this order or decision and the denial of reconsideration are FINAL and may be appealed to superior court. The appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision denying reconsideration, UNLESS the denial is by inaction, in which case the appeal MUST be filed within 40 days after the date on which the application for reconsideration was filed. If the AOGCC grants an application for reconsideration, this order or decision does not become final. Rather, the order or decision on reconsideration will be the FINAL order or decision of the AOGCC, and it may be appealed to superior court. That appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision on reconsideration. In computing a period of time above, the date of the event or default after which the designated period begins to run is not included in the period; the last day of the period is included, unless it falls on a weekend or state holiday, in which event the period runs until 5:00 p.m. on the next day 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 1 (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 Qarlington@gmail.com); Jeanne McPherren; Jerry Hodgden; Jill Simek; Jim Shine; Jim Watt; Jim White 6im4thgn@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. Coiombie .AOQCC SpeciaCA.ssistant .ACaska OiCandgas Conservation Commission 333 'Vest 7'1 .Avenue .Anchorage, .ACaska 99501 Office: (907) 793-1221 ,tax: (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.aov. Bernie Karl K&K Recycling Inc. Gordon Severson Penny Vadla P.O. Box 58055 3201 Westmar Cir. 399 W. Riverview Ave. Fairbanks, AK 99711 Anchorage, AK 99508-4336 Soldotna, AK 99669-7714 George Vaught, Jr. P.O. Box 13557 Denver, CO 80201-3557 Darwin Waldsmith P.O. Box 39309 Ninilchik, AK 99639 Richard Wagner P.O. Box 60868 Fairbanks, AK 99706 THE STATE °fALAS_ A 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 viii and. Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.cogcc.olaska.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 run is not included in the period; the last day of the period is included, unless it falls on a weekend or state holiday, in which event the period runs until 5:00 p.m. on the next day that does not fall on a weekend or state holiday. Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.alaska.gov ADMINISTRATIVE APPROVAL AREA INJECTION ORDER NO. 40.001 October 27, 2021 Mr. Travis Smith, Well Intervention & Integrity Engineer ConocoPhillips Alaska, Inc. P.O. Box 100360 Anchorage, AK 99510-0360 Re: Docket Number: AIO-21-026 Request for Administrative Approval to Area Injection Order 40: Water Injection Greater Moose’s Tooth Unit (GMTU) MT6-09 (PTD 2181340), Lookout Oil Pool Dear Mr. Smith: By letter received October 15, 2021, ConocoPhillips Alaska, Inc. (CPAI) requested administrative approval to continue water injection with a known tubing by inner annulus (TxIA) pressure communication. In accordance with 20AAC 25.556(d), the Alaska Oil and Gas Conservation Commission (AOGCC) hereby GRANTS, subject to conditions, CPAI’s request for administrative approval to continue water only injection in the subject well. CPAI reported a potential TxIA pressure communication to AOGCC on September 7, 2021, while the well was injecting water. CPAI performed diagnostics and wellwork including a temperature and acoustic leak detect log, and replacing the dummy valve in a gas lift mandrel. The TxIA communication persisted over the monitoring period. CPAI performed additional diagnostics including a passing non-state witnessed mechanical integrity test (MIT) of the inner annulus to 3,000 psi and the outer annulus to 1,800 psi on October 12, 2021. This indicates that MT6-09 exhibits at least two competent barriers to the release of well pressure. AOGCC believes CPAI can safely manage the TxIA repressurization with periodic pressure bleeds by maintaining the inner annulus to a pressure not to exceed 2,600 psi when injecting water. Accordingly, the AOGCC believes that the well’s condition does not compromise overall well integrity so as to threaten human safety or the environment. AOGCC’s approval to continue water injection only in GMTU MT6-09 is conditioned upon the following: 1. CPAI shall record wellhead pressures and injection rate daily; AIO 40.001 October 27, 2021 Page 2 of 2 2. CPAI shall submit to the AOGCC a monthly report of well pressures, injection rates, and pressure bleeds for all annuli. Bleeds to be flagged on the report; 3. CPAI shall perform a MIT of the inner annulus every two years to the greater of the maximum anticipated injection pressure or 0.25 x packer TVD, but not less than 1,500 psi; 4. CPAI shall limit the well’s inner annulus operating pressure to 2,600 psi and the outer annulus to 1,000 psi. Audible control room alarms shall be set at or below these limits; 5. CPAI shall monitor the inner and outer annulus pressures in real time with its SCADA system; 6. CPAI shall immediately shut in the well and notify the AOGCC if there is any change in the well's mechanical condition; 7. After well shut in due to a change in the well's mechanical condition, AOGCC approval shall be required to restart injection; and 8. The next required MIT shall be completed before or during the month of June 2022. This is to align with the agreed upon CPAI Underground Injection Control MIT permanent test schedule for pad testing. DONE at Anchorage, Alaska and dated October 27, 2021. Jeremy M. Price Daniel T. Seamount, Jr. Jessie L. Chmielowski Chair, Commissioner Commissioner Commissioner RECONSIDERATION AND APPEAL NOTICE As provided in AS 31.05.080(a), within 20 days after written notice of the entry of this order or decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration of the matter determined by it. If the notice was mailed, then the period of time shall be 23 days. An application for reconsideration must set out the respect in which the order or decision is believed to be erroneous. The AOGCC shall grant or refuse the application for reconsideration in whole or in part within 10 days after it is filed. Failure to act on it within 10 days is a denial of reconsideration. If the AOGCC denies reconsideration, upon denial, this order or decision and the denial of reconsideration are FINAL and may be appealed to superior court. The appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision denying reconsideration, UNLESS the denial is by inaction, in which case the appeal MUST be filed within 40 days after the date on which the application for reconsideration was filed. If the AOGCC grants an application for reconsideration, this order or decision does not become final. Rather, the order or decision on reconsideration will be the FINAL order or decision of the AOGCC, and it may be appealed to superior court. That appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision on reconsideration. In computing a period of time above, the date of the event or default after which the designated period begins to run is not included in the period; the last day of the period is included, unless it falls on a weekend or state holiday, in which event the period runs until 5:00 p.m. on the next day that does not fall on a weekend or state holiday. Dan Seamount Digitally signed by Dan Seamount Date: 2021.10.27 11:10:33 -08'00' Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2021.10.27 11:15:43 -08'00' Jeremy Price Digitally signed by Jeremy Price Date: 2021.10.27 11:49:51 -08'00' From:Salazar, Grace (CED) To:AOGCC_Public_Notices Subject:Area Injection Order No. 40.001 (ConocoPhillips, Greater Moose"s Tooth Unit) Date:Wednesday, October 27, 2021 1:41:00 PM Attachments:AIO 40.001.pdf The Alaska Oil and Gas Conservation Commission has issued the attached administrative approval regarding ConocoPhillips Alaska, Inc.’s request to continue water only injection service for Greater Moose’s Tooth Unit (PTD 2181340). Grace Respectfully, M. Grace Salazar, Special Assistant Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage, AK 99501 Direct: (907) 793-1221 Email: grace.salazar@alaska.gov https://www.commerce.alaska.gov/web/aogcc/ Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.alaska.gov ADMINISTRATIVE APPROVAL CONSERVATION ORDER NO. 605A.001 AREA INJECTION ORDER NO. 40.002 December 1, 2021 Mr. Stephen Thatcher Manager, WNS Development North Slope Development ConocoPhillips Alaska, Inc. P.O. Box 100360 Anchorage, AK 99510-0360 Re: Docket Numbers: CO-21-006 and AIO-21-006 Request for Administrative Approval to Amend Conservation Order No. 605A and Area Injection Order No. 40 Surface Commingling of Production and Authorized Injection Fluids Colville River Unit, Qannik Oil Pool Greater Moose’s Tooth Unit, Lookout Oil Pool Dear Mr. Thatcher: By letter dated April 22, 2021, ConocoPhillips Alaska, Inc. (CPAI) requested administrative approval to amend Conservation Order No. 605A (CO 605A), the pool rules for the Qannik Oil Pool (QOP), and Area Injection Order No. 40 (AIO 40), the area injection order for the Lookout Oil Pool, in order to make them consistent with the other Colville River Unit (CRU) and Greater Moose’s Tooth Unit (GMTU) pool rules and area injection orders. Specifically, CPAI requested approval for surface commingling of production from the Rendezvous Oil Pool (ROP) and the QOP in the facilities of the CRU prior to custody transfer metering. CPAI also requests to amend the list of authorized injection fluids in AIO 40 to be consistent with the other pools that share a common water injection system. In accordance with 20 AAC 25.556(d), the Alaska Oil and Gas Conservation Commission (AOGCC) hereby GRANTS CPAI’s request for administrative approvals. Other Orders No. 112A and 148 (OO 112A and OO 148 respectively) authorize commingling of production from the GMTU drill sites 1 and 2 (GMTU1 and GMTU2 respectively) in surface facilities in the CRU with production from the CRU pools prior to custody transfer metering. CO 605A.001 AIO 40.002 December 1, 2021 Page 2 of 3 Rule 6 of CO 605A allows QOP production to be commingled with other CRU pools but was never updated to also allow surface commingling with the LOP and ROP as was authorized under OO 112A and OO 148. To eliminate this contradiction between CO 605A and OO 112A and OO 148, Rule 6 of CO 605A needs to be amended to read as follows: Rule 6 Common Production Facilities and Surface Commingling (Revised CO 605A.001) a. Production from the Qannik Oil Pool and other CRU and GMTU pools may be commingled in surface facilities prior to custody transfer. b. Production shall be allocated to wells within the Qannik Oil Pool in accordance with the procedures described in Section 6.0 of CPAI’s application, dated April 3, 2008. c. Each producing well must be tested a minimum of twice per month. d. The Commission may require more frequent or longer testing if the allocation quality deteriorates. e. The operator shall submit a monthly report and electronic file(s) containing daily allocation data and daily test data for agency surveillance and evaluation. f. The operator shall provide the Commission an annual well test and allocation review report in conjunction with the annual reservoir surveillance report required under Rule 9 (below). All CRU and GMTU pools that are authorized for an enhanced oil recovery injection project share the same supply systems and thus the same fluids go to all pools. Currently, the LOP lacks one fluid authorized in the other pools. Specifically, the LOP lacks authorization for: Small amounts of Class II fluids, which will be mixed with the source or produced water including sump fluid, hydrotest fluid, rinsate generated from washing trucks, excess well work fluids, meltwater collected from well cellars. All CRU and GMTU pools are tied into the same injection system.. The LOP, ROP, and Alpine Oil Pool (AOP) are all Alpine formation reservoirs. Because to date, there have been no compatibility issues with injecting these fluids in the AOP or ROP, no compatibility issues are anticipated for the LOP either. To make AIO 40 consistent with the other AIOs for CRU and GMTU pools, Rule 3 will be amended to read as follows: Rule 3 Authorized Fluids for Injection for Enhanced Recovery Fluids authorized for injection are: a. Source water from the Kuparuk seawater treatment plant; b. Produced water from all present and yet-to-be defined oil pools within the GMTU and CRU; c. Enriched hydrocarbon gas (blend of CRU and GMTU lean gas enriched with indigenous heavy gas components); CO 605A.001 AIO 40.002 December 1, 2021 Page 3 of 3 d. Lean gas from the Alpine Central Facility; e. Tracer survey fluids to monitor reservoir performance; f. Fluids used to improve near wellbore injectivity; g. Fluids used to seal wellbore intervals which negatively impact recovery efficiency; h. Fluids associated with freeze protection; i. Standard oilfield chemicals; and j. Small amounts of Class II fluids, which will be mixed with the source or produced water including sump fluid, hydrotest fluid, rinsate generated from washing trucks, excess well work fluids, meltwater collected from well cellars. DONE at Anchorage, Alaska and dated December 1, 2021. Daniel T. Seamount, Jr. Jessie L. Chmielowski Commissioner Commissioner RECONSIDERATION AND APPEAL NOTICE As provided in AS 31.05.080(a), within 20 days after written notice of the entry of this order or decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration of the matter determined by it. If the notice was mailed, then the period of time shall be 23 days. An application for reconsideration must set out the respect in which the order or decision is believed to be erroneous. The AOGCC shall grant or refuse the application for reconsideration in whole or in part within 10 days after it is filed. Failure to act on it within 10 days is a denial of reconsideration. If the AOGCC denies reconsideration, upon denial, this order or decision and the denial of reconsideration are FINAL and may be appealed to superior court. The appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision denying reconsideration, UNLESS the denial is by inaction, in which case the appeal MUST be filed within 40 days after the date on which the application for reconsideration was filed. If the AOGCC grants an application for reconsideration, this order or decision does not become final. Rather, the order or decision on reconsideration will be the FINAL order or decision of the AOGCC, and it may be appealed to superior court. That appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision on reconsideration. In computing a period of time above, the date of the event or default after which the designated period begins to run is not included in the period; the last day of the period is included, unless it falls on a weekend or state holiday, in which event the period runs until 5:00 p.m. on the next day that does not fall on a weekend or state holiday. Dan Seamount Digitally signed by Dan Seamount Date: 2021.11.30 13:51:19 -09'00' Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2021.11.30 14:34:16 -09'00' From:Salazar, Grace (OGC) To:AOGCC_Public_Notices Subject:[AOGCC_Public_Notices] AOGCC Conservation Order No. 605A.001 an Area Injection Order No. 40.002 Date:Wednesday, December 1, 2021 7:27:51 AM Attachments:CO 605A.001 and AIO 40.002.pdf The Alaska Oil and Gas Conservation Commission has issued the attached Order, granting Conoco Phillips Alaska, Inc.’s request for administrative approval to amend Conservation Order No. 605A for the Qannik Oil Pool and Area Injection Order No. 40 for the Lookout Oil Pool. Grace ____________________________________ Respectfully, M. Grace Salazar, Special Assistant Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage, AK 99501 Direct: (907) 793-1221 Email: grace.salazar@alaska.gov https://www.commerce.alaska.gov/web/aogcc/ __________________________________ List Name: AOGCC_Public_Notices@list.state.ak.us You subscribed as: grace.salazar@alaska.gov Unsubscribe at: https://list.state.ak.us/mailman/options/aogcc_public_notices/grace.salazar%40alaska.gov AOGCC 333 W 7th Avenue, Anchorage, AK 99501 TO: BERNIE KARL K&K RECLYCLING, INC. PO BOX 58055 FAIRBANKS, AK 99711 Mailed 12/1/21 gs Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.alaska.gov ADMINISTRATIVE APPROVAL AREA INJECTION ORDER NO. 18E.001 AREA INJECTION ORDER NO. 28.009 AREA INJECTION ORDER NO. 35.004 AREA INJECTION ORDER NO. 40.003 AREA INJECTION ORDER NO. 43.001 January 27, 2022 Mr. Stephen Thatcher, Manager North Slope Development ConocoPhillips Alaska, Inc. P.O. Box 100360 Anchorage, AK 99510-0360 Re: Docket Number: AIO-21-010 Request to Reinstate Area Injection Order No. 18.001with Modifications Colville River Unit, Alpine Oil Pool Dear Mr. Thatcher: By letter dated May 26, 2021, ConocoPhillips Alaska, Inc. (CPAI) requested reinstatement of Area