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Home My WebLink AboutAIO 044AIO 44 Pikka Unit Pikka Field Nanushuk Oil Pool North Slope Borough, Alaska 1. April 16, 2024 Oil Search application to Establish an Area Injection Order for the Nanushuk Oil Pool 2. April 30, 2024 Notice of public hearing 3. June 4, 2024 Hearing presentation and transcripts 4. June 11, 2024 additional information for AIO applications 5. June 12, 2024 Notice of public hearing 6. August 16, 2024 Pikka AIO ownership question STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION 333 West 7th Avenue Anchorage, Alaska 99501 Re: THE APPLICATION OF Oil Search (Alaska), LLC for an order authorizing underground injection of fluids for enhanced oil recovery and oil storage in the Pikka Unit, Nanushuk Oil Pool ) ) ) ) ) ) ) ) ) ) Docket Number: AIO-24-013 Area Injection Order 44 Pikka Unit Pikka Field Nanushuk Oil Pool North Slope Borough, Alaska August 21, 2024 IT APPEARING THAT: 1. By application dated April 16, 2024 (Application), and amended June 11, 2024, Oil Search (Alaska), LLC (OSA), a subsidiary of Santos Limited (Santos) as operator of the Pikka Unit (PU), requested an order authorizing underground injection of fluids for enhanced oil recovery and oil storage purposes in the area covered by Nanushuk Oil Pool (NOP). 2. Pursuant to 20 AAC 25.540, the Alaska Oil and Gas Conservation Commission (AOGCC) scheduled a public hearing for June 4, 2024. On April 30, 2024, the AOGCC published notice of that hearing on the State of Alaska’s Online Public Notice website and on the AOGCC’s website, electronically transmitted the notice to all persons on the AOGCC’s email distribution list, and mailed printed copies of the notice to all persons on the AOGCC’s mailing distribution list. On May 1, 2024, the notice was also published in the Anchorage Daily News. 3. The hearing commenced at 10:00 a.m. on June 4, 2024. Testimony was received from representatives of OSA. 4. No public comments on the Application were received. 5. The record was closed at the end of the day on June 7, 2024. 6. After the hearing OSA decided to expand the affected area of the proposed AIO to match the extent of the NOP as it was defined in Conservation Order 807. On June 11, 2024, OSA submitted an amended application (Amended Application) to expand the proposed affected area in its initial application to coincide with the pool extents for the NOP. The proposed expansion required notifications of parties that were not required to be noticed based on the proposed area the original Application. As such, and pursuant to 20 AAC 25.540, the AOGCC tentatively scheduled an additional public hearing for July 18, 2024. On June 12, 2024, the AOGCC published notice of that hearing on the State of Alaska’s Online Public Notice website and on the AOGCC’s website, electronically transmitted the notice to all persons on the AOGCC’s email distribution list, and mailed printed copies of the notice to all persons on the AOGCC’s mailing distribution list. On June 16, 2024, the notice was also published in the Anchorage Daily News. AIO 44 August 21, 2024 Page 2 of 13 7. No public comments on the Amended Application nor requests to hold the additional tentatively scheduled hearing were received. As the AOGCC had sufficient information to make a decision on the Amended Application, the additional hearing was vacated. 8. The record was closed at 4:30 PM on July 16, 2024, the close of the comment period as stated in the June 16, 2024 public notice. FINDINGS: 1. Owners and Landowners: Surface owners in the proposed NOP area are Kuukpik Corporation, the State of Alaska, Katherine Brown, Jim T. Allen, and the estate of Helen E. Tukle. Subsurface owners of the NOP are Alaska Department of Natural Resources (DNR) and the Arctic Slope Regional Corporation. OSA and Repsol E&P USA LLC (Repsol) are the working interest owners of the leased acreage within the proposed Affected Area, as defined below. 