Injection Order (AIO) No. 18A.001, which allowed for the mixing of treated effluent with Class II enhanced oil recovery (EOR) fluids for injection into the Alpine Oil Pool (AOP) when the Class I disposal well was unavailable. AIO 18A.001 was rescinded when AIO 18E was issued on March 4, 2021. The Alaska Oil and Gas Conservation Commission (AOGCC) does not reinstate rescinded orders. However, the substance of CPAI’s request is for administrative approval to authorize an additional fluid to be for injection, and AOGCC will treat it as such. Since AIO 18A.001 was issued, four additional pools have been tied into the EOR injection system that serves the AOP. These pools and the AIOs that govern their injection operations are: Pool Governing AIO Nanuq Oil Pool (NOP) AIO 28 Qannik Oil Pool (QOP) AIO 35 Lookout Oil Pool (LOP) AIO 40 Rendezvous Oil Pool (ROP) AIO 43 The NOP and QOP are in the Colville River Unit (CRU), and the LOP and ROP are in the Greater Moose’s Tooth Unit (GMTU). AIO 18E.001, AIO 28.009, AIO 35.004, AIO 40.003, & AIO 43.001 January 27, 2022 Page 2 of 2 There are currently two usable Class I disposal wells (a third Class I well was suspended in 2013) in the CRU, and there are none in the GMTU. Well CRU WD-02 (PTD 198-258) is used for disposal of treated effluent, and CRU CD1-01A (PTD 212-099) is the primary drilling waste disposal well. Having the ability to mix small amounts of treated effluent into the EOR injection stream when using a Class I well is not possible due to required mechanical integrity testing, well damage, well workover operations, or any other incident that may make a well temporarily unusable provides operational flexibility for the remote CRU and GMTU developments. Under the authorization of AIO 18A.001, CPAI has periodically mixed treated effluent with the EOR injection water with no indication of fluid incompatibilities or formation damage that reduces injectivity. In accordance with 20 AAC 25.556(d), the AOGCC hereby amends AIO numbers 18E, 28, 35, 40, and 43 to include the following in the list of authorized fluids in Rule 1 of AIO 18E, Rule 4 of AIO 28, and Rule 3 of AIO 35, 40, and 43: - Treated effluent, subject to the following conditions: o Treated effluent injection may occur when the Class I disposal well for effluent disposal is unavailable; o Treated effluent will be mixed with other EOR injection fluids (seawater or produced water); and o Injection of treated effluent may not exceed 1% by volume of the total annualized average water injection at the Colville River Unit and Greater Moose’s Tooth Unit. DONE at Anchorage, Alaska and dated January 27, 2022. Jeremy M. Price Daniel T. Seamount, Jr. Jessie L. Chmielowski Commissioner, Chair Commissioner Commissioner RECONSIDERATION AND APPEAL NOTICE As provided in AS 31.05.080(a), within 20 days after written notice of the entry of this order or decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration of the matter determined by it. If the notice was mailed, then the period of time shall be 23 days. An application for reconsideration must set out the respect in which the order or decision is believed to be erroneous. The AOGCC shall grant or refuse the application for reconsideration in whole or in part within 10 days after it is filed. Failure to act on it within 10 days is a denial of reconsideration. If the AOGCC denies reconsideration, upon denial, this order or decision and the denial of reconsideration are FINAL and may be appealed to superior court. The appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision denying reconsideration, UNLESS the denial is by inaction, in which case the appeal MUST be filed within 40 days after the date on which the application for reconsideration was filed. If the AOGCC grants an application for reconsideration, this order or decision does not become final. Rather, the order or decision on reconsideration will be the FINAL order or decision of the AOGCC, and it may be appealed to superior court. That appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision on reconsideration. In computing a period of time above, the date of the event or default after which the designated period begins to run is not included in the period; the last day of the period is included, unless it falls on a weekend or state holiday, in which event the period runs until 5:00 p.m. on the next day that does not fall on a weekend or state holiday. Dan Seamount Digitally signed by Dan Seamount Date: 2022.01.27 08:48:32 -09'00' Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2022.01.27 09:05:42 -09'00' Jeremy Price Digitally signed by Jeremy Price Date: 2022.01.27 13:57:28 -09'00' From:Salazar, Grace (OGC) To:AOGCC_Public_Notices Subject:[AOGCC_Public_Notices] Area Injection Order Nos. 18E.001, 28.009, 35.004, 40.003 and 43.001 (ConocoPhillips, Alpine Pool) Date:Thursday, January 27, 2022 2:53:56 PM Attachments:AIO 18E.001_ AIO 28.009_ AIO 35.004_ AIO 40.003_AIO 43.001.pdf The Alaska Oil and Gas Conservation Commission has issued the attached administrative approval amending a number of Area Injection Orders for ConocoPhillips Alaska, Inc.’s Colville River Unit, Alpine Oil Pool. Grace ____________________________________ Respectfully, M. Grace Salazar, Special Assistant Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage, AK 99501 Direct: (907) 793-1221 Email: grace.salazar@alaska.gov https://www.commerce.alaska.gov/web/aogcc/ __________________________________ List Name: AOGCC_Public_Notices@list.state.ak.us You subscribed as: grace.salazar@alaska.gov Unsubscribe at: https://list.state.ak.us/mailman/options/aogcc_public_notices/grace.salazar%40alaska.gov AOGCC 333 W 7th Avenue, Anchorage, AK 99501 TO: BERNIE KARL K&K RECLYCLING, INC. PO BOX 58055 FAIRBANKS, AK 99711 Mailed 1/28/22gs Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.alaska.gov ADMINISTRATIVE APPROVAL AREA INJECTION ORDER NO. 40.001 CANCELLATION Ms. Kate Dodson Senior Well Intervention Engineer ConocoPhillips Alaska, Inc. P.O. Box 1000360 Anchorage, AK 99510 Re: Docket Number: AIO-22-019 Request to cancel Area Injection Order (AIO) 40.001 Greater Moose’s Tooth Unit (GMTU) MT6-09 (PTD 2181340), Lookout Oil Pool Dear Ms. Dodson: By letter dated July 8, 2022, ConocoPhillips Alaska, Inc. (CPAI)requested cancellation of administrative approval (AA) AIO 40.001. In accordance with 20AAC 25.556(d), the Alaska Oil and Gas Conservation Commission (AOGCC) hereby GRANTS CPAI’s request to cancel the AA. CPAIfirst reported a potential tubing by inner annulus (TxIA) pressure communication to AOGCC on September 5, 2021 and on October 27, 2021 AOGCC issued AIO 40.001. AOGCC determined that water only injection could safely continue if CPAI complied with the restrictive conditions set out in AA AIO 40.001. CPAI has repaired the well with new tubing under Sundry 321-633 and completed a passing state witnessed mechanical integrity test (MIT) of the inner annulus on May 20, 2022 which indicates that MT6-09 exhibits at least two competent barriers to the release of well pressure. AA AIO 40.001 is no longer necessary to the operation of MT6-09 and is hereby CANCELLED. DONE at Anchorage, Alaska and dated July 22, 2022. Jeremy M. Price Daniel T. Seamount, Jr. Jessie L. Chmielowski Chair, Commissioner Commissioner Commissioner Dan Seamount Digitally signed by Dan Seamount Date: 2022.07.22 11:46:39 -08'00' Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2022.07.22 12:45:37 -08'00' Jeremy Price Digitally signed by Jeremy Price Date: 2022.07.22 13:05:15 -08'00' AIO 40.001 Cancellation July 22, 2022 Page 2 of 2 RECONSIDERATION AND APPEAL NOTICE As provided in AS 31.05.080(a), within 20 days after written notice of the entry of this order or decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration of the matter determined by it. If the notice was mailed, then the period of time shall be 23 days. An application for reconsideration must set out the respect in which the order or decision is believed to be erroneous. The AOGCC shall grant or refuse the application for reconsideration in whole or in part within 10 days after it is filed. Failure to act on it within 10 days is a denial of reconsideration. If the AOGCC denies reconsideration, upon denial, this order or decision and the denial of reconsideration are FINAL and may be appealed to superior court. The appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision denying reconsideration, UNLESS the denial is by inaction, in which case the appeal MUST be filed within 40 days after the date on which the application for reconsideration was filed. If the AOGCC grants an application for reconsideration, this order or decision does not become final. Rather, the order or decision on reconsideration will be the FINAL order or decision of the AOGCC, and it may be appealed to superior court. That appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision on reconsideration. In computing a period of time above, the date of the event or default after which the designated period begins to run is not included in the period; the last day of the period is included, unless it falls on a weekend or state holiday, in which event the period runs until 5:00 p.m. on the next day that does not fall on a weekend or state holiday. 1 Carlisle, Samantha J (OGC) From:Carlisle, Samantha J (OGC) <samantha.carlisle@alaska.gov> Sent:Friday, July 22, 2022 1:12 PM To:AOGCC_Public_Notices Subject:[AOGCC_Public_Notices] Area Injection Order 40.001 cancelation (CPAI, GMTU) Attachments:aio 40.001 cancelation.pdf Categories:Follow-up Docket Number: AIO-22-019 Request to cancel Area Injection Order (AIO) 40.001 Greater Moose’s Tooth Unit (GMTU) MT6-09 (PTD 2181340), Lookout Oil Pool Samantha Carlisle AOGCC Special Assistant Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage, AK 99501 (907) 793-1223 __________________________________ List Name: AOGCC_Public_Notices@list.state.ak.us You subscribed as: samantha.carlisle@alaska.gov Unsubscribe at: https://list.state.ak.us/mailman/options/aogcc_public_notices/samantha.carlisle%40alaska.gov Bernie Karl K&K Recycling Inc. P.O. Box 58055 Fairbanks, AK 99711 mailed 7/22/22 Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.alaska.gov ADMINISTRATIVE APPROVALS AREA INJECTION ORDER 18E.007 AREA INJECTION ORDER 28.010 AREA INJECTION ORDER 35A.001 AREA INJECTION ORDER 40.004 AREA INJECTION ORDER 43.002 Mr. Michael Driscoll WNS Development Supervisor North Slope Development ConocoPhillips Alaska, Inc. P.O Box 100360 Anchorage, AK 99510-0360 Re: Docket Number: AIO-25-013 Making mechanical integrity testing notification requirements consistent across Colville River Unit and Greater Moose’s Tooth Unit pools Colville River Unit, Alpine Oil Pool, Qannik Oil Pool, and Nanuq Oil Pool Greater Moose’s Tooth Unit Lookout Oil Pool and Rendezvous Oil Pool Dear Mr. Driscoll: By letter dated March 17, 2025, ConocoPhillips Alaska, Inc. (CPAI) asked the Alaska Oil and Gas Conservation Commission (AOGCC) to reconsider a portion of Rule 5 of Enhanced Recovery Injection Order No. 9 (ERIO 9) which stated that CPAI was required to provide a minimum of 72- hour notice prior to conducting a required mechanical integrity test. CPAI pointed out that other pools the in Colville River Unit (CRU) and Greater Moose’s Tooth Unit (GMTU) have different minimum notification requirements and that the pools should be consistent and proposed changing the requirement in Rule 5 of ERIO 9 from 72 to 24 hours. The AOGCC agrees the notification requirement should be consistent across all pools in these two units. However, the CRU and GMTU are remote locations in the context of Industry Guidance Bulletins (IGB) 10-01A (Test Witness Notification) and IGB 10-02B (Mechanical Integrity Testing) because the fields do not have a permanent road connection to Alaska’s road system and therefore 48 hours’ notice is appropriate for these fields. On its own motion and in accordance with 20 AAC 25.556(d), the AOGCC hereby amends the Demonstration of Tubing/Casing Annulus Mechanical Integrity rules in the injection orders for the CRU and GMTU fields. AIO 18E.007, 28.010, 35A.001, 40.004, and 43.002 April 24, 2025 Page 2 of 4 Now Therefore it is Ordered: Rule 6 of AIO 18E is amended to read as follows: Rule 6 Demonstration of Tubing/Casing Annulus Mechanical Integrity (Source: Revised This Order for Clarification) The mechanical integrity of each injection well must be demonstrated before injection begins and before returning a well to service following any workover affecting mechanical integrity. An AOGCC-witnessed MIT must be performed after injection is commenced for the first time in a well, to be scheduled when injection conditions (e.g., temperature, pressure, rate, etc.) have stabilized. Subsequent tests must be performed at least once every four years thereafter. For slurry injection wells, the tubing/casing annulus must be tested for mechanical integrity every two years. The AOGCC must be notified at least 48 hours in advance to enable a representative to witness an MIT. Unless an alternate means is approved by the AOGCC, mechanical integrity must be demonstrated by a tubing/casing annulus pressure test using a surface pressure of 1,500 psi or 0.25 psi/ft multiplied by the vertical depth of the packer, whichever is greater, that shows stabilizing pressure and does not change more than 10 percent during a 30-minute period. Results of MITs must be readily available for AOGCC inspection. Rule 6 of AIO 28 is amended to read as follows: Rule 6 Demonstration of Tubing/Casing Annulus Mechanical Integrity A Commission-witnessed mechanical integrity test must be performed after injection is commenced for the first time in a well, to be scheduled when injection conditions (temperature, pressure, rate, etc.) have stabilized. Subsequent tests must be performed at least once every four years thereafter, except at least once every two years in the case of a slurry injection well. The Commission must be notified at least 48 hours in advance to enable a representative to witness mechanical integrity tests. Unless an alternate means is approved by the Commission, mechanical integrity must be demonstrated by a tubing/casing annulus pressure test using a surface pressure of 1,500 psi or 0.25 psi/ft multiplied by the vertical depth of the packer, whichever is greater, that shows stabilizing pressure and does not change more than 10 percent during a 30-minute period. Results of mechanical integrity tests must be readily available for Commission inspection. Rule 6 of AIO 35A is amended to read as follows: Rule 6. Demonstration of Tubing/Casing Annulus Mechanical Integrity (Source: AIO 35) The mechanical integrity of an injection well must be demonstrated before injection begins, and before returning a well to service following a workover affecting mechanical integrity. An AOGCC-witnessed mechanical integrity test must be performed after injection is commenced for the first time in a well, to be scheduled when injection conditions (temperature, pressure, rate, etc.) have stabilized. Subsequent tests must be performed at least once every four years thereafter (except at least once every two years in the case of a slurry injection well). The AOGCC must be notified at least 48 hours in advance to enable a representative to witness mechanical integrity tests. Unless an alternate means is AIO 18E.007, 28.010, 35A.001, 40.004, and 43.002 April 24, 2025 Page 3 of 4 approved by the AOGCC, mechanical integrity must be demonstrated by a tubing/casing annulus pressure test using a surface pressure of 1500 psi or 0.25 psi/ft multiplied by the vertical depth of the packer, whichever is greater, that shows stabilizing pressure and does not change more than 10 percent during a 30-minute period. Results of mechanical integrity tests must be readily available for AOGCC inspection. Rule 6 of AIO 40 is amended to read as follows: Rule 6 Demonstration of Tubing/Casing Annulus Mechanical Integrity The mechanical integrity of each injection well must be demonstrated before injection begins and before returning a well to service following any workover affecting mechanical integrity. An AOGCC-witnessed MIT must be performed after injection is commenced for the first time in a well, to be scheduled when injection conditions (temperature, pressure, rate, etc.) have stabilized. Subsequent tests must be performed at least once every four years thereafter. The AOGCC must be notified at least 48 hours in advance to enable a representative to witness an MIT. Unless an alternate means is approved by the AOGCC, mechanical integrity must be demonstrated by a tubing/casing annulus pressure test using a surface pressure of 1,500 psi or 0.25 psi/ft multiplied by the vertical depth of the packer, whichever is greater, that shows stabilizing pressure and does not change more than 10 percent during a 30-minute period. Results of MITs must be readily available for AOGCC inspection. Rule 6 of AIO 43 is amended to read as follows: Rule 6 Demonstration of Tubing/Casing Annulus Mechanical Integrity The mechanical integrity of each injection well must be demonstrated before injection begins and before returning a well to service following any workover affecting mechanical integrity. An AOGCC-witnessed mechanical integrity test (MIT) must be performed after injection is commenced for the first time in a well, to be scheduled when injection conditions (temperature, pressure, rate, etc.) have stabilized. Subsequent tests must be performed at least once every four years thereafter. The AOGCC must be notified at least 48 hours in advance to enable a representative to witness an MIT. Unless an alternate means is approved by the AOGCC, mechanical integrity must be demonstrated by a tubing/casing annulus pressure test using a surface pressure of 1,500 psi or 0.25 psi/ft multiplied by the vertical depth of the packer, whichever is greater, that shows stabilizing pressure and does not change more than 10 percent during a 30-minute period. Results of MITs must be readily available for AOGCC inspection. DONE at Anchorage, Alaska and dated April 24, 2025. Jessie L. Chmielowski Gregory C. Wilson Commissioner Commissioner Gregory C. Wilson Digitally signed by Gregory C. Wilson Date: 2025.04.23 15:47:29 -08'00' Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2025.04.23 16:29:43 -08'00' AIO 18E.007, 28.010, 35A.001, 40.004, and 43.002 April 24, 2025 Page 4 of 4 RECONSIDERATION AND APPEAL NOTICE As provided in AS 31.05.080(a), within 20 days after written notice of the entry of this order or decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration of the matter determined by it. If the notice was mailed, then the period of time shall be 23 days. An application for reconsideration must set out the respect in which the order or decision is believed to be erroneous. The AOGCC shall grant or refuse the application for reconsideration in whole or in part within 10 days after it is filed. Failure to act on it within 10 days is a denial of reconsideration. If the AOGCC denies reconsideration, upon denial, this order or decision and the denial of reconsideration are FINAL and may be appealed to superior court. The appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision denying reconsideration, UNLESS the denial is by inaction, in which case the appeal MUST be filed within 40 days after the date on which the application for reconsideration was filed. If the AOGCC grants an application for reconsideration, this order or decision does not become final. Rather, the order or decision on reconsideration will be the FINAL order or decision of the AOGCC, and it may be appealed to superior court. That appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision on reconsideration. In computing a period of time above, the date of the event or default after which the designated period begins to run is not included in the period; the last day of the period is included, unless it falls on a weekend or state holiday, in which event the period runs until 5:00 p.m. on the next day that does not fall on a weekend or state holiday. From:Coldiron, Samantha J (OGC) To:AOGCC_Public_Notices Subject:Area Injection Orders 18E.007, 28.010, 35A.001, 40.004, 43.002 (CPAI) Date:Thursday, April 24, 2025 9:25:00 AM Attachments:AIO18E.007_AIO28.010_AIO35A.001_AIO40.004_AIO43.002.pdf Docket Number: AIO-25-013 Making mechanical integrity testing notification requirements consistent across Colville River Unit and Greater Moose’s Tooth Unit pools Colville River Unit, Alpine Oil Pool, Qannik Oil Pool, and Nanuq Oil Pool Greater Moose’s Tooth Unit Lookout Oil Pool and Rendezvous Oil Pool Samantha Coldiron AOGCC Special Assistant Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage, AK 99501 (907) 793-1223 Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.alaska.gov ADMINISTRATIVE APPROVALS AREA INJECTION ORDER NO. 2C.096 AREA INJECTION ORDER NO. 16.009 AREA INJECTION ORDER NO. 18E.008 AREA INJECTION ORDER NO. 28.011 AREA INJECTION ORDER NO. 35A.002 AREA INJECTION ORDER NO. 39A.001 AREA INJECTION ORDER NO. 40.005 AREA INJECTION ORDER NO. 43.003 Greg Hobbs, Regulatory Engineer ConocoPhillips Alaska, Inc. P.O. Box 100360 Anchorage, AK 99510-0360 Re: Docket Number: AIO-25-001 Request to change language of Area Injection Order Rule 7 Well Integrity and Confinement Dear Mr. Hobbs: By letter dated January 15, 2025, ConocoPhillips Alaska, Inc. (CPAI) requested the amendment to Rule 7 of the Area Injection Orders listed below: •AIO 18E: Colville River Field, Colville River Unit, Alpine Oil Pool • AIO 28: Colville River Field, Colville River Unit, Nanuq Oil Pool • AIO 35A: Colville River Field, Colville River Unit, Qannik Oil Pool • AIO 39A: Kuparuk River Field, Kuparuk River Unit, Torok Oil Pool • AIO 40: Greater Moose's Tooth Field, Greater Moose's Tooth Unit, Lookout Oil Pool • AIO 43: Greater Moose's Tooth Field, Greater Moose's Tooth and Bear Tooth Units, Rendezvous Oil Pool The purpose of the amendment is to clarify the appropriate process and current practice when pressure communication, leakage or lack of injection zone isolation is indicated by certain data observed by the operator. CPAIproposed adopting the Rule 7 language from the recently approved AIO 45 Coyote Oil Pool. AIO 2C.096, AIO 16.009, AIO 18E.008, AIO 28.011, AIO 35A.002, AIO 39A.001, AIO 40.005, and AIO 43.003 May 12, 2025 Page 2 of 3 In accordance with 20 AAC 25.556(d), the Alaska Oil and Gas Conservation Commission (AOGCC) hereby GRANTS CPAI’s request to amend Rule 7 of the AIOs listed above. Additionally, on its own motion, and in accordance with 20 AAC 25.556(d), the AOGCC has determined that Rule 7 of the CPAI AIO’s listed below should also be amended for the same reasons. • AIO 2C: Kuparuk River Field, Kuparuk River Unit, Kuparuk River, West Sak, and Tabasco Oil Pools • AIO 16: Kuparuk River Field, Kuparuk River Unit, Tarn Oil Pool Now Therefore it is Ordered: Rule 7 of each of the AIO’s listed is amended to read as follows: Rule 7 Well Integrity and Confinement Whenever an indication of pressure communication, leakage, or lack of injection zone isolation occurs, the operator must notify the AOGCC by the next business day. Such indication may arise from information including but not limited to injection rate, operating pressure observation, test, survey, log, or outer anulus pressure monitoring in wells within one-quarter mile radius of where the applicable defined oil pool is not cemented. If the operator's investigation supports a conclusion of pressure communication, leaking, or lack of injection zone isolation, the operator must submit a corrective action plan to the AOGCC, following the applicable unit sundry matrix order. The operator must shut in any well for which: (a) continued operation would be unsafe, (b) continued operation would threaten contamination of freshwater; or (c) the AOGCC directs the operator to shut in the well. The operator must submit a monthly report of daily tubing and casing annuli pressures and injection rate for injection wells that (a) are subject to administrative approval (AA) to operate; or (b) lack injection zone isolation. DONE at Anchorage, Alaska and dated May 12, 2025. Jessie L. Chmielowski Gregory C. Wilson. Commissioner, Chair Commissioner Gregory C. Wilson Digitally signed by Gregory C. Wilson Date: 2025.05.12 12:12:38 -08'00' Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2025.05.12 13:42:57 -08'00' AIO 2C.096, AIO 16.009, AIO 18E.008, AIO 28.011, AIO 35A.002, AIO 39A.001, AIO 40.005, and AIO 43.003 May 12, 2025 Page 3 of 3 RECONSIDERATION AND APPEAL NOTICE As provided in AS 31.05.080(a), within 20 days after written notice of the entry of this order or decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration of the matter determined by it. If the notice was mailed, then the period of time shall be 23 days. An application for reconsideration must set out the respect in which the order or decision is believed to be erroneous. The AOGCC shall grant or refuse the application for reconsideration in whole or in part within 10 days after it is filed. Failure to act on it within 10 days is a denial of reconsideration. If the AOGCC denies reconsideration, upon denial, this order or decision and the denial of reconsideration are FINAL and may be appealed to superior court. The appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision denying reconsideration, UNLESS the denial is by inaction, in which case the appeal MUST be filed within 40 days after the date on which the application for reconsideration was filed. If the AOGCC grants an application for reconsideration, this order or decision does not become final. Rather, the order or decision on reconsideration will be the FINAL order or decision of the AOGCC, and it may be appealed to superior court. That appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision on reconsideration. In computing a period of time above, the date of the event or default after which the designated period begins to run is not included in the period; the last day of the period is included, unless it falls on a weekend or state holiday, in which event the period runs until 5:00 p.m. on the next day that does not fall on a weekend or state holiday. From:Coldiron, Samantha J (OGC) To:AOGCC_Public_Notices Subject:[AOGCC_Public_Notices] Area Injection Orders Admin Approvals (CPAI) Date:Monday, May 12, 2025 1:54:34 PM Attachments:AIO2C.096, AIO16.009, AIO18E.008, AIO28.011, AIO35A.002, AIO39A.001, AIO40.005, and AIO43.003.pdf Docket Number: AIO-25-001 Request to change language of Area Injection Order Rule 7 Well Integrity and Confinement Samantha Coldiron AOGCC Special Assistant Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage, AK 99501 (907) 793-1223 __________________________________ List Name: AOGCC_Public_Notices@list.state.ak.us You subscribed as: samantha.coldiron@alaska.gov Unsubscribe at: https://list.state.ak.us/mailman/options/aogcc_public_notices/samantha.coldiron%40alaska.go v INDEXES 11 January 15, 2025 VIA E-MAIL DELIVERY Victoria Loepp Senior Petroleum Engineer Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue, Suite 100 Anchorage, Alaska 99501-3572 Subject: Area Injection Order Rule 7 Proposed Language Change Dear Ms. Loepp, ConocoPhillips Alaska Inc. (CPAI) makes this application to amend the Area Injection Orders listed below to clarify the appropriate process and current practice when pressure communication, leakage or lack of injection zone isolation is indicated by certain data observed by the operator. An example of the current area injection order language from the Alpine Area Injection Order (AIO 18E) is as follows: Whenever any pressure communication, leakage or lack of injection zone isolation is indicated by an injection rate, operating pressure observation, test, survey, log, or other evidence, the operator shall, by the next business day, notify the Commission and submit a plan of corrective action on a Form 10-403 for Commission approval. The Operator shall immediately shut in the well if continued operation would be unsafe or would threaten contamination of freshwater, or if so directed by the AOGCC. A monthly report of daily tubing and casing annuli pressures and injection rates must be provided to the AOGCC for all injection wells indicating well integrity failure or lack of injection zone isolation. There are two concerns with the current language. First, the rule requires the filing of a form 10-403 report with the AOGCC on the next business day. This does not represent current practice. Instead, the rule should require the Operator to notify the AOGCC by the next business day and file a report following the applicable AOGCC Sundry matrix only if the Operator’s investigation supports a conclusion of pressure communication, leaking, or lack of injection zone isolation. Second, the current rule requires the submission of daily tubing and casing annuli pressure for all injection wells indicating well integrity failure or lack of injection zone isolation. The current practice is not to submit this information for wells that are shut in. The shut in wells are separately tracked in the annual long-term shut-in wells report to the AOGCC. Greg Hobbs Principal Regulatory Engineer 700 G Street, ATO 1562 Anchorage, AK 99510 (907) 263-4749 (office) Greg.S.Hobbs@conocophillips.com By Samantha Coldiron at 12:09 pm, Jan 15, 2025 2 CPAI proposes the following language from the recent Coyote Oil Pool area injection order to resolve both issues: Whenever an indication of pressure communication, leakage, or lack of injection zone isolation occurs, the operator must notify the AOGCC by the next business day. Such indication may arise from information including but not limited to injection rate, operating pressure observation, test, survey, log, or outer anulus pressure monitoring in wells within one-quarter mile radius of where the COP is not cemented. If the operator’s investigation supports a conclusion of pressure communication, leaking, or lack of injection zone isolation, the operator must submit a corrective action plan to the AOGCC, following the [KRU, CRU or GMTU sundry matrix order as applicable]. The operator must shut in any well for which: (a) continued operation would be unsafe, (b) continued operation would threaten contamination of freshwater; or (c) the AOGCC directs the operator to shut in the well. The operator must submit a monthly report of daily tubing and casing annuli pressures and injection rate for injection wells that (a) are subject to administrative approval (AA) to operate; or (b) lack injection zone isolation. If acceptable, CPAI requests that the rule be modified in the following orders with appropriate reference to the applicable sundry matrix order: x AIO 18E: Colville River Field, Colville River Unit, Alpine Oil Pool x AIO 28: Colville River Field, Colville River Unit, Nanuq Oil Pool x AIO 35A: Colville River Field, Colville River Unit, Qannik Oil Pool x AIO 39A: Kuparuk River Field, Kuparuk River Unit, Torok Oil Pool x AIO 40: Greater Moose’s Tooth Field, Greater Moose’s Tooth Unit, Lookout Oil Pool x AIO 43: Greater Moose’s Tooth Field, Greater Moose’s Tooth and Bear Tooth Units, Rendezvous Oil Pool CPAI appreciates your consideration of this request. Feel free to contact me at 907-263-4749 or greg.s.hobbs@conocophillips.com with any questions. Sincerely, Greg Hobbs Regulatory Engineer ConocoPhillips Alaska, Inc. Digitally signed by Greg Hobbs DN: OU=Regulatory Engineer, O= ConocoPhillips Alaska Wells, CN=Greg Hobbs, E=greg.s.hobbs@ conocophillips.com Reason: I am the author of this document Location: Date: 2025.01.15 10:49:29-09'00' Foxit PDF Editor Version: 13.0.0 Greg Hobbs 10 P.O. BOX 100360 ANCHORAGE, ALASKA 99510-0360 Commissioner Jessie Chmielowski Alaska Oil & Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, AK 99501 Commissioner Chmielowski: ConocoPhillips Alaska, Inc (CPAI). presents the attached cancellation request for Administrative Approval AA 40.001. GMTU MT6-09 (PTD 218-134) was granted AIO 40.001 on October 27, 2021, due to known TxIA communication. A RWO was completed April 17, 2022,which installed new 4.5”, L-80, Hyd 563 tubing. Subsequent the RWO the well has completed monitor periods on both water and gas injection and no TxIA communication was observed. As the RWO repaired the annular communication, AIO 40.001 is no longer needed. CPAI requests that AIO 40.001 be canceled and that MT6-09 be returned to normal WAG operation under AIO 40. If you need additional information, please contact us at your convenience. Sincerely, Kate Dodson Senior Well Intervention Engineer ConocoPhillips Alaska, Inc. Office phone: 907-265-6181 Email: kate.dodson@conocophillips.com July 8, 2022 By Samantha Carlisle at 1:49 pm, Jul 08, 2022 MT6-09 90-Day Bleed History WELL DATE STR-PRES END-PRES DIF-PRES CASING MT6-09 2022-05-07 200.0 625 425.0 IA MT6-09 2022-05-11 850.0 819 -31.0 IA MT6-09 2022-05-16 840.0 340 -500.0 IA MT6-09 2022-05-27 988.0 1724 736.0 IA MT6-09 2022-06-04 2037.0 1492 -545.0 IA MT6-09 2022-06-05 2063.0 1836 -227.0 IA MT6-09 2022-06-07 953.0 650 -303.0 OA MT6-09 2022-06-12 1020.0 375 -645.0 OA MT6-09 2022-06-15 2410.0 1000 -1410.0 IA Last Tag Annotation Depth (ftKB) End Date Wellbore Last Mod By LAST TAG:MT6-09 jennalt Last Rev Reason Annotation End Date Wellbore Last Mod By Rev Reason: Pulled DFCV, pushed Obsidian Plug to TD. 5/3/2022 MT6-09 famaj Casing Strings Casing Description CONDUCTOR OD (in) 20 ID (in) 19.12 Top (ftKB) 36.7 Set Depth (ftKB) 115.0 Set Depth (TVD) … 115.0 Wt/Len (lb… 94.00 Grade H-40 Top Connection Welded Casing Description SURFACE OD (in) 13 3/8 ID (in) 12.40 Top (ftKB) 36.7 Set Depth (ftKB) 2,146.0 Set Depth (TVD) … 2,030.8 Wt/Len (lb… 68.00 Grade L-80 Top Connection TXP Casing Description INTERMEDIATE #1 OD (in) 9 5/8 ID (in) 8.84 Top (ftKB) 34.2 Set Depth (ftKB) 10,395.7 Set Depth (TVD) … 7,286.1 Wt/Len (lb… 40.00 Grade TN-80 Top Connection TXP Casing Description TIEBACK STRING OD (in) 7 ID (in) 6.28 Top (ftKB) 32.1 Set Depth (ftKB) 9,767.0 Set Depth (TVD) … 6,907.6 Wt/Len (lb… 26.00 Grade L80 Top Connection TSHBlue Casing Description INTERMEDIATE #2 SDL LINER OD (in) 7 ID (in) 6.28 Top (ftKB) 9,754.6 Set Depth (ftKB) 12,026.0 Set Depth (TVD) … 7,897.1 Wt/Len (lb… 26.00 Grade L-80 Top Connection Tenaris Blue Liner Details: excludes liner, pup, joints, casing, sub , shoe , float... Top (ftKB) Top (TVD) (ftKB) Top Incl (°) Item Des Com Nominal ID (in) 9,754.6 6,900.1 52.91 SBE Seal Bore Extension 7.375 9,787.1 6,919.7 52.91 SEAL ASSY Latching Seal assy (5.76' seals in LSS below) 6.170 9,789.9 6,921.4 52.91 SETTING SLEEVE HRD-E Liner Setting Sleeve 7.735 9,798.8 6,926.8 52.91 QUICK CONNECT HP Liner Quick Connect,w/Bullet Seals 7" 32# Tenaris Blue 6.151 9,804.4 6,930.2 52.91 INT CASING Pup 7" 26# L-80 Liner Tenaris Blue Liner 6.276 11,983.0 7,891.8 82.87 INT CASING 7" 32# L-80 Liner Tenaris Blue Casing joint 6.276 12,019.8 7,896.3 83.29 STABILIZER Reamer Shoe Stabilizer w/ Spline Profile, 7" 32# MYS110 Tenaris Blue 6.080 Casing Description PRODUCTION LINER OD (in) 4 1/2 ID (in) 3.96 Top (ftKB) 11,864.2 Set Depth (ftKB) 16,090.3 Set Depth (TVD) … 7,954.8 Wt/Len (lb… 12.60 Grade L-80 Top Connection TXP Liner Details: excludes liner, pup, joints, casing, sub , shoe , float... Top (ftKB) Top (TVD) (ftKB) Top Incl (°) Item Des Com Nominal ID (in) 11,864.2 7,876.6 81.76 PACKER HRDE ZXP 5.75" SBE (16.10') 5.000 11,890.7 7,880.3 82.35 HANGER 4-1/2" x 7" Flex Lock Hgr H521 Box x TXP Pin 3.875 Tubing Strings: string max indicates LONGEST segment of string Tubing Description Tubing – Completion Upper String … 4 1/2 ID (in) 3.96 Top (ftKB) 28.7 Set Depth (ft… 11,875.3 Set Depth (TVD… 7,878.2 Wt (lb/ft) 12.60 Grade L-80 Top Connection Hyd563 Completion Details: excludes tubing, pup, space out, thread, RKB... Top (ftKB) Top (TVD) (ftKB) Top Incl (°) Item Des Nominal ID (in) OD Nominal (in)Make Model 28.7 28.7 0.00 Hanger 3.958 13.350 FMC TC-EMS 2,018.1 1,924.0 33.00 Nipple - X 3.813 4.500 HES X-Nipple 11,114.1 7,663.2 64.79 Mandrel 3.884 4.500 Camco KBG2 11,223.1 7,707.1 67.58 Nipple - X 3.813 4.500 HES X-Nipple 11,775.3 7,862.3 79.81 Packer 3.880 4.500 SLB SLB Perm PKR 11,832.5 7,871.9 81.06 Nipple - DB, XN, DS, D 3.750 4.500 SLB DB-6 nipple 11,860.0 7,876.0 81.67 No-Go Locator 3.930 5.000 Baker No-Go 11,861.0 7,876.1 81.69 Seal Assembly 3.930 5.000 Baker Bullet Mandrel Inserts : excludes pulled inserts St ati on N o/Top (ftKB) Top (TVD) (ftKB) Top Incl (°) Make Model OD (in) Serv Valve Type Latch Type Port Size (in) TRO Run (psi) Run Date Com 1 11,114.1 7,663.2 64.79 Camco 1 GAS LIFT DMY BK 0.000 0.0 5/2/2022 HORIZONTAL, MT6-09, 5/4/2022 7:43:47 PM Vertical schematic (actual) PRODUCTION LINER ; 11,864.2-16,090.3 INTERMEDIATE #2 SDL LINER; 9,754.6-12,026.0 Seal Assembly; 11,861.0 No-Go Locator; 11,860.0 Pup Joint; 11,844.4 Nipple - DB, XN, DS, D; 11,832.5 Packer; 11,775.3 Nipple - X; 11,223.1 Mandrel; 11,114.1 INTERMEDIATE #1; 34.2- 10,395.7 TIEBACK STRING; 32.1-9,767.0 SURFACE; 36.7-2,146.0 Nipple - X; 2,018.1 CONDUCTOR; 36.7-115.0 Pup Joint; 30.9 Hanger; 28.7 WNS INJ KB-Grd (ft) 36.64 RR Date 12/22/201 8 Other Elev… MT6-09 ... TD Act Btm (ftKB) 16,296.0 Well Attributes Field Name LOOKOUT Wellbore API/UWI 501032077900 Wellbore Status INJ Max Angle & MD Incl (°) 92.48 MD (ftKB) 15,327.65 WELLNAME WELLBOREMT6-09 Annotation LAST WO: End Date 4/17/2022 H2S (ppm) DateComment SSSV: X NIPPLE HORIZONTAL, MT6-09, 5/4/2022 7:43:48 PM Vertical schematic (actual) PRODUCTION LINER ; 11,864.2-16,090.3 INTERMEDIATE #2 SDL LINER; 9,754.6-12,026.0 Seal Assembly; 11,861.0 No-Go Locator; 11,860.0 Pup Joint; 11,844.4 Nipple - DB, XN, DS, D; 11,832.5 Packer; 11,775.3 Nipple - X; 11,223.1 Mandrel; 11,114.1 INTERMEDIATE #1; 34.2- 10,395.7 TIEBACK STRING; 32.1-9,767.0 SURFACE; 36.7-2,146.0 Nipple - X; 2,018.1 CONDUCTOR; 36.7-115.0 Pup Joint; 30.9 Hanger; 28.7 WNS INJ MT6-09 ... WELLNAME WELLBOREMT6-09 Comment Set 4.5" MCX Inj valve (SN: 42… Submit to: OOPERATOR: FIELD / UNIT / PA D: DATE: OPERATOR REP: AOGCC REP: Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD 2180480 Type Inj W Tubing 1052 1060 1053 1051 Type Test P Packer TVD 7938 BBL Pump 2.9 IA 480 2200 2160 2150 Interval I Test psi 1985 BBL Return 2.4 OA 228 318 316 315 Result P Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD 2181340 Type Inj W Tubing 964 967 965 965 Type Test P Packer TVD 7862 BBL Pump 3.6 IA 810 3300 3240 3240 Interval I Test psi 3000 BBL Return 2.5 OA 297 665 653 647 Result P Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result TYPE INJ Codes TYPE TEST Codes INTERVAL Codes Result Codes W = Water P = Pressure Test I = Initial Test P = Pass G = Gas O = Other (describe in Notes) 4 = Four Year Cycle F = Fail S = Slurry V = Required by Variance I = Inconclusive I = Industrial Wastewater O = Other (describe in notes) N = Not Injecting ConocoPhillips Alaska Inc, Alpine / GMTU / MT6 PAD Brian Bixby Hembree / Hills 05/20/22 Notes:Initial MITIA post RWO per Sundry # 321-634 Notes: MT6-08 MT6-09 Notes:Initial MITIA post RWO per Sundry # 321-633 and MITIA to MAIP per AIO 40.001 Notes: Notes: STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION MMec h an i c al Int egr i t y Tes t jim.regg@alaska.gov;AOGCC.Inspectors@alaska.gov;phoebe.brooks@alaska.gov chris.wallace@alaska.gov Form 10-426 (Revised 01/2017)MIT GMTU MT6-08 & 09 05-20-22.xlsx Submit to: OOPERATOR: FIELD / UNIT / PA D: DATE: OPERATOR REP: AOGCC REP: Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD 2181340 Type Inj G Tubing 3327 3339 3342 3346 Type Test P Packer TVD 7862 BBL Pump 2.6 IA 1520 4000 3980 3980 Interval V Test psi 3000 BBL Return 2.7 OA 630 900 900 900 Result P Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result TYPE INJ Codes TYPE TEST Codes INTERVAL Codes Result Codes W = Water P = Pressure Test I = Initial Test P = Pass G = Gas O = Other (describe in Notes) 4 = Four Year Cycle F = Fail S = Slurry V = Required by Variance I = Inconclusive I = Industrial Wastewater O = Other (describe in notes) N = Not Injecting STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION MMec h an i c al Int egr i t y Tes t jim.regg@alaska.gov;AOGCC.Inspectors@alaska.gov;phoebe.brooks@alaska.gov chris.wallace@alaska.gov Notes:MITIA to MAIP per AIO 40.001 OOA 100 110 110 110 Notes: MT6-09 Notes: Notes: Notes: ConocoPhillips Alaska Inc, Alpine / GMTU / MT6 PAD Bob Noble Miller / Weimer 06/07/22 Form 10-426 (Revised 01/2017)MIT GMTU MT6-09 06-07-22.xlsx By Grace Salazar at 1:21 pm, May 26, 2021 From:Salazar, Grace (OGC) To:Glessner, Dana Cc:Roby, David S (OGC) Subject:Conservation Order No. 605A.001 an Area Injection Order No. 40.002 Date:Wednesday, December 1, 2021 7:05:00 AM Attachments:CO 605A.001 and AIO 40.002.pdf Hello Dana, The Alaska Oil and Gas Conservation Commission has issued the attached Order, granting Conoco Phillips Alaska, Inc.’s request for administrative approval to amend Conservation Order No. 605A for the Qannik Oil Pool and Area Injection Order No. 40 for the Lookout Oil Pool. If you have any questions, please do not hesitate to contact Mr. Dave Roby, Senior Reservoir Engineer, at (907) 793-1232 or via email at dave.roby@alaska.gov. Grace ____________________________________ Respectfully, M. Grace Salazar, Special Assistant Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage, AK 99501 Direct: (907) 793-1221 Email: grace.salazar@alaska.gov https://www.commerce.alaska.gov/web/aogcc/ 7 ConocoPhillips April 22, 2021 Jeremy Price, Chair Alaska Oii and Gas Conservation Commission 333 W. 7th Ave #100 Anchorage, Alaska, 99501-3539 RECEIVED 8y Grace Salazar at 9.49 am, Apr 23, 2021 Stephen Thatcher Manager, WN5 Development North Slope Development ConocoPhillips Alaska, Inc. P.O. Box 100360 Anchorage, AK 99510-0360 phone 907.263.4464 RE: Request for Administrative Amendments, Qannik Oil Pool and Lookout Oil Pool, North Slope, AK Dear Commissioner Price, ConocoPhillips Alaska, Inc. (CPAI) as Operator of the Colville River Unit (CRU) and Greater Moose's Tooth Unit (GMTV) and on behalf of the CRU and GMTU working interest owners (WIO), requests that the Alaska Oil and Gas Conservation Commission (AOGCC) administratively amend the conservation order (CO) for the Qannik Oii Pool (QOP) and the area injection order (A10) for the Lookout Oil Pool (LOP). This request is being made concurrently with applications for the Rendezvous Oil Pool (ROP) CO and AIO. Those applications also provide further background for this request. The OOP is currently approved for production commingling with other CRU pools and the LOP. The ROP CO application explains that like the LOP, the ROP is an Alpine formation reservoir that is expected to be fully compatible with production from the other CRU and GMTU oil pools. CPAI requests that CO No. 605.003, Rule 6 of the QOP be amended to allow commingling of ROP production in surface facilities prior to custody transfer, as follows: CO 605.003 Rule 6 Common Production Facilities and Surface Commingling a. Production from the Qannik Oil Pool and other CRU and GMTU pools may be commingled in surface facilities prior to custody transfer. b. Production shall be allocated to wells within the Qannik Oil Pool in accordance with the procedures described in Section 6.0 of CPAI's application, dated April 3, 2008. c. Each producing well must be tested a minimum of twice per month. d. The Commission may require more frequent or longer testing if the allocation quality deteriorates. e. The operator shall retain electronic file(s) containing daily allocation data and daily test data for a minimum of five years. f. The operator shall provide the Commission an annual well test and allocation review report in conjunction with the annual reservoir surveillance report required under Rule 9. Request for Administrative Amendments April 22, 2021 Page 2 of 2 CPAI also requests that the LOP AIO 40, Rule 3 be amended so that the fluids authorized for injection in the EOR interval include the following: • Small amounts of Class II fluids, which will be mixed with the source or produced water including: sump fluid, hydro -test fluid, rinsate from washing mud hauling trucks, excess well -work fluids, meltwater collected from well cellars. These fluids are currently approved as an EOR injection fluid in the AOP (AIO 18E) and requested in the concurrent ROP AIO application. The proposed language limits injection to small quantities that must be mixed with source or produced water. Additionally, like the AOP and ROP, the LOP is an Alpine formation reservoir, and these injection fluids are expected to be fully compatible with the LOP and are not expected to negatively impact hydrocarbon recovery. CPAI is requesting the addition of these fluids to maintain consistency across CPAI operated pools and also for operational flexibility of remote operations where storage capacity is limited. Please contact Dana Glessner (265-6478, glessd@conocophillips.com) if you have questions or require additional information. Regards, Stephen Thatcher Manager, WNS Development North Slope Operations and Development Cc: Chait Borade, Arctic Slope Regional Corporation Erik Kenning, Arctic Slope Regional Corporation Tom Stokes, Alaska Department of Natural Resources, Division of Oil and Gas Wayne Svejnoha, United States Department of Interior, Bureau of Land Management P.O. BOX 100360 ANCHORAGE, ALASKA 99510-0360 October 13, 2021 Commissioner Jessie Chmielowski Alaska Oil & Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, AK 99501 Commissioner Chmielowski: ConocoPhillips Alaska, Inc. presents the attached proposal to apply for Administrative Approval to allow GMTU injection well MT6-09 (PTD 218-134-0) to continue water- only injection service with known TxIA communication. If you need additional information, please contact us at your convenience. Sincerely, Travis Smith Well Intervention & Integrity Engineer ConocoPhillips Alaska, Inc. Office phone: (907) 670-4014 BySamanthaCarlisleatSm,Oct1,2021 P.O. BOX 100360 ANCHORAGE, ALASKA 99510-0360 1 Greater Moose’s Tooth Unit Well MT6-09 (PTD 218-134-0) Technical Justification for Administrative Relief Request Purpose ConocoPhillips Alaska, Inc. (CPAI) requests that the AOGCC approve this Administrative Approval request to allow water-only injection for Greater Moose’s Tooth Unit injector MT6-09 (PTD 218-134-0). The well displays tubing by inner annulus communication during water injection. Well History and Status Greater Moose’s Tooth Unit injector MT6-09 was completed in December 2018. MT6-09 was initially reported to the Commission on September 7, 2021 for inner annulus pressurization while on water injection. CPAI immediately attempted a temperature and acoustic LDL on September 8, 2021. This log did not identify an acoustic anomaly in the well, and an inconclusive slight temperature feature at the gas lift mandrel. The dummy valve in this mandrel was replaced with a high-sealibility dummy valve, and the well was returned to water injection for a monitoring period. The TxIA communication persisted after the dummy valve swap. MT6-09 is constructed with three casing strings: a 13-3/8” surface casing, 9-5/8” intermediate casing string, and a 7” steerable drilling liner (SDL) hung from a liner hanger and tied back to surface. The production section is completed with 4-1/2” liner tied back to surface with the 4- 1/2” production tubing. While TxIA communication puts injection pressure on the 7” casing, the additional casing strings still offer redundant barriers. These are discussed in detail below. CPAI believes that MT6-09’s current condition (and the Operating and Monitoring Plan below) allow the well to be operated safely without threatening human safety or the environment. Therefore, CPAI request Administrative Approval that will allow MT6-09 to continue water- only injection with known TxIA communication. Barrier and Hazard Evaluation Barriers in place are sufficient to allow safe operation with water injection service. Tubing: The 4-1/2”, 12.6 lb/ft, L-80 tubing to the seal assembly at 11,860’ MD (7,876’ TVD) will pass MIT-IA criteria—most recently to 3,000 psi on October 12, 2021. There is known TxIA communication, however, based on TIO trends while on injection. Intermediate casing #2: The 7”, 26 lb/ft, L-80 Tie-back casing and SDL string has integrity to the Baker SLZX liner packer at 9,776’ MD (6,913’ TVD) based on an MIT-OA performed to 1,800 psi on October 12, 2021. Additionally, the 7” tie-back casing and SDL string have integrity to the seal bore assembly at 11,860’ MD (7,876’ TVD) based on the aforementioned passing MIT-IA and TIO trends. P.O. BOX 100360 ANCHORAGE, ALASKA 99510-0360 2 Intermediate casing #1: The 9-5/8”, 40 lb/ft, TN-80 casing has integrity to the Baker SLZX liner packer at 9,776’ MD (6,913’ TVD) based on an MIT-OA performed to 1,800 psi on October 12, 2021 as well as TIO trends. Surface casing: The 13-3/8”, 68 lb/ft, L-80 surface casing has an internal yield pressure rating of 5,020 psi. The surface casing has integrity based on TIO trends. Primary barrier: The TxIA communication precludes relying on the tubing and seal assembly as the primary barrier during water injection to prevent a release from the well and provide zonal isolation. The primary barrier during water injection is the 7” intermediate casing. The inner annulus (4-1/2” x 7”) pressure will be allowed to equalize with tubing injection pressure to a maximum of 2,600 psi. Secondary barrier: The 9-5/8” intermediate casing is the secondary barrier during water injection, should the 7” intermediate casing fail. The Do Not Exceed (DNE) pressure on the 7” x 9-5/8” OA will remain at the 1,000 psi that is standard for CPAI wells at WNS. Tertiary barrier: The surface casing will act as a tertiary barrier during water injection, in the unlikely case that the first two barriers have simultaneous failures. Monitoring: This well will be monitored real time for wellhead pressure changes. Any pressure trends that indicate further annular communication require investigation, Commission notification, and corrective action, up to and including a shut-in of the well. TIO trends are compiled, reviewed, and submitted to the AOGCC for review on a monthly basis. Proposed Operating and Monitoring Plan 1. Well will be used for water injection only, gas injection not allowed; 2. Perform a passing MITIA every 2-years to maximum anticipated injection pressure; 3. Allow operating IA (4-1/2” x 7”) pressure to equalize with tubing injection pressure to a maximum of 2,600 psi during water injection service; operating OA (7” x 9-5/8”) pressure up to 1,000 psi; 4. Pressure transmitters will be maintained on the IA and OA allowing real time monitoring and alarm notifications; 5. Submit monthly reports of daily tubing, IA, and OA pressures, injection volumes and pressure bleeds for all annuli; 6. Shut-in the well should diagnostic testing or injection rates and pressures indicate further problems with appropriate notification to the AOGCC; 7. MIT Anniversary date to be set the month of June 2020 to align the 2-year AOGCC witnessed testing with the UIC MIT permanent 4-year scheduled pad testing; Last Tag Annotation Depth (ftKB) End Date Wellbore Last Mod By LAST TAG:MT6-09 jennalt Last Rev Reason Annotation End Date Wellbore Last Mod By REV REASON: Replace Gas Lift DV 9/22/2021 MT6-09 praffer Casing Strings Casing Description CONDUCTOR OD (in) 20 ID (in) 19.12 Top (ftKB) 36.7 Set Depth (ftKB) 115.0 Set Depth (TVD) … 115.0 Wt/Len (l… 94.00 Grade H-40 Top Thread Welded Casing Description SURFACE OD (in) 13 3/8 ID (in) 12.40 Top (ftKB) 36.7 Set Depth (ftKB) 2,146.0 Set Depth (TVD) … 2,030.8 Wt/Len (l… 68.00 Grade L-80 Top Thread TXP Casing Description INTERMEDIATE #1 OD (in) 9 5/8 ID (in) 8.84 Top (ftKB) 34.2 Set Depth (ftKB) 10,395.7 Set Depth (TVD) … 7,286.1 Wt/Len (l… 40.00 Grade TN-80 Top Thread TXP Casing Description TIEBACK STRING OD (in) 7 ID (in) 6.28 Top (ftKB) 32.1 Set Depth (ftKB) 9,767.0 Set Depth (TVD) … 6,907.6 Wt/Len (l… 26.00 Grade L80 Top Thread TSHBlue Casing Description INTERMEDIATE #2 SDL LINER OD (in) 7 ID (in) 6.28 Top (ftKB) 9,754.6 Set Depth (ftKB) 12,026.0 Set Depth (TVD) … 7,897.1 Wt/Len (l… 26.00 Grade L-80 Top Thread Tenaris Blue Liner Details Top (ftKB) Top (TVD) (ftKB) Top Incl (°) Item Des Com Nominal ID (in) 9,754.6 6,900.1 52.91 SBE Seal Bore Extension 7.375 9,787.1 6,919.7 52.91 SEAL ASSY Latching Seal assy (5.76' seals in LSS below) 6.170 9,789.9 6,921.4 52.91 SETTING SLEEVE HRD-E Liner Setting Sleeve 7.735 9,798.8 6,926.8 52.91 QUICK CONNECT HP Liner Quick Connect,w/Bullet Seals 7" 32# Tenaris Blue 6.151 9,804.4 6,930.2 52.91 INT CASING Pup 7" 26# L-80 Liner Tenaris Blue Liner 6.276 11,983.0 7,891.8 82.87 INT CASING 7" 32# L-80 Liner Tenaris Blue Casing joint 6.276 12,019.8 7,896.3 83.29 STABILIZER Reamer Shoe Stabilizer w/ Spline Profile, 7" 32# MYS110 Tenaris Blue 6.080 Casing Description PRODUCTION LINER OD (in) 4 1/2 ID (in) 3.96 Top (ftKB) 11,864.2 Set Depth (ftKB) 16,090.3 Set Depth (TVD) … 7,954.8 Wt/Len (l… 12.60 Grade L-80 Top Thread TXP Liner Details Top (ftKB) Top (TVD) (ftKB) Top Incl (°) Item Des Com Nominal ID (in) 11,864.2 7,876.6 81.76 PACKER HRDE ZXP 5.75" SBE (16.10') 5.000 11,890.7 7,880.3 82.35 HANGER 4-1/2" x 7" Flex Lock Hgr H521 Box x TXP Pin 3.875 Tubing Strings Tubing Description Tubing – Production String Ma… 4 1/2 ID (in) 3.96 Top (ftKB) 28.6 Set Depth (ft… 11,874.7 Set Depth (TVD) (… 7,878.1 Wt (lb/ft) 12.60 Grade L-80 Top Connection Tblue Completion Details Top (ftKB) Top (TVD) (ftKB) Top Incl (°) Item Des Com Nominal ID (in) 28.6 28.6 0.00 HANGER FMC 4-1/2" Tubing Hanger 563 3.958 2,014.8 1,921.2 32.98 NIPPLE NIPPLE,LANDING,4 1/2",X,3.813", TSH Blue 3.813 11,405.9 7,770.9 71.56 NIPPLE NIPPLE,LANDING,4 1/2", 3.813" XN, TSH Blue with RHC Plug Body Installed @ 72° @11,427' 3.750 11,859.4 7,875.9 81.65 NO-GO LOCATOR Locator No-Go 5.75" OD 3.930 11,860.4 7,876.0 81.67 SEAL ASSY Seal Assembly 3.930 Mandrel Inserts St ati on N o/Top (ftKB) Top (TVD) (ftKB) Top Incl (°) Make Model OD (in) Serv Valve Type Latch Type Port Size (in) TRO Run (psi) Run Date Com 1 11,227.5 7,708.8 67.68 Camco KBG-2 1 GAS LIFT DMY BK 9/22/2021 Notes: General & Safety End Date Annotation 1/14/2018 NOTE: View Schematic w/ Alaska Schematic 10.0 MT6-09, 9/29/2021 12:59:51 PM Vertical schematic (actual) PRODUCTION LINER ; 11,864.2-16,090.3 INTERMEDIATE #2 SDL LINER; 9,754.6-12,026.0 SEAL ASSY; 11,860.3 NO-GO LOCATOR; 11,859.4 NIPPLE; 11,405.9 GAS LIFT ; 11,227.5 INTERMEDIATE #1; 34.2- 10,395.7 TIEBACK STRING; 32.1-9,767.0 SURFACE; 36.7-2,146.0 NIPPLE; 2,014.8 CONDUCTOR; 36.7-115.0 HANGER; 28.6 WNS INJ KB-Grd (ft) 36.64 Rig Release Date 12/22/2018 MT6-09 ... TD Act Btm (ftKB) 16,296.0 Well Attributes Field Name LOOKOUT Wellbore API/UWI 501032077900 Wellbore Status INJ Max Angle & MD Incl (°) 92.48 MD (ftKB) 15,327.65 WELLNAME WELLBOREMT6-09 Annotation LAST WO: End DateH2S (ppm) DateComment SSSV: NIPPLE Annular Communication Surveillance 17 Well Name:MMT6-09 Start Date:17-Jul-2021 15 Days:90 End Date:15-Oct-2021 50 60 70 80 90 100 110 120 130 140 150 0 500 1000 1500 2000 2500 3000 17-Jul-2120-Jul-2123-Jul-2126-Jul-2129-Jul-211-Aug-214-Aug-217-Aug-2110-Aug-2113-Aug-2116-Aug-2119-Aug-2122-Aug-2125-Aug-2128-Aug-2131-Aug-213-Sep-216-Sep-219-Sep-2112-Sep-2115-Sep-2118-Sep-2121-Sep-2124-Sep-2127-Sep-2130-Sep-213-Oct-216-Oct-219-Oct-2112-Oct-2115-Oct-21Temperature (degF)Pressure (PSI)Pressure Summary WHP IAP OAP WHT 0 2000 4000 6000 8000 10000 12000 17-Jul-2120-Jul-2123-Jul-2126-Jul-2129-Jul-211-Aug-214-Aug-217-Aug-2110-Aug-2113-Aug-2116-Aug-2119-Aug-2122-Aug-2125-Aug-2128-Aug-2131-Aug-213-Sep-216-Sep-219-Sep-2112-Sep-2115-Sep-2118-Sep-2121-Sep-2124-Sep-2127-Sep-2130-Sep-213-Oct-216-Oct-219-Oct-2112-Oct-2115-Oct-21Injection Rate (BPD or MSCFD)Injection Rate Summary DGI MGI PWI SWI BLPD Submit to: OPERATOR: FIELD / UNIT / PAD: DATE: OPERATOR REP: AOGCC REP: Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD 2181340 Type Inj W Tubing 1900 1900 1900 1897 Type Test P Packer TVD 7876 BBL Pump 4.3 IA 1787 2187 2180 2173 Interval O Test psi 1800 BBL Return 2.8 OA 437 2000 1980 1975 Result P Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD 2181340 Type Inj W Tubing 1897 1900 1900 1900 Type Test P Packer TVD 7876 BBL Pump 1.6 IA 1785 3330 3300 3290 Interval O Test psi 3000 BBL Return 1.6 OA 350 555 554 554 Result P Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result TYPE INJ Codes TYPE TEST Codes INTERVAL Codes Result Codes W = Water P = Pressure Test I = Initial Test P = Pass G = Gas O = Other (describe in Notes) 4 = Four Year Cycle F = Fail S = Slurry V = Required by Variance I = Inconclusive I = Industrial Wastewater O = Other (describe in notes) N = Not Injecting STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION Mechanical Integrity Test jim.regg@alaska.gov;AOGCC.Inspectors@alaska.gov;phoebe.brooks@alaska.gov chris.wallace@alaska.gov Notes:Diagnostic MITOA (7" x 9-5/8") Note: Fill-up volume based on fluid level shot for the OA was 1.4 bbl pre-MIT. Notes: MT6-09 MT6-09 Notes:Diagnostic MITIA (4-1/2" x 7") Notes: Notes: ConocoPhillips Alaska Inc, GREATER MOOSES TOOTH / GMTU / MT6 PAD N/A Hembree 10/12/21 Form 10-426 (Revised 01/2017)MIT GMTU MT6-09 10-12-2021.xlsx 5 d 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 2018 AOGCC 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 predasiiea 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: 0 predastien wells Inner annulus, outer annulus, and tubing pressure shall be senstantly 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, WNS Development North Slope Operations and Development 2 AOGCC 4/3/2018 ITMO: APPLICATIONS OF CONOCOPHILLIPS AK Docket No. CO 18-001 & A10 18-013 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. ) 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: sahile@gci.net AOGCC 4/3/2018 ITMO: APPLICATIONS OF CONOCOPHILLIPS AK Docket No. CO 18-001 & A101 8-013 Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Page 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: sahile@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 &Af018-013 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 & A10 18-013 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. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net AOGCC 1 Doherty. 2 Next up. 4/3/2018 ITMO: APPLICATIONS OF CONOCOPHILLIPS AK Docket No. CO 18-001 & A1018-013 Page 9 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., 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 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., Arch. AK99501 Fax: 907-243-1473 Email: sahile@gci.net AOGCC 4/32018 ITMO: APPLICATIONS OF CONOCOPHILLIPS AK Docket No. CO 18-001 & A10I8-013 Page 11 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., 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 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 & AI018-013 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 & A1018-013 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 Docket No. CO 18-001 & AI018-013 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., Arch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.nel 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: sahile@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., 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 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 CDS. 25 COMMISSIONER SEAMOUNT: Is that well the 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 & AI018-013 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 MPG 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., Anch. 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 & A101 8-013 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., 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 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., 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 & A1018-813 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 135 Christensen Dr., Ste. 2., Anch. AK99501 Fax: 907-243-1473 Email: sahile@gci.net AOGCC 4/3/2018 ITMO: APPLICATIONS OF CONOCOPITLLIPS AK Docket No. CO I8-001 & A1018-013 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 & A10 18-013 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 & A1018-013 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. AK 99501 Fax 907-243-1473 Email: sahile@gci.nel 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., 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 & AI018-013 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. CO 18-001 & A101 8-013 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. I 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. 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 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 4/3/2078 ITMO: APPLICATIONS OF CONOCOPHILLIPS AK Docket No. CO I8-001 & 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., 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 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. 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 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 AOOCC 4/3/2018 1TMO: APPLICATIONS OF CONOCOPHILLIPS AK Docket No. CO 18-001 & A101 8-013 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 & A101 8-013 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., 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 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., 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 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., 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 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., 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 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. 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 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 & A101 8-013 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, GLC 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. AK99501 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 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., 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 & A101 8-013 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 1TMO: APPLICATIONS OF CONOCOPHILLIPS AK DocketNo. 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., 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 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., 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 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 25 Prince Creek and those are actually up in the Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Arch, AK 99501 Fax: 907-243-1473 Email: sahile@gci.net U61KK4 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 FAS16fKi 4/3/2018 ITMO: APPLICATIONS OF CONOCOPHILLIPS AK Docket No. CO 18-001 & AI018-013 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. 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 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 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 I8-001 & A101 8-013 Page 551 CHAIR FRENCH: So just a quick operations question, Mr. Cookson. You're going to start off with seawater for injection, but you think that you'll transition over to produced water at some time in the future? MR. COOKSON: I'm not sure. I wouldn't say that I think that we will, that's a possibility and we leave that open. It was in the -- you know, we have that list of possible fluids to inject, we included both. CHAIR FRENCH: Okay. But does..... MR. COOKSON: Just for completeness. For completeness so that when that does happen we don't have to come back..... CHAIR FRENCH MR. COOKSON: CHAIR FRENCH: MR. COOKSON: CHAIR FRENCH: MR. COOKSON today..... Sure. .....here and ask..... Sure. .....you guys for permission. Thank you. That concludes our testimony for CHAIR FRENCH: Excellent. MR. COOKSON: .....or our prepared testimony. CHAIR FRENCH: Prepared testimony. Excellent. 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 18-001 & AI018-013 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 18-001 &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., Arch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net AOGCC 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 & AIOI 8-013 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 & A1018-013 Page 59 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 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) ffr� g 60- JC)JU CloIam,:�iP n v �S pl�`` f d r CP �'__ At6 Ura4-A-))y" a st- CP --Z t\JD %//C/0rl, 0, Z oe-IoJJ �OG�Q N'o ConocoPhillips Lookout Pool Hearing Conservation & AlO 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 cono4 illips • 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 • Exploration Well SHL — Development Well 0 Proposed Lookout PA 1111 Road or Pad — Pipeline OAK 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 Col \ � River I CD5, Lookout PA Boundary MTS Pad GMTS Project e 0� aQ�Q bd • • Q�°,arc e� Greater cc�~�0 c°Mooses GMT2�Qaa Q P7 Tooth Unit \�X •\\\\\\ CD3. \u [pine �+ Y\\\ Central '\�CD2�� ties CD4 1 \ , N • 0 2 mmmmKzz=l Miles ConocoPhillips Alaska Greater Mooses Tooth Unit and Colville River Unit Roads, Pads, & Pipelines 3/20/2018 _ Working Interest Owners: k � ewvfda'`, • 78% ConocoPhillips (Operator) • 22% Anadarko' ! w� Surface Owners: r i4k\ r _. Notification to BLM and i 2 3a -- -- --"""' • Kuukpik Kuukpik per 20AAC ! •BLM 25.402(c)(2) on 2-29-2018 i _._._.: "; — - Greater ____ Subsurface Owners: Mooser Tooth unit i • ASRC 0i@ L.0\\ • BLM � \\ I coivai River - ion. I � Unit I Proposed Lookout Pool Boundary: 15" - IJRE � ,. I ..__ 11NR3E — ;T6 � • M11T6 Well Ped •Includes each full section intersected �� LoPosad Lookout Oil Poe Rw clary Q Leokma Reservoir M by reservoir outline except for Mitre - =Approved; Lookout ParVapYiN Arca = Kuukpik SO.. ASRC Suin,fa� 1 section (no pay) N _; r GMTU Trad k_.iUniT BouMenes ^', c` CPA] Leasee ,6A ConocoPhillips Alaska SaleAnadarkogleasehold to ConocoPhillips is pending - Proposed Lookout Oil Pool Area governmewentt app approval a os 1 1.5 2 Mnes 11251218 ConocoPhillips 1993,'95,'96 2D Seismic Acquisition in NE NPR -A 1998-2000 3D Seismic Acquisition 2001-2002 Drilled Lookout 1 & 2 and Mitre 1 & 1PB1 2008 GMTU Formed 2009 GMTU 11t Expansion 2015 CD5 / West Alpine Development 2015 GMT1/ Lookout Seismic �� 0 0.5 Acquisition 2016-2017 GMT1 1st Construction Season, GMT2 3D Seismic Acquisition Current •Final installation of drillsite facilities and pipelines *First well, MT6-03 spud on March 21, 2018 *First production (two wells) and injection (one well) targeted in Q4, 2018. 2018 - mid 2019 Complete 9 -well drilling program 50 AAOOd021 Greater Mooses Tooth Unit 9A, AA061E 15A AA001802 5l 746 r) Rive sr --- - River - Unit #1 MT6 Well Pad Q PmMad Lookout Oil Pool Boundary Q Lookout Reservoir Q Proposed Lookout PaNdpMing Are. ® Nuukpik Sud.. ASRC Subsudaoa GMTU Tracts %MUnit Boundaries .a Proposed Lookout Oil Pool Area 3"2012010 ConocoPhtulps Z Z 0 0 ~ b- AA081801 NN - �� 0 0.5 1 1.5 2 -, Miles 5l 746 r) Rive sr --- - River - Unit #1 MT6 Well Pad Q PmMad Lookout Oil Pool Boundary Q Lookout Reservoir Q Proposed Lookout PaNdpMing Are. ® Nuukpik Sud.. ASRC Subsudaoa GMTU Tracts %MUnit Boundaries .a Proposed Lookout Oil Pool Area 3"2012010 ConocoPhtulps 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 0 00,11.•0,x. —We« —PFEum. Qcrnn LwYaYltmrvon Q PmyoKC Looxan PA i, D-.01- S. . -.SRC AStt Q P -E Lak.W 0 4 P.18..a ry CPAI _9x Q � A 0 0.5 1 Miles Greater Mooses Tooth Unit Lookout Oil Pool Development Plan Lookoutl 2001 Lookout2 2002 Neutron "Neutron° rvass , Perm ensity ° z Perm ,� `"Densit R ,m im RS �°, �, "` Sonic '.: " GR rm�a c"m , RS ,m , rt Sonic sw NE �..,. a ==na RD orosit uaoa ,:_• RD : ;`Porosity" u MA ° ,,, �. f 0 2 7833'MD 7 63's z V 2 W 50 U 65 W Q W n o G. ` 7834'M 7784' s m a 0 96 Nenua p o ..._ _ -71 01'..s Wn v -7814'Ss w 144 Ali ooQ 8a ds:one not ehind ogged c sing m K � 2Nechelik • / i j iI Kingak Frn 20 0 TRIASSIC Shubllk Fm. ., • � 6 z Sa e"'wig-p•- 'w GP• • m W 245 245 PERMIAN7928' •.. ^.I -7879' gs W O PENNSYLVANIAN 286., - 0 0 WN 620 Lisburne Gp. -- 00 ISSISSIPPIAN SGP f3� I a6n 8 *-Alpine C SS 8000' M * - Primary Source (Kingak) s 129' gross interval 65' gross interval m 79' net pay (0 >15% cutoff) 53' net pay (0 >15% cutoff) 20% avg poro., 84 and avg. perm, 16.4% avg Sw 20% avg poro., 24 and avg. perm, 30.5% avg Sw Cased hole MDT - 42.5° oil Test (4 days) : 4000 BOPD, GOR -1500 cf/bbl Kh: -1300 and -ft CoramPhillips 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 w •W AW a 3 � >5W W r} tEW T1W »W �eW 1BW O p S V aOc O_ C 9 ry f'1 ? M � F 9 R w TTI U 02000 4000 6000 8000 10000flus Cl=20ft 150000 ConocoPhillips Southwest Northeast MITRE PBI LOOKOUT#2 LOOKOUT—1 ]8W - 6 -sand A-sa >9m - 6080 .—__ j Pom6ly>19%cuteN { - elao f}} P0l tl1 Porosity >16% Cutoff 00L Net Pay 20.5 15.5 v. aroeity216635%.d16A% ay. S. 26.0% f >{ _ Not Pay 53' or. Porosity, 18.6% rv. S. 30.5% & 25.6% Porosity>15%>cutotl_- 1000' av PaanPO2631fi5% and 0.5 and Not P ooy TB' av perm 24 and reMmle>aB6ermlon Nh $1.8 6Ss N md m 0 BW Pan 0.1 mtl vv. Pormlty 20.0% ay. S. KN 12]2 mdfi Tsal wl lrac av perm 81 mtl 1000100 00' API GOR 1600 mcl40' e3 Kh 6636 mdK 6636 Fm Pmesure 3TTB psi, a0'APlimm MOT KN -1300 mdA mew Cl or 20 Ift • 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 10 .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 Reservoir Fluid Properties (7800 feet TVDss datum) Property, Units Measured Value Initial Reservoir Pressure, psia 3770 Reservoir Temperature, °F 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) lGIO 90 as 70 Assumed Conditions Pressure = 375004 Temperature =187 current Injectant h 23 60 80 100 120 140 Pore Volume Injected, % PV -&-:eanGas-+-CurrentCoTocs,,srnaIBlend t 0;r_EnrichingFijid jectnnt is i5`� Erriching Fluid -0-20% 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. Conoc4;hinips • 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 fastrg(IN rm) Conoao igffips • 20" Insulated conductor w/ thermo-siphon: • Surface: 16" Hole • Spud Mud—Slightly Inhibited • TO —2100' MD (C-40) • 13-3/8" Casing & Cement to Surface • Install and test BOPE • Intermediate 1: • 12'/." Hole • LSND Mud • TD 7,500' to 11,000' (HRZ) • 9-5/8" Casing • Cement Shoe per AOGCC requirements • Intermediate 2: (Pipe Conveyed section) • 8-Y2" Hole • LSND Mud • 7" Liner (Steerable Drilling System) • TO `8,800' to 12,700' (Alpine C) • Cement Shoe per AOGCC requirements • Run cement quality log on injectors Lateral • 6" Hole • Mineral Oil Base (producers), Water Base (injectors) • 4-Y2" Liner • TD 14,600' to 22,500' • Completion • Liner top packer set above Alpine C within confining zone • Gas lifted producers w/ permanent downhole pressure gauges • Fracture stimulation not anticipated • Wellheads with horizontal tree TOC at least 300' abov Packer and the greater of 500' and or 250' Ivd above Alpine C Request waiver to 20 AAC 25.412(b) —injection well packer set depth Top Alpine C 20" Insulated Conductor 80 feet, cemented to surface Q 116 13418" surface Casing cemented to surface Q 41/2' Tubing 0 O 9618"Casing TOC the greater of 509 and or 259 tvd above shoe 0 " o 0 T' Liner Tubing / Liner Ccmpleticn: 1) 414" Lending Nlpple(3.813" ID) 2) 4-W x 1' GLM 3) 4-h' x V GLM 4) Liner Top Packer / Hanger 5) 4 -NP x 1' GLM 6) Liner Top Packer / Henger wl Tie Back sleeve 7) 4-'f,' Landing Nipple (3.725' NoGo) 8) 4-'/:" Blank Pipe 9) 4-.6' Liner with Pert Pups 4-%" Liner with Ped Pups 8" Hole 5000 —12000 ft horizontal • 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 • Mitre 1— • Plugged and abandoned completed April 21, 2002 • 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. conocow,aups 21 � Iuv IJMIVA 001 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) _n- ConoJ;hillips �L^��l�>=w.Eattas 111.. „ o r � NOGG t 111 �_��® • 111.. 1110=1111 swill 11 ' • 111.. 11 .■c ::. I„I ; 1 1 ED . il�� ... -'_ SIM ■ —_ . 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) _n- ConoJ;hillips MITRE 1P61 LOOKOUT 2 NUIQSUT 1 Base Permafrost at 1000' TVDSS I k6oKOUTI AAITRE 7P81 u CLOVER A ♦ iirip5 Gas lift meter an each producer Four Production Wells Injection meter on each injection well Five Injection Wells GMT Unit ; Colville River Unit Lookout Oil Pool CD5 Production CD5 Injection Lookout Gas Meters at CD5 A Other CRU Drillsites Oil Sales to Alpine Pipeline Seawater 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 7 Colomb[e, 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 AIO 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 IAOGCCI, 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 if to you, contact Dave Roby at (9071793-1232 or dave.robv@alaska.gov. 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 dave.robv@alaska.gov. 2 STATE OF ALASKA ADVERTISING ORDER NOTICE TO PUBLISHER SUBMIT PIVOICE SROaVRVG ADVERTISING ORDER NO., CERTn+6D AFFn AVIT OFPURWCATIOI Wllrl ATTACKED COPY OFADVERTLSMENT. ADVERTISING ORDER NUMBER p AO-18-013 FROM: Alaska Oil and Gas Conservation Commission AGENCY CONTACT: Jody Colombie/Samantha Carlisle DATE OF A.O. 3/12018 AGENCY PHONE: (907) 279-1433 333 West 7th Avenue Anchorage, Alaska 99501 DATES ADVERTISEMENT REQUIRED: COMPANY CONTACT NAME: PHONE NUMBER: ASAP FAX NUMBER: 907 276-7542 TO PUBLISHER: Anchorage Daily News SPECIAL INSTRUCTIONS: 300 W. 31st Ave. Anchorage, Alaska 99503 TYPE OF ADVERTISEMENT: LEGAL I DISPLAY "- CLASSIFIED "" OTHER (Specity belov4 DESCRIPTION PRICE CO-18-001 and AIO-18-013 Initials of who prepared AO: Alaska Non -Taxable 92-600185 """--- 9f19M1'1'IN9'UICL$6fT5'/MGAW..BR'fiStNG:: >::OR»E.RNOe.QkRTrFtFA:A:F.FIUAvty,Qq X > :Pitet:!ciTgoNWY7.gwrrniTP.tit)P7t:oF:;:; :A gy'sit'1TSMENY:to Department of Administration Division of AOGCC 333 West 7th Avenue Anchors e, Alaska 99501 Pae 1 of I Total of All Pa es $ REF Type I Number Amount Dole Comments I PVN JADN89311 2 AD AO-18-013 3 4 FPI AMOUNT SY Act Template PGM LGR Object FY DIST LIQ I 18 A14100 3046 18 z 3 4 5 Purc ieg rity Tide: PurcM1asiog ority's Signahre Telephone Number �2wae L. Citi% 7. A.O. a and receiving ag name must appear on all Invoices aid documents relating to this purchase. 2. The gate is registered free transactions under Chapter a2, IRS code. Registration number 92-73-0006 K. Items are for the euclusive use of the state end nd for resale. DISTRIBUTION... . DWWAR Fi 0041ginal AO Copses. Pp6liRher (faked) llivisipp Fival; Recejving', , Form: 02-901 Revised: 3/112018 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 7s' 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 �SFren�ch� 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 INS 5th day of March, 2018 Notary Public in and for The State of Alaska. Third Division Anchorage, Alaska MY COMMIS O EXPIRES COMMIS:] EXPIRES 0-10,g 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. (CPA0,by applications dated February 28 2018, requests the Alaska Oil and Gas Conservation Commission (AOGCC) establish pool rules for Mair proposed. Lookout Oil Pool (LOP) in the Greater Moose's Tooth Unit and Issue an Area Injection Order to authorize a water alternating enriched gasin action process for enhanced oil recovery purposes in the proposed J. The AOGCC has scheduled a public hearing on the application for April 3, 2018, at 10:00 a.m. at 333 West 7th Avenue, Anchorage, Alaska 99501. In addition, written comments regardingg this application mayy be submitted to the AOGCC at 333 West 7t7 Avenue, Anchorage, Atask 99501. Comments must 6e received no later than the conclusion of the April 3, 2018 hearing. If, because of a disability special accommodations may be needed tc Comment or attend the hearing, contact the AOGCC at (907) 279-1433, no later than March 29, 2018. //sittnature on file// 11011iS S. FrenC Chair, Commission Published: March 4, 2018 DECEIVED Notary 'rublic BRITNEY L. THOMPSON State of Alaska My Commission Expires Feb 23, 2019 MAR 12 2019 AOGCC 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 1 (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 Stephen Thatcher (michal.frystacky@alaska.gov)'; 'Guhl, Meredith (DOA sponsored) Manager, WNS Development (meredith.guhl@alaska.gov)'; Herrera, Matthew F (DOA); 'Jones, Jeffery B (DOA) conocoPhBlips Alaska, Inc. aeffjones@alaska.gov)'; Kair, Michael N (DOA); Laubenstein, Lou (DOA);'Link, Liz M P.O Box 196612 Anchorage, AK 99519-6612 (DOA)'; Loepp, Victoria T (DOA); Mcphee, Megan S (DOA); 'Mumm, Joseph (DOA sponsored) Joseph.mumm@alaska.gov)'; 'Noble, Robert C (DOA) (bob.noble@alaska.gov)';'Paladijczuk, Tracie L (DOA)(tracie.paladijczuk@alaska.gov)'; 'Pasqual, Maria (DOA) (maria.pasqual@alaska.gov)'; 'Regg, James B (DOA) Qim.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 Homer'; 'Dave Harbour';'David Boelens';'David Duffy';'David House';'David McCaleb';'ddonkel@cfl.rr.com'; Diemer, Kenneth (DNR); 'DNROG Units'; 'Donna Ambrui ; '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 Wedman'; '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 (DNR); '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'; 'Eppie 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 (tmgrovier@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 �rrwrlDeve�gpy M-001 and AIO-18-013 Loo&9RtPool, Greater Moose's Tooth Unit A0PftftVfl AIf6?5PWM4Zules and Area Injection Order Samantha Carlisle Executive Secretary III Alaska Oil and Gas Conservation Commission 333 West Th Avenue Anchorage, AK 99501 (907) 793-1223 CON'FIDF,NTIALITYNOTICE: This e-mail message, including anv 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 tins 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 von, contact Samantha Carlisle at (907) 793-1223 or Samantha.Carlisle(?alaska eov. Bernie Karl K&K Recycling Inc. Gordon Severson Penny Vadla P.O. Box 58055 3201 Westmar Cir. 399 W. Riverview Ave. Fairbanks, AK 99711 Anchorage, AK 99508-4336 Soldotna, AK 99669-7714 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 February 28, 2018 Hollis French, Chair Alaska Oil and Gas Conservation Commission 333 W. 7th Ave #100 Anchorage, Alaska, 99501-3539 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 RE: Application for Area Injection Order for Lookout Oil Pool, North Slope, AK Dear Commissioner French: MAR 01 2018 AOGCC In accordance with 20 ACC 25.402 (Enhanced Recovery Operations) and 20 AAC 25.460 (Area Injection Orders), ConocoPhillips Alaska, Inc. ("CPAI") as operator of the Greater Mooses Tooth Unit ("GMTU"), requests that the Alaska Oil and Gas Conservation Commission ("Commission") approve CPAI's application for an Area Injection Order ("AIO") for the proposed Lookout Oil Pool, which is within the GMTU. Lookout Oil Pool injection operations are planned to be initiated in Q4 2018. 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 (265-6547) if you have questions or require additional information Regards, �7 �, _/ Z,� Stephen Thatcher Manager, WNS Development North Slope Operations and Development Cc: Land Manager - Alaska, Anadarko E&P Onshore LLC, GMTU W IO Representative Enclosures (3) CPAI Application for Area Injection Order February 28, 2018 Page 2 of 34 ConocoPhillips APPLICATION FOR AREA INJECTION ORDER IN THE LOOKOUT OIL POOL February 28, 2018 Section A— Introduction Section B — Plot of Project Area 20 AAC 25.402(c)(1) Section C — Operator & Surface Owners 20 AAC 25.402(c)(2) Section D — Affidavit 20 AAC 25.402(c)(3) Section E — Description of Proposed Operation 20 AAC 25.402(c)(4) Section F — Pool Description 20 AAC 25.402(c)(5) Section G — Formation Geology 20 AAC 25.402(c)(6) Section H — Logs of Injection Wells 20 AAC 25.402(c)(7) Section I — Mechanical Integrity of Injection Wells 20 AAC 25.402(c)(8) Section J — Injection Fluids 20 AAC 25.402(c)(9) Section K— Injection Pressures 20 AAC 25.402(c)(10) Section L — Fracture Information 20 AAC 25.402(c)(11) Section M — Formation Water Quality 20 AAC 25.402(c)(12) Section N — Aquifer Exemption 20 AAC 25.402(c)(13) Section O — Hydrocarbon Recovery 20 AAC 25.402(c)(14) Section P — Confinement in Offset Wells 20 AAC 25.402(c)(15) Section Q — Proposed Area Injection Order Rules List of Figures/Exhibits B-1: LOP Area and Planned and Existing Wells D-1: Affidavit F-1: Defining Well, Lookout 1, Highlighting Pool Interval G-1: LOP, Alpine C -Sand isochore (Confidential, Appendix 1) G-2: LOP, UJU Depth Structure Map (Confidential, Appendix 1) G-3: LOP Cross Section (Confidential, Appendix 1) G-4: Lookout 2 Log, Alpine formation and Confining Intervals 1-1: Generic Lookout Injector Well Design J-1: Kuparuk Seawater Treatment Plant Water Composition J-2: Alpine Facility Produced Water Composition J-3: Alpine Facility Enriched Gas Injectant Compositions J-4 Alpine Facility Dry Gas Composition 0-1: Recovery versus PV Enriched Gas Injected Appendix 1 —Confidential Information CPAI Application for Area Injection Order February 28, 2018 Page 3 of 34 SECTION A — INTRODUCTION Document Scope This document is an application for an Area Injection Order ("AIO") submitted to the Alaska Oil and Gas Conservation Commission ("Commission") in accordance with 20 AAC 25.460 (Area Injection Orders). The purpose of this document is to gain authorization from the Commission to inject fluids for pressure maintenance and enhanced recovery of hydrocarbons in the Lookout oil pool ("LOP") pursuant to 20 AAC 25.460 and 20 ACC 25.402. ConocoPhillips Alaska, Inc. ("CPAP'), in its capacity as Operator of the Greater Mooses Tooth Unit ("GMTU"), submits this document to the Commission. This application has been prepared in accordance with 20 ACC 25.402 (Enhanced Recovery Operations) and 20 ACC 25.460 (Area Injection Orders). CPAI is concurrently and separately, seeking a Conservation Order from the Commission for the classification and rules to govern the development of the proposed LOP. Introduction The LOP 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 Upper Jurassic Unconformity (UJU). The LOP lies between -7,600 ft. true vertical depth sub -sea ("TVDss") and -8,100 ft. TVDss across the pool area. The LOP lies entirely within the Greater Mooses Tooth Unit. The project to develop the LOP is sometimes referred to as the GMT1 Project. Development of the LOP will be from a single drill site, the new MT6 drillsite. Current plans are to develop the field with four horizontal production wells and five horizontal injection wells employing alternating water injection and enriched gas injection to optimize pool recovery. GMT1 production will be measured for custody transfer prior to commingled on the surface with production from the Colville River Unit (CRU) and processing at the Alpine Central Facility (ACF). From a geologic and reservoir perspective, the LOP is like the Alpine Oil Pool except the LOP does not have Alpine A sand present, does not include Kuparuk sands and it has a lighter (higher API) oil and a higher solution gas -to -oil ratio. From an operations perspective, Lookout will be treated similar to other CRU oil pools. CPA] Application for Area Injection Order February 28, 2018 Page 4 of 34 SECTION B — PLOT OF PROJECT AREA 20 AAC 25.402(c)(1) 20 AAC 25.402(c)(1) -An application for injection must include a plat showing the location of each proposed injection well, abandoned or other unused well, production well, dry hole, and other well within one-quarter mile of each proposed injection well Figure B-1 shows the planned wells for the Lookout development along with all previously drilled wells in the LOP area. Nine horizontal wells are proposed with five injectors and four producers. The previously drilled wells are Lookout 1, Lookout 2 and Mitre 1. Mitre 1 lies outside the reservoir boundary, Lookout 2 lies within the reservoir boundary and both wells have been plugged and abandoned. Lookout 1 has been suspended and has potential utility as a surveillance well to monitor reservoir flood performance and there are no plans to plug and abandon the well now. CPAI Application for Area Injection Order February 28, 2018 Page 5 of 34 SECTION C — OPERATOR & SURFACE OWNERS 20 AAC 25.402(c)(2) 20 AAC 25.402(c)(2) - An application for injection must include a list of all operators and surface owners within a one-quarter mile radius of each proposed injection well. CPAI is the designated operator of the GMTU, which includes the MT6 drill site from which Lookout wells will be drilled. The surface owners and operators within one-quarter mile radius of the proposed injection area are listed below. Operators: No operator other than CPAI Surface Owners: United States Department of Interior Bureau of Land Management Alaska State Office 222 West Ph Avenue #13 Anchorage, Alaska 99513 Attn: Branch Chief, Energy and Minerals Kuukpik Corporation P.O. Box 89187 Nuiqsut, Alaska 99789-0187 Attention: Joe Nukapigak, President CPAI Application for Area Injection Order February 28, 2018 Page 6 of 34 SECTION D — AFFIDAVIT 20 AAC 25.402(c)(3) 20 AAC 25.402(c)(3) -An application for injection must include an affidavit showing that the operators and surface owners within a one-quarter mile radius have been provided a copy of the application for injection. Exhibit D-1 is an affidavit showing that the operators and surface owners within a one-quarter mile radius of the proposed injection area have been provided a copy of this application. CPAI Application for Area Injection Order February 28, 2018 Page 7 of 34 SECTION E — DESCRIPTION OF PROPOSED OPERATION 20 AAC 25.402(c)(4) 20 AAC 25.402(c)(4) -An application for injection must include a full description of the particular operation for which approval is requested. The LOP will be developed from the new GMTU drill site MT6, which is connected to the ACF The LOP will be developed with horizontal production and injection wells in line drive patterns, oriented with the maximum principal stress, that range in length from 3,500 to 12,000' within the reservoir. The development plan includes 5 horizontal injection wells and 4 horizontal production wells with possible pilot holes. The pilot hole data will provide additional reservoir data and assist in optimization of horizontal well placement. Pressure support will be maintained with water and enriched gas injection. An Enriched Water Alternating Gas ("EWAG") gas flood will be initiated early in the waterflood to improve ultimate recovery. Although the gas flood is not miscible with current injection composition, enriched gas injection (EWAG) with condensing components will result in oil swelling and yield incremental recovery. Simulation work demonstrated an optimal well spacing of 2200' separation between injectors and producers. A large NE -trending 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. However, if actual production rates aren't as expected, production stimulation may be considered. Two wells are planned with multi -lateral completions in the 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. CPAI Application for Area Injection Order February 28, 2018 Page 8 of 34 SECTION F — POOL DESCRIPTION 20 AAC 25.402(c)(5) 20 AAC 25.402(c)(5) - An application for injection must include the names, descriptions, and depths of the pools to be affected. Location As shown on Figure B-1, the affected area proposed for the Lookout Area Injection Order is the entire LOP, as proposed, which is within the following land: Umiat Meridian T11N, R2E Section 13-14 all Section 23-24 all Section 25-26 all Section 35-36 all T1 IN, R3E Section 17-19 all Section 29-32 all T10N, R2E Section 1 all Section 2 NE 1/4 T1 ON, R3E Section 6 all Pool Definition Injection of fluids for enhanced recovery is proposed for the correlative interval shown in Figure F-1, known as the LOP. Within the requested areal extent, 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 No. 1 well. CPAI Application for Area Injection Order February 28, 2018 Page 9 of 34 SECTION G — FORMATION GEOLOGY 20 AAC 25.402(c)(6) 20 AAC 25.402(c)(6) - An application for injection must include the name, description, depth, and thickness of the formation into which fluids are to be injected, and appropriate geological data on the injection zone and confining zone, including lithologic descriptions and geologic names. Stratigraphy and Sedimentology The LOP 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 Upper Jurassic Unconformity (UJU). A full stratigraphic column for the Lookout 1 well is shown in Figure G-1 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 The LOP 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. Confining zones are shown in Figure G-5 and are: Upper Confining Interval Deep marine shales and silts of the Fish Creek Slump, HRZ, Kalubik and Miluveach intervals form the upper confining zone for the LOP. Total thickness varies from 600 ft. to 1200+ ft. 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. No free water leg or gas cap has been encountered or is believed to exist in the pool interval. 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. CPAI Application for Area Injection Order February 28, 2018 Page 10 of 34 SECTION H — LOGS OF INJECTION WELLS 20 AAC 25.402(c)(7) 20 AAC 25.402(c)(7) - An application for injection must include the logs of the injection wells if not already on file with the commission. To date, no injection wells have been drilled. Well MT6-08 is planned as the first injection well in the LOP with spud estimated for July 2018. The logs associated with the drilling and completion of this wellbore will be filed with the Commission once available and as required. CPAI Application for Area Injection Order February 28, 2018 Page 11 of 34 SECTION I — MECHANICAL INTEGRITY OF INJECTION WELLS 20 AAC 25.402(c)(8) 20 AAC 25.402(c)(8) - An application for injection must include a description of the proposed method for demonstrating mechanical integrity of the casing and tubing under 20 AAC 25.412 and for demonstrating that no fluids will move behind casing beyond the approved injection zone, and a description of (A) the casing of the injection wells if the wells are existing, or (8) the proposed casing program, if the injection wells are new. The injection well designs for the LOP (Figure 1-1) are similar to wells in the Colville River Unit (Alpine Field) but contain an additional casing string to manage borehole instability when drilling the shales just above the reservoir. Surface casing set below the C40 marker in the Colville Group will be cemented back to surface. Within the planned development area, the base of permafrost is interpreted to lie between -800 to -1200 ft. TVDSS. The intermediate hole will be drilled in two intervals with the first casing point being the Fish Creek Slump interval and the second casing point at approximately 85 degrees inclination just above, or just into the Alpine C sand. The intermediate #1 section between the proposed surface casing shoe and the top of the Fish Creek Slump interval 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 Slump interval 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. The LOP will be developed 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. In lieu of the packer depth requirement under 20 AAC 25.412(b), CPAI requests the packer/isolation equipment depth for injection wells may be located greater than 200 ft. measured depth from above the top of the perforations/open interval, but shall not be located above the confining zone and shall have outer casing cement volume sufficient to place cement a minimum of 300' measured depth above the planned packer depth. This will accommodate efficient wireline operations down to the pressure isolation equipment. The tubing/casing annulus pressure of each injection well will be tested in accordance with 20 ACC 25.412(c). Drilling and completion operations will be performed in accordance with 20 AAC 25. In accordance with 20 AAC 25.412(d), cement quality logs, or other data approved by the Commission, will be provided for all injection wells to demonstrate isolation of the injected fluids to the approved interval. CPAI Application for Area Injection Order February 28, 2018 Page 12 of 34 SECTION J — INJECTION FLUIDS 20 AAC 25.402(c)(9) 20 AAC 25.402(c)(9) - An application for injection must include a statement of the type of fluid to be injected, the fluid's composition, the fluid's source, the estimated maximum amounts to be injected daily, and the fluid's compatibility with the injection zone. The LOP will be developed with water injection followed by cycles of enriched gas injection (EWAG). Primary injected fluids are sea water originating from the Kuparuk Seawater Treatment Plant and enriched gas from the ACF. The seawater and enriched gas will be the same as those injected into CRU pools. Produced water, rather than seawater, may be injected in the future. Other fluids may also be injected for reservoir stimulation, reservoir performance evaluation, freeze protection, chemical inhibition or to otherwise ensure efficient and safe operation of the wells in the LOP; however, these fluids are not planned for continuous injection as a means for enhanced recovery. The volumes of these other fluids are expected to be de minimis and are not expected to hinder the recovery efficiency or performance of the proposed LOP. Types and sources of fluids requested for injection are (compositions included for fluids that may be dedicated injection fluids): • Source water from the Kuparuk seawater treatment plant (composition listed in Figure J-1) • Produced water from all present and yet -to -be defined oil pools within the GMTU and CRU, (recent ACF produced water composition in Figure J-2) • Enriched hydrocarbon gas (MI): Blend of CRU and GMTU lean gas enriched with indigenous heavy gas components (composition listed in Figure J-3) • Lean gas (ACF composition listed in Figure J-4) • Fluids used during hydraulic stimulation • Tracer survey fluids to monitor reservoir performance (chemical, radioactive, etc.) • Fluids used to improve near wellbore injectivity (via use of acid or similar treatment) • Fluids used to seal wellbore intervals which negatively impact recovery efficiency (cement, resin, etc.) • Fluids associated with freeze protection (diesel, crude, glycol, methanol, etc.) • Standard oilfield chemicals (corrosion inhibitor, scale inhibitor, etc.) Fluid Compatibility The primary and miscellaneous fluids listed above are expected to be compatible with the LOP as has been demonstrated by performance in the analog Alpine Oil Pool. Moderate barium sulfate scale formation in production wells, as has been experienced to various degrees in CRU pools, is possible due to the mixing of seawater (containing sulfate, SO4) and formation connate water (containing barium, BA). A scale inhibition treatment program, like that performed in CRU pools, will be performed at Lookout as required. Injection Volumes Injection will proceed in a manner to maintain reservoir voidage to a value of one. Alternating cycles of injected water and gas will be managed to maximize oil production and minimize any extreme returns of the injected fluids. Injection rates will be limited by injection pressures as to not exceed the overburden pressure gradient and cause fractures to penetrate through the confinement layer. Total LOP injection rates for the four injection wells are expected to typically be in the range of 10,000-25,000 BWPD and 5000-25000 MCFD. CPAI Application for Area Injection Order February 28, 2018 Page 13 of 34 SECTION K — INJECTION PRESSURES 20 AAC 25.402(c)(10) 20 AAC 25.402(c)(10) - An application for injection must include the estimated average and maximum injection pressure. Maximum estimated surface water and gas injection pressures are 2850 psia and 4200 psi, respectively. Maximum surface pressures are based on the ACF pump discharge pressure for water and gas. These pressures are unlikely to be realized at the MT6 drillsite. Average estimated surface water and gas injection pressures are 2650 psia and 4000 psi, respectively. These are the expected pressures at the MT6 drillsite header accounting for pressure drop in the pipeline system. CPA[ Application for Area Injection Order February 28, 2018 Page 14 of 34 SECTION L — FRACTURE INFORMATION 20 AAC 25.402(c)(11) 20 AAC 25.402(c)(11) -An application for injection must include evidence to support a commission finding that each proposed injection well will not initiate or propagate fractures through the confining zones that might enable the injection fluid or formation fluid to enter freshwater strata. In the LOP area, the Alpine C is over and underlain by laterally and vertically extensive, ductile shales and silts that provide a confining barrier to isolate formation and injected fluids within the Alpine C. The overlying strata of the Fish Creek Slump, HRZ, Kalubik and Miluveach range in thickness from 600' to 1200'. Approximately 1700' feet of Kingak underlies the pool. Injection experience in the analog Alpine Oil Pool verifies the competency of the confining zones. There are no freshwater or underground sources of drinking water in the LOP area as provided in Appendix 2 of CPAI's application to establish the LOP. Data from multiple wells in the LOP and surrounding area indicate shallow water salinities below the permafrost are in excess of 10,000 ppm. Fracture gradient analysis has been calibrated with rock mechanical properties from analog core data and drilling leak off tests in the overlying shales. Data indicates overlying intervals have fracture gradients of 0.85 psi/ft or higher. By analog rock properties, the underlying Kingak shale is expected to have a similar fracture gradient. Fracture gradient in the Alpine C interval is approximately 0.65 psi/ft. To ensure containment of fluids within the LOP, CPAI recommends a rule limiting injection pressure to a maximum injection gradient of 0.81 psi/ft. CPAI conducted a containment analysis that verified the 0.81 psi/ft injection gradient will not initiate or propagate fractures through the confining strata. The analysis involved the use of frac modelling software with inputs based on the Lookout 2 well log calibrated with data from core sample geo-mechanical tests. Figure L-1 shows results of the simulated injection of 240,000 barrels of water, at a rate of 10,000 barrels per day, into a vertical well at bottomhole injection pressures above 0.81 psi/ft. The frac modelling software used was version 8.4.0.15 of Grid Oriented Hydraulic Fracture Extension Replicator (GOHFER), due to its reliability and common use within ConocoPhillips as well as in the fracturing industry. GOWER is a planar 3-D geometry fracture simulator developed by Barree & Associates in association with Stim-lab and is commercially available throughout the industry for performing hydraulic fracture simulation work. CPAI Application for Area Injection Order February 28, 2018 Page 15 of 34 SECTION M — FORMATION WATER QUALITY 20 AAC 25.402(c)(12) 20 AAC 25.402(c)(12) - An application for injection must include a standard laboratory water analysis, or the results of another method acceptable to the commission, to determine the quality of the water within the formation into which fluid injection is proposed. There is no known free water level within the LOP and therefore no analysis of native formation water is available. Similarly, there is no free water level in the Alpine Oil Pool to provide an analysis of Jurassic water In the original Alpine Area Injection Order application, water analysis was provided for formations above and below the Jurassic, as an example of the possible water quality by analogy. CPAI Application for Area Injection Order February 28, 2018 Page 16 of 34 SECTION N — AQUIFER EXEMPTION 20 AAC 25.402(c)(13) 20 AAC 25.402(c)(13) - An application for injection must include a reference to any applicable freshwater exemption issued under 20 AAC 25.440. There have been no freshwater exemptions issued under 20 AAC 25.440 in the LOP area. There are no known freshwater aquifers in the LOP area as provided in Section L of this application. CPAI Application for Area Injection Order February 28, 2018 Page 17 of 34 SECTION O — HYDROCARBON RECOVERY 20 AAC 25.402(c)(14) 20 AAC 25.402(c)(14) - An application for injection must include the expected incremental increase in ultimate hydrocarbon recovery. Pressure support in the reservoir with water injection is necessary due to the expected high voidage rates and relatively low recovery without voidage replacement. In addition, the full incremental benefit of the proposed Enriched Water Alternating Gas ("EWAG") gas flood will not be realized without water injection. 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 are expected to yield an ultimate EWAG recovery that will be in the range of 50-65% of OOIP. Uncertainty factors that may impact the recovery estimate include facies distribution, net pay, voidage replacement, well productivity, and OIP. Although the gas flood is not miscible with current injection composition, EWAG will result in oil swelling and yield incremental recovery. Reservoir simulation and analytical analysis indicate that primary recovery alone is expected to yield recovery of 20%. The remaining 30-45% of the ultimate recovery is expected through secondary and tertiary mechanisms with EWAG injection. The low viscosity oil of the Lookout reservoir is conducive to high recovery efficiency. Reservoir pressure needs to be maintained above the bubble point to preserve this favorable condition for high ultimate recovery. A standalone effort to forecast the incremental recovery from enriched gas injection was completed to match lab based recovery observations. Figure 0-1 shows resulting recovery with variations in gas enrichment from the 1 D simulation using the Lookout tuned equation of state. CPAI Application for Area Injection Order February 28, 2018 Page 18 of 34 SECTION P — CONFINEMENT IN OFFSET WELLS 20 AAC 25.402(c)(15) 20 AAC 25.402(c)(15) - An application for injection must include a report on the mechanical condition of each well that has penetrated the injection zone within a one-quarter mile radius of a proposed injection well. Two exploration wells shown in Figure B-1 penetrate the LOP. Lookout #1 was drilled and cased in 2001. In 2002 the Alpine C sand was perforated and completed with production packers and tubing. The well was used to monitor pressure during the flow testing of Lookout #2 and long-term buildup. In 2003 the pressure gauges were pulled and the well secured with downhole tubing plug, kill weight fluid, back pressure valve in tubing hanger and VR plugs in wellhead annuli. Lookout #2 was drilled, completed and flow tested in spring 2002 with P&A completed May 5, 2002 CPAI Application for Area Injection Order February 28, 2018 Page 19 of 34 SECTION Q — PROPOSED AREA INJECTION ORDER RULES The rules set forth apply to the following area referred to in this order: Umiat Meridian T1 IN, R2E Section 13-14 all Section 23-24 all Section 25-26 all Section 35-36 all T11 N, 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 1. Authorized Injection Strata for Enhanced Recovery Fluids authorized under Rule 3, below, may be injected for the purposes of pressure maintenance and enhanced hydrocarbon recovery within the proposed Lookout Oil Pool, which is defined as the accumulation of oil and gas common to and correlating with the interval within the Lookout No.1 well between the measured depths of 7,833 ft. and 8,000 ft. Rule 2. Well Construction In lieu of the packer depth requirement under 20 AAC 25.412(b), the packer/isolation equipment depth for injection wells may be located above 200 ft. measured depth from above the top of the perforations/open interval, but shall not be located above the confining zone and shall have outer casing cement volume sufficient to place cement a minimum of 300 ft. measured depth above the planned packer depth. Rule 3. Authorized Fluids for Injection for Enhanced Recovery Fluids authorized for injection are: a. Source water from the Kuparuk seawater treatment plant b. Produced water from all present and yet -to -be defined oil pools within the GMTU and CRU c. Enriched hydrocarbon gas (MI) from the Alpine Central Facility d. Lean gas e. Fluids used during hydraulic stimulation f. Tracer survey fluids to monitor reservoir performance (chemical, radioactive, etc.) g. Fluids used to improve near wellbore injectivity (via use of acid or similar treatment) In. Fluids used to seal wellbore intervals which negatively impact recovery efficiency (cement, resin, etc.) i. Fluids associated with freeze protection (diesel, crude, glycol, methanol, etc.) j. Standard oilfield chemicals (corrosion inhibitor, scale inhibitor, etc.) Rule 4. Authorized Injection Pressure for Enhanced Recovery Injection pressures will be managed not to exceed the maximum injection gradient of 0.81 psi/ft to ensure containment of injected fluids within the Lookout Oil Pool. Rule 5. Monitoring Tubing -Casing Annulus Pressure The tubing and casing annuli pressures of each injection well must be monitored at least daily, except if prevented by extreme weather condition, emergency situations, or similar unavoidable circumstances. Monitoring results shall be documented and made available for Commission inspection. CPAI Application for Area Injection Order February 28, 2018 Page 20 of 34 Rule 6. Demonstration of Tubing/Casing Annulus Mechanical Integrity The mechanical integrity of each injection well must be demonstrated before injection begins and before returning a well to service following any workover affecting mechanical integrity. An AOGCC-witnessed MIT must be performed after injection is commenced for the first time in a well, to be scheduled when injection conditions (temperature, pressure, rate, etc.) have stabilized. Subsequent tests must be performed at least once every four years thereafter. The AOGCC must be notified at least 24 hours in advance to enable a representative to witness an MIT. Unless an alternate means is approved by the AOGCC, mechanical integrity must be demonstrated by a tubing/casing annulus pressure test using a surface pressure of 1,500 psi or 0.25 psi/ft multiplied by the vertical depth of the packer, whichever is greater, that shows stabilizing pressure and does not change more than 10 percent during a 30 -minute period. Results of MITs must be readily available for AOGCC inspection. Rule 7. Well Integrity and Confinement Whenever any pressure communication, leakage or lack of injection zone isolation is indicated by an injection rate, operating pressure observation, test, survey, log, or any other evidence, the Operator shall notify the AOGCC by the next business day and submit a plan of corrective action on a Form 10-403 for AOGCC approval. The Operator shall immediately shut in the well if continued operation would be unsafe or would threaten contamination of freshwater. A monthly report of daily tubing and casing annuli pressures and injection rates must be provided to the AOGCC for all injection wells for which well integrity failure or lack of injection zone isolation is indicated. Rule 8. Notification of Improper Class II Injection Injection of fluids other than those listed in Rule 3 without prior authorization is considered improper Class II injection. Upon discovery of such an event, the operator must immediately notify the AOGCC, provide details of the operation, and propose actions to prevent recurrence. This requirement is in addition to, and does not relieve the operator of any other obligations under the notification requirements of any other State or Federal agency, regulation or law. Rule 9. Other Conditions If fluids are found to be fracturing the confining zone or migrating out of the approved injection stratum, the Operator must immediately shut in the injection wells and immediately notify the AOGCC. Injection may not be restarted unless approved by the AOGCC. Rule 10. Administrative Action Upon proper application, the Commission may administratively waive the requirements of any rule stated above or administratively amend the order as long as the change does not promote waste or jeopardize correlative rights, is based on sound engineering or geoscience principles, and will not result in an increased risk of fluid movement into freshwater. CPA[ Application for Area Injection Order February 28, 2018 Page 21 of 34 List of Figures/Exhibits B-1: LOP AREA AND PLANNED AND EXISTING WELLS D-1: AFFIDAVIT F-1: DEFINING WELL, LOOKOUT 1, HIGHLIGHTING POOL INTERVAL G-4: LOOKOUT 2 LOG, ALPINE SAND AND CONFINING INTERVALS 1-1: GENERIC LOOKOUT INJECTOR WELL DESIGN J-1: KUPARUK SEAWATER TREATMENT PLANT WATER COMPOSITION J-2: ALPINE FACILITY PRODUCED WATER COMPOSITION J-3: ALPINE FACILITY ENRICHED GAS INJECTANT COMPOSITION J-4: ALPINE FACILITY DRY GAS COMPOSITION L-1: LOOKOUT 2 WELL FRAC MODEL RESULTS 0-1: RECOVERY VERSUS PV ENRICHED GAS INJECTED APPENDIX 1 CONFIDENTIAL SECTION CPAI Application for Area Injection Order February 28, 2018 Page 22 of 34 FIGURE B-1: LOP BOUNDARY AND PLANNED AND EXISTING WELLS PkVVd.dM doried 0 Su$W60(1 © Drilling0rder —Injector Producer Q GMTI Lookoul Res n QProposed Lookout PA (7jW118oundanes ® Kuukpik Surface ASRC subsurface Q Proposed Lookout Oil Pool Boundary CPAI Leases tZE N A 0 0.5 1 Miles Greater Mooses Tooth Unit T11 NR3E T10NR3E Lookout Oil Pool Development Plan CPAI Application for Area Injection Order February 28, 2018 Page 23 of 34 EXHIBIT D-1: AFFIDAVIT STATE OF ALASKA THIRD JUDICIAL DISTRICT I, Stephen Thatcher, declare and affirm as follows: 1. 1 am the Western North Slope Development Manager for ConocoPhillips Alaska, Inc., the'designated operator of the Greater Mooses Tooth Unit, and as such have responsibility for Lookout operations. 2. Oni , 2018, 1 caused copies of the Lookout Area Injection Order application to be provided to the followiY1) rfang suce owners and operators of all land within a quarter -mile radius of the proposed injection areas: United States Department of Interior Bureau of Land Management Alaska State Office 222 West 7t^ Avenue #13 Anchorage, Alaska 99513 Attn: Branch Chief, Energy and Minerals Kuukpik Corporation P.O. Box 89187 Nuiqsut, Alaska 99789-0187 Attention: Joe Nukapigak, President Dated: IhO , 2018. Stephen Thatcher Declared and affirmed before me this�day of �, 2018. STATE OF�AAS%A NOTARY PUBLIC otaryPublic in and for A asks LAURA E MUTCH qW My ow $ion Ex [meA r.U.swo My commission Expires: CPAI Application for Area Injection Order February 28, 2018 Page 24 of 34 FIGURE F-1: DEFINING WELL, LOOKOUT 1, HIGHLIGHTING POOL INTERVAL Lookoutl 2001 w w 0 TVDSS rR) mo IR) -- -,p .-1161 yw! Sbi 1 Mmm Iw L`; c:n S7 833' md! I a 17763' f , e 7871' g 78 1' ss I I — I o O a I i 4 O O O J I n CPAI Application for Area Injection Order February 28, 2018 Page 25 of 34 FIGURE G-1: LOOKOUT AREA STRATIGRAPHIC SECTION — LOOKOUT 1 WELL LOG Prince Creek Sands (lase 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) i%.G s4 "M IIIIIIIII pill 'b � guilt MAIC! NEZ 5"11111, Will •11 �. Ei III Prince Creek Sands (lase 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) CPAI Application for Area Injection Order February 28, 2018 Page 26 of 34 FIGURE G-5: LOOKOUT 2 LOG, ALPINE FORMATION AND CONFINING INTERVALS OR TW AU 1w OT :W 160.001,102 1'.0000. 011m -m 10D.000D 160.W uslR 60 RROB 18500 Ortm3 2. tNtrtl .6000 R3/R3 0 2 Asx 6900 69:U 'IA T ff N ]1W d C Q ]300 { .F C L rs ]300 m n 0 '°° ]i00 O J A 'S; G A N n S )Exi ]600 ]]CO ]]Y lax ]800 O O O_ p n � o w� � w' � CPAI Application for Area Injection Order February 28, 2018 Page 27 of 34 FIGURE 1-1: GENERIC LOOKOUT INJECTOR WELL 0 LJ N TOC at least 300' above Packer & 500' above Alpine C v 20" Insulated Conductor 80 feet, cemented to surface 13-3/8" Surface Casing cemented to surface 4.1/2" Tubing 9 5/8" Casing TOC at least 500' above shoe Tubing / Liner Completion: 1) 4-%" X Landing Nipple (3.813" ID) 2) 4-Y' x 1' GLM 3) Liner Top Packer/Hanger 4) CMU Sliding Sleeve - X (3.813" ID) 5) Liner Top Packer/Hanger w/ Tie Back sleeve 6) 4-%" XN Landing Nipple (3.725" NoGo) 7) 4-%' Blank Pipe 8) 4-'A" Linerwith Perf Pups VIP' Liner with Perf Pups 0 0 0 0 0 0 0 0 0 Top Alpine C _ 7" Liner 6" Hale 5000 —12000 H horizontal CPAI Application for Area Injection Order February 28, 2018 Page 28 of 34 FIGURE J-1: KUPARUK SEAWATER TREATMENT PLANT WATER COMPOSITION Sample Number: S-160203-00063 Sample Name: STP Seawater Plant Discharge Location: Area: KUPARUK Unit: STP Sample Point: STP SPD Sampled Date: 2/2/2016 3:50:OOPM Matrix Id: WATER- SEA Reviewed By: Carville, Daniele Date 02/24/2016 Analvsis Results: Test Nm.r I.SUIt UOM BACTERIA • ATP AL(AUUMINUM) 0.04 mg/I ATPASE 31692 RLU DID NIX IC • ACETATE 4.65 mg/I ITP METALS' BA (BARIUM) ACETATE b.0 mg/I DIU NE%IC• BUTYRATE ICP METALS' CA (CALCIUM) CA (CALCIUM) BUTYRATE <SG mg/I DIO NDL IC' CHLORIDE CR (CHROMIUM) 0.01 mg/I CHLORIDE 18447.8 mg/I DID NIX IC - FORMATE 0.07 mg/1 ICP METALS' K (POTASSIUM) FORNTATE <5.0 mg/I DIG NEX IC' PROPIONATE ICP METALS • LI (LITHIUM) LI(UTHIUM) PROPIONATE tS.0 mg/I 010 NIX IC' SULFATE MG (MAGNESIUM) 1130.33 SO4 (SULFATE) 2500.0 mg/I ICP METALS • AL (ALUMINUM) AL(AUUMINUM) 0.04 mg/I ICP METALS8 (BORON) B(BO RON) 4.65 mg/I ITP METALS' BA (BARIUM) BA (BARIUM) 0.15 mg/I ICP METALS' CA (CALCIUM) CA (CALCIUM) 426.59 mg/l ICP METALS • CR (CHROMIUM) CR (CHROMIUM) 0.01 mg/I ICP METALS • FE (IRON) FE(IRON) 0.07 mg/1 ICP METALS' K (POTASSIUM) K (POTASSIUM) 391.42 mg/I ICP METALS • LI (LITHIUM) LI(UTHIUM) 0.22 mg/I ICP METALS' MG (MAGNESIUM) MG (MAGNESIUM) 1130.33 mg/I ICP METALS • MN (MANGANESE) MN (MANGANESE) 0.009 mg/1 ICP METALS • NA (SODIUM) NA(SODIUM) 9973.70 mg/I ICP METALS' P (PHOSPHORUS) P (PHOSPHORUS) 0.03 mg/I ICP METALS • SI (SILICON) 81 (SILICON) 1.43 mg/I ICP METALS • SR (STRONTIUM) CPAI Application for Area Injection Order February 28, 2018 Page 29 of 34 FIGURE J-1: KUPARUK SEAWATER TREATMENT PLANT WATER COMPOSITION (CONTINUED) Sample Number: 5-16020300063 Sample Name: STP Smwater Plant Disdi arge Location: Area: KUPARUK Unit: STP Sample Point: STIR SPD Sampled Date: 2/2/2016 350:00PM Matrix id: WATER - SEA Reviewed By. Carville, Daniele Dates 02/24/2016 Analysis Results: Test parameter Result Uom SR (TRONTIUM) 8.28 Mel ICP METALS' ZN VINC) ZN(ZIN C) 0.02 Mel 5-2320 ALKALIN IrY' TOTAL SICARBO NATE (H CO3) 191.8 Mel CARBO NATE (CO3) 0.0 Mel 5-2510' CONDUCTIVITY CO INDUCT IVITY 53800 uS/an 5-2520 SALINITY' SP GRAY S PECIFIC GRAVITY 1.0269 5-4500 PH (B) • PH PH 7.12 5-450 0 5 2-(F) • SULFIDE BY TITR SULFIDE 1.8 Mel CPAI Application for Area Injection Order February 28, 2018 Page 30 of 34 FIGURE J-2: ALPINE FACILITY PRODUCED WATER COMPOSITION KUPARUK LAB ANALYTICAL REPORT 907-659-7214 n1C20@cop.com Sample Number. S-161011-00326 Sample Name: Alpine Flash Drum Inmtiun: Area: ALPINE Unit ALPFAC Sample Point A7PWFD Sampled Date: 10/7/2016 2:3400AM Matrix Id: WATER - PRODUCED Reviewed Ry: Carville, Daniele Date:10/30/2016 Ana hi" Results, 1= 2 t III%= 1= DIONEA I C' ACETATE ACETATE 4000 mgll DIONOI IC • BUTYRATE BUTYRATE a5.0 mg/I OIONEM IC' CHLORIDE CHLORIDE ]4185.1 mg/1 DIONEK IC' FORMATE FORMATE e50 mg(I DIONEN IC' PROPIONATE PROPIONATE 297 mg/I OIONEA IC' SULFATE 504aUIFATE) 47.0 mg/1 W METALS' AL LAW MINUM) AL(AWMINUM) 0.04 mg/1 IM METAIS • B(BORON) B(SORON) 2207. mg/I IC' METALS • BA (BARIUM) MHARIUM) 2.8 mg/1 for METAIS • CA (CALCIUM) CA(CALCIUM) 16433 mdl TOP METAIS • OR (CHROMIUM) CR (CHROMIUM) 0.01 mg/1 ICP METALSEE (IRON) HE QRON) 4.73 mg/I ICP METAIS • K (POTASSIUM) K(POTASSIUM) 50.63 mg/I 1OF METALS • U (LITHIUM) U (UTHIUM) 1.47 m&A OR METALS' MG (MAGNESIUM) MIS(MAGNESIUM) 123.03 mgp JCP METAIS • MN (MANGANESE) MN (MANGANESE) 0.065 mg/l lOP METAIS • NA (SODIUM) NA(SODIUM) 9183.43 mg/I 10` METALS • P(PHOSPHORUS) P(PHOSPHORUS) 3.32 mg/I IB METALS • SI (SLICON) SI(SNICON) 1760 mgA ICP METALS • SR CSTRONTIUM) SR I$TRONTIUM) 12.09 mg/I ConocoPhillips CPAI Application for Area Injection Order February 28, 2018 Page 31 of 34 FIGURE J-3: ALPINE FACILITY ENRICHED GAS INJECTANT COMPOSITIONS (MOLE %) Analysis Results - Gas Injectant Composition Test Parameter Result (Volume Weighted Average) UOM D-2163 MOD GC * METHANE Methane 73.19 Mole % D-2163 MOD GC * ETHANE Ethane 10.16 Mole % D-2163 MOD GC * PROPANE Propane 9.60 Male % D-2163 MOD GC * I -BUTANE i -Butane 1.23 Mole % D-2163 MOD GC * N -BUTANE n -Butane 2.40 Mole % D-2163 MOD GC * N -PENTANE i -Pentane 0.59 Mole % D-2163 MOD GC * I -PENTANE n -Pentane 0.56 Mole % D-2163 MOD GC * TOTAL C6 Hexanes 0.42 Mole % D-2163 MOD GC * TOTAL C7 Heptanes 0.26 Mole % D-2163 MOD GC * C6 HEAVIER C6+ 0.98 Mole % D-2163 MOD GC * C8 HEAVIER C8+ 0.29 Mole % D-2163 MOD GC * CARBON DIOXIDE CO2 0.72 Mole % D-2163 MOD GC * NITROGEN Nitrogen 0.58 Mole % D-2163 MOD GC * AVG MOL WT Mole Wt. 23.42 /mol CPA[ Application for Area Injection Order February 28, 2018 Page 32 of 34 FIGURE J-4: ALPINE FACILITY LEAN GAS COMPOSITION ANALYSIS—NAME ANALYSIS RESULT ANALYSIS UNITS Methane 74.583 Mole% Ethane 10.123 Mole % Propane 9.893 Mole% i -Butane 1.198 Mole % n -Butane 1.984 Mole% i -Pentane 0.320 Mole% n -Pentane 0.277 Mole% Hexa nes 0.104 Mole % Hepta nes 0.059 Mole % C6 Plus 0.179 Mole% C8 Plus 0.016 Mole % Carbon Dioxide 0.798 Mole % Nitrogen 0.645 Mole % Molecular Weight 22.35 g/mol CPAI Application for Area Injection Order February 28, 2018 Page 34 of 34 FIGURE 0-1: SIMULATED RECOVERY VERSUS PV INJECTED 100 90 Bo 70 a � W W 50 O O W 40 a N 30 N E20 _ ......_.__.__.---`----- Assumed Conditions pressure = 375opsi 10 Temperature = 187 Current Injectant M 0 .. - _------`---.. 0 20 40 60 80 100 120 140 Pore Volume injected, % PV 9ettant ks - Lean Gas- Current Compositional Blend- g 10% Enriching Fluid - *--15%Enriching Fluid - 20% Enriching Fluid ID