2. Operator: OSA is operator of all the leased acreage in the proposed Affected Area. 3. Affected Area: OSA is proposing that the Affected Area encompass the entirety of the PU, which lies between the Colville River Unit (CRU) to the west, the Kuparuk River, Oooguruk, and Quokka Units to the east, the Beaufort Sea to the north and non-unitized state lands to the south. The unit lies mostly onshore on the North Slope of Alaska but also extends onto state submerged lands in the Beaufort Sea. 4. Exploration and Delineation History: OSA, along with predecessor operators Repsol and Armstrong Energy, LLC., have conducted significant exploration activity in the project area. More than 20 wells have penetrated the Nanushuk Formation in the area and 6 of these had successful flow tests and 4 collected cores from the Nanushuk Formation. Key wells used to define the NOP include the Qugruk-3, Qugruk-3A, Qugruk-7, Qugruk-301, Qugruk-8, Qugruk-9, Qugruk-9A, Fiord-2, Fiord-3, Pikka B, and Pikka C. AIO 44 August 21, 2024 Page 3 of 13 Figure 1. Pikka Project Area Showing Unit Boundary, Leases, Exploratory Wells, and Development Infrastructure (Source: Oil Search (Alaska), LLC) AIO 44 August 21, 2024 Page 4 of 13 5. Pool Identification: As defined by CO 807, the NOP encompasses a thick accumulation of deltaic shelf deposits that were time-equivalent to shale-dominated Torok Formation sediments that were deposited in deeper water. The proposed NOP is the accumulation of hydrocarbons common to and correlating with that portion of the Nanushuk Formation (Nanushuk) shown on the Qugruk 3 reference log between 3,892 and 5,166 feet measured depth (MD), which is equivalent to 3,785 and 4,985 feet true vertical depth below mean sea level (also termed true vertical feet sub-sea, or TVDSS). OSA’s informally named “Nanushuk 3” sandstone interval will be OSA’s primary development target, but towards the western edge of the proposed NOP the underlying Nanushuk 2 interval becomes more developed, and it may also be a development target. AIO 44 August 21, 2024 Page 5 of 13 Figure 2. Qugruk 3 type log (Source: Oil Search (Alaska), LLC) 6. Relationship to Nanushuk Developments in the CRU and KRU: At the public hearing, OSA testified that the Nanushuk is composed of several imbricated, sand-rich, eastward-prograding, top-set intervals. The axes of these intervals strike north-northeast and they off lap progressively toward the east across the boundary between the CRU and the PU. According to Conservation Order (CO) 605, CO 605A, and Area Injection Order (AIO) No. 35, the Qannik Oil Pool (QOP) in ConocoPhillips Alaska, Inc.’s (CPAI) CRU comprises sandstone intervals within the Nanushuk that are overlain and underlain by thick shales and siltstones assigned to the Seabee and Torok Formations respectively. The QOP was initially defined as the interval AIO 44 August 21, 2024 Page 6 of 13 that correlates to 6,086 to 6,249 feet MD in the CRU CD2-11 well (API 50-103-20515-00-00), and AIO 35 currently specifies this as the approved injection interval. However, the QOP was subsequently expanded vertically by CO 605A to include the interval from 6,030 to 6,249 feet MD in CRU CD2-11. CPAI’s informally named Narwhal reservoir within the boundaries of the CRU produces from, and injects into, the Nanushuk Formation. Enhanced Recovery Injection Order (ERIO) No. 6, which authorized a pilot injection project in the Narwhal reservoir defines the Narwhal as correlating to the interval of 4,192 to 5,152 feet MD in the Qugruk 3 well. So, as shown by Figure 2, CPAI’s Narwhal reservoir is correlative with a portion of OSA’s NOP (between 3,829- and 5,166-feet MD). According to ERIO 8, CPAI’s informally named Coyote reservoir in the KRU is another Nanushuk Formation development that is overlain by the Seabee Formation, underlain by the Torok Formation, and correlates to the interval in the Palm 1 well (API No. 50-103-20361-00- 00) from 4.270 to 5.115 feet MD. 7. Geology: a. Stratigraphy: OSA’s proposed NOP is part of a large-scale, constructional, siliciclastic clinoform system that prograded from west to east. The top set shelfal sediments constitute the Nanushuk Formation, and the contemporaneous, slope-dominated sediments deposited along the east-facing foreset slopes are assigned to the Torok Formation. Reservoir quality is greatest in the sand-rich top set beds that were influenced by wave action on a marine shelf. Porosity ranges from 4 to 28 percent and averages 17.5 percent, with permeabilities ranging from 0.01 to 660 millidarcies (mD) and averaging 60 mD. Water saturation ranges from 9 to 78 percent and averages 41 percent. b. Structure: The NOP structure is a monocline that dips gently to the east and is cut by only a small number of faults that have minor vertical offsets. c. Trap Configuration and Seals: The hydrocarbon accumulation is contained by a stratigraphic trap, with along strike and updip facies changes providing lateral seals and the overlying Seabee Formation, which is about 1,000 feet thick in the planned development area, provides a top seal. Lower confinement is provided by interbedded claystones, silty shales, and shale of the Torok Formation, which has an aggregate thickness of approximately 250 feet in this area. d. Permafrost Base: The base of permafrost ranges between approximately -750 and -1,400 feet TVDss in the planned development area. 8. Reservoir Fluid Contacts: Gas and water contacts have not been directly encountered within the proposed NOP. Each oil accumulation region might have its own free water level, which are currently estimated to lie to be between -4,950 and -5,280 feet TVDSS. AIO 44 August 21, 2024 Page 7 of 13 9. Reservoir Fluid Properties: OSA provided the following properties for samples from three different accumulation regions within the planned development area. Description Pikka B Qugruk 8 Pikka C Accumulation Region South Central North Sample depth (feet TVDSS) -4,271 -4,185 -4,096 Reservoir Pressure (psia) 1,955 1,923 1,898 Reservoir Temperature (°F) 102 102 105 Stock tank oil API Gravity (°) 26.1 29.3 30.4 Gas oil ration (SCF/STB) 405 430 378 Bubble point pressure, Pb (psi) 1,609 1,561 1,631 Oil formation factor at Pb (RB/STB) 1.177 1.188 1.167 Oil viscosity at Pb (cP) 5.62 2.04 2.53 Oil Compressibility at Pb (1E-6/psi) 8.71 6.60 7.47 Gas gravity (multi-stage separator test) 0.842 0.829 0.768 Gas formation factor at Pb (RB/MSCF) 1.406 1.406 1.439 10. In-Place and Recoverable Reserves Volumes: Nanushuk Reservoir Volume Range (MMSTBO) Original Oil in Place (OOIP) 2,297-2,814 Primary Recovery (<7% OOIP) 161-253 Primary + Waterflood (23% OOIP) 532-718 Primary + Water Alternating Gas (26-29% OOIP) 592-868 Predicted Recovery from NDB pad development only (Primary + WAG ~37% OOIP) ~383 11. Reservoir Development Drilling Plan: OSA plans to develop the NOP in a phased manner. Initially, 41 wells will be drilled from the central Nanushuk Drill Site B (NDB) and future development may occur from two additional drill sites, the northern Nanushuk Drill Site A (NDA) and the southern Nanushuk Drill Site C (NDC). A horizontal line drive water- alternating-gas (WAG) development has been chosen. Due to the highly laminated nature of the reservoir, all wells will be fracture stimulated to enhance productivity and improve vertical injection sweep. Most wells will trend northwest along the maximum principal stress direction of 330° to improve waterflood performance. Wells will have horizontal sections of 3,000 to 8,000 feet length and arranged end to end, with between one and three wells in each line, to form AIO 44 August 21, 2024 Page 8 of 13 alternating rows of producers and injectors. Current studies suggest 1,800 feet between producers and injectors will be optimal, but this is subject to change based on initial well performance and the collection and analysis of addition geologic and engineering data. Development drilling on the NDB commenced in 2023 and will continue for approximately 5 years. Extended-reach drilling (ERD) may occur later. Existing and planned development wells that are used to develop the Nanushuk reservoirs in the CRU and the PU are or will be truncated a minimum of 500 feet from the common unit boundary in accordance with state spacing requirements. 12. Reservoir Management: OSA plans to develop the NOP WAG enhanced oil recovery project with water initially coming from a new build seawater treatment plant and eventually being supplemented with produced water when enough becomes available. Produced gas will be reinjected. Production and injection voidage will be balanced to maintain reservoir pressure at or near the original measured pressure. Development will target a 1.0 voidage replacement ratio. Due to the produced gas being reinjected, OSA expects the producing gas oil ratio (GOR) will increase over time and eventually exceed twice the initial GOR, which is allowable under 20 AAC 25.240(b) as, for development projects, the AOGCC may grant a waiver of the GOR limit if a pool is being developed as an enhanced oil recovery (EOR) project or if produced gas is being reinjected. 13. Wellbore Construction: From the NDB, the NOP will be developed with wells that fall into one of four tiers based primarily on the length of the well. Tier 1 and Tier 2 wells are three- casing-string design wells with a 13-3/8” surface casing set at about 2,200 feet true vertical depth (TVD) and cemented to surface, and a 9-5/8” intermediate casing set within the Nanushuk. Tier 1 wells will be fully cemented from the casing shoe to a liner-top packer (LTP) in the surface casing, while Tier 2 wells will utilize a two-stage cementing operation: initially cement will be pumped around the casing shoe and then a stage tool placed shallower in the casing string will be opened to place cement across the known shallow hydrocarbon bearing sands in the Tuluvak and continuing upward to an LTP in the surface casing. Tier 1 and 2 wells will then be completed with a 4-1/2” solid liner with hydraulic fracturing sleeves and swell packers that will be hung in the intermediate string with an LTP. Tier 3 wells are a slim hole, four-casing-string design with a 13-3/8” surface casing set at about 2,200 feet TVD and cemented to surface. A 9-5/8” intermediate 1 liner will be set along the tangent of the well and cemented using a one- or two-stage cementing operation as described for the Tier 1 and Tier 2 wells. A 7” intermediate 2 liner will land in the Nanushuk, cemented at the shoe, and tied into Intermediate 1 with an LTP. The wells will then be completed with a solid 4-1/2” liner as described for Tier 1 and Tier 2 wells. The very long Tier 4 wells will employ a large bore, four-casing-string design, and will require a different rig of greater capacity to drill and complete. These wells would be completed similarly to the Tier 3 wells except that the casing strings are enlarged to 18-5/8” surface casing, 13-3/8” Intermediate 1 liner, and 9-5/8” Intermediate 2 liner. The wells would be completed with the same 4-1/2” production liner that the Tier 1 to 3 wells employ. 14. Proposed Injection Fluids: OSA proposes that re-injection of NOP crude oil, solution gas, and minor amounts of water recovered from well tests prior to facility startup be authorized for storage injection in the NOP. AIO 44 August 21, 2024 Page 9 of 13 For EOR purposes, OSA request the following fluids be authorized for injection into the NOP: a. Beaufort seawater sourced from the PU or KRU seawater treatment plants; b. Produced water from all present and yet-to-be defined oil and gas pools with the PU, CRU, and KRU so long as produced water salinity is within the range of that produced in offset units; c. Lean and enriched gas from the PU as well as gas imported from outside the unit; d. Fluids used during hydraulic stimulation; e. Tracer survey fluids to monitor reservoir performance (chemical, radioactive, etc.); f. Fluids used to improve flowback or near wellbore injectivity (nitrogen, acid solvents, etc.); g. Fluids associated with freeze protection (diesel, crude, glycol, methanol, etc.); h. Standard oilfield chemicals (corrosion inhibitor, scale inhibitor, etc.); and i. Small amounts of Class II fluids, which will be mixed with the source or produced water including sump fluid, hydrotest fluid, rinsate generated from washing trucks, excess well work fluids, meltwater collected from well cellars. 15. Fluid Compatibility: Injection history at the CRU has demonstrated the compatibility of both produced water and seawater in Brookian age reservoirs, specifically over 10+ years in the Nanushuk formation in 16. Scale Deposition: No downhole scaling issues are expected with either seawater or produced water, and only minor scale inhibition is expected to be needed at the surface production heater. 17. Injection Volumes: NOP injection volume will be managed in an effort to maintain the voidage-replacement ratio at approximately 1:1. Fluid-injection rates for individual wells are anticipated to range between 2,000 and 10,000 BWPD and 3 and 15 MMCFPD of gas. 18. Injection Pressures: Injection pressure will be managed to prevent the injection-pressure gradient from exceeding 0.8 psi/ft, the typical injection gradient will be less than 0.75 psi/ft. Analysis indicates the confining intervals have a fracture gradient as high as 0.87 psi/ft while the NOP fracture gradient is in the 0.6 to 0.7 psi/ft range. 19. Fracture modelling: Fracture modelling indicates that fractures propagated by injection will not fracture the confining intervals. 20. Formation Water Quality: A water sample collected from the Pikka B well had a salinity of about 17,000 ppm. 21. Confinement in Offset Wells: Exploration wells which penetrate the NOP interval have been cemented across the interval and plugged above the NOP. Development wells being drilled from the NDB drill site are being constructed in accordance with AOGCC regulations and the NOP pool rules, which includes reviewing nearby wells for the injection wells to ensure injected fluids will stay within the injection interval. 22. Waivers: In addition to the waivers already granted in CO 807, OSA is seeking a waiver for the packer depth requirements of 20 AAC 25.412(b) for injection wells, which requires packers to be placed within 200’ measured depth of the injection perforations. AIO 44 August 21, 2024 Page 10 of 13 CONCLUSIONS: 1. An Area Injection Order is necessary for the proposed development of the NOP to allow for enhanced oil recovery injection operations and the storage of fluids produced during well cleanup prior to the PU processing facilities being brought online. 2. Reservoir simulation results show that a primary recovery enhanced by waterflood and water alternating gas injection maximizes ultimate recovery from the NOP. 3. Reservoir voidage will be targeted to maintain a replacement ratio of approximately 1:1. 4. Maintaining the sandface injection pressure gradient at or below 0.80 psi/ft will prevent fractures from forming or propagating in the confining intervals. 5. An aquifer exemption is not required because water from the injection interval has a salinity of approximately 17,000 ppm 6. Waivers to the packer setting depth requirements for injection wells contained in 20 AAC 25.412(b) are common in projects with high angle wells, as are being drilled for the development of the NOP, and are appropriate in this situation. NOW THEREFORE IT IS ORDERED: The underground injection of fluids for pressure maintenance, enhanced recovery, and storage purposes is authorized in the following area, subject to the following rules and 20 AAC 25, to the extent not superseded by these rules: Affected Area: Umiat Meridian (See Figure 1) Township 10 North, Range 5 East Sections 2-4: All Section 5: E1/2, SE1/4NW1/4, E1/2SW1/4, and SW1/4SW1/4 Township 11 North, Range 5 East Section 1: E1/2 and E1/2W1/2 Sections 12-13: All Section 14: E1/2, E1/2NW1/4, SW1/4NW1/4, and SW1/4 Section 15: SE1/4SE1/4 Section 22: E1/2, E1/2SW1/4, and SW1/4SW1/4 Sections 23-27: All Sections 34-36: All Township 11 North, Range 6 East Sections 1-12: All Sections 17-20: All AIO 44 August 21, 2024 Page 11 of 13 Township 12 North, Range 5 East Sections 24-25: All Section 26: NE1/4, NE1/4NW1/4, and E1/2SE1/4 Section 36: N1/2, N1/2SW1/4, SE1/4SW1/4, and SE1/4 Township 12 North, Range 6 East All Township 13 North, Range 5 East Sections 1-3: All Sections 11-14: All Sections 23-25: All Township 13 North, Range 6 East Sections 1-2: All Sections 6-36: All Township 14 North, Range 5 East Sections 24-27: All tide and submerged lands lying shoreward of the line fixed by coordinates found in Exhibit A of the Final Decree in U.S. v. Alaska, No. 84 Original Sections 34-36: All Township 14 North, Range 6 East Section 19: All tide and submerged lands lying shoreward of the line fixed by coordinates found in Exhibit A of the Final Decree in U.S. v. Alaska, No. 84 Original Sections 30 & 31: All Rule 1 Authorized Injection Strata for Enhanced Recovery Fluids authorized under Rule 3, below, may be injected for the purposes of pressure maintenance, enhanced hydrocarbon recovery, and storage within the Affected Area defined above into strata that are common to, and correlate with the interval between the measured depths of 3,829 and 5,166 feet in the Qugruk 3 well (API No. 50-103-20664-00-00; see Figure 2, above.) Rule 2 Well Construction In lieu of the packer depth requirements under 20 AAC 25.412(b), the packer/isolation equipment depth for injection wells may be located above 200 feet MD from above the top of the perforations/open interval, but shall not be located above the confining zone and shall have outer casing cement volume sufficient to place a minimum of 300 feet MD above the planned packer depth. Rule 3 Authorized Fluids for Injection for Temporary Storage and Enhanced Recovery Fluids authorized for injection for the purposes of temporary storage prior to facility startup include: a. NOP crude oil AIO 44 August 21, 2024 Page 12 of 13 b. solution gas c. minor amounts of water recovered from well tests Fluids authorized for injection for the purposes of enhanced recovery include: a. Beaufort seawater sourced from the PU or KRU seawater treatment plants; b. Produced water from all present and yet-to-be defined oil and gas pools with the PU, CRU, and KRU so long as produced water salinity is within the range of that produced in offset units; c. Lean and enriched gas from the PU as well as gas imported from outside the unit; d. Fluids used during hydraulic stimulation; e. Tracer survey fluids to monitor reservoir performance (chemical, radioactive, etc.); f. Fluids used to improve flowback or near wellbore injectivity (nitrogen, acid solvents, etc.); g. Fluids associated with freeze protection (diesel, crude, glycol, methanol, etc.); h. Standard oilfield chemicals (corrosion inhibitor, scale inhibitor, etc.); and i. 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. Rule 4 Authorized Injection Pressure for Enhanced Recovery Injection pressures will be managed so as not to exceed the maximum injection gradient of 0.80 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 NOP and are located within a quarter-mile radius of a NOP injector shall be monitored daily. All monitoring results shall be documented and available for AOGCC inspection. Rule 6 Demonstration of Tubing/Casing Annulus Mechanical Integrity The mechanical integrity of each injection well must be demonstrated before injection begins and before returning a well to service following any workover affecting mechanical integrity. An AOGCC-witnessed mechanical integrity test (MIT) must be performed after injection is commenced for the first time in a well, to be scheduled when injection conditions (temperature, pressure, rate, etc.) have stabilized. Subsequent tests must be performed at least once every four years thereafter. The AOGCC must be notified at least 72 hours in advance to enable a representative to witness an MIT. Unless an alternate means is approved by the AOGCC, mechanical integrity must be demonstrated by a tubing/casing annulus pressure test using a surface pressure equivalent to the maximum injection pressure, or 1,500 psi, whichever is greater, that shows stabilizing pressure and does not change more than 10 percent during a 30-minute period. Results of MITs must be readily available for AOGCC inspection. AIO 44 August 21, 2024 Page 13 of 13 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 NOP is not cemented), the operator shall notify the AOGCC by the next business day and submit a plan of corrective action on a Form 10-403 for AOGCC approval. The operator shall immediately shut in the well if continued operation would be unsafe or would threaten contamination of freshwater. A monthly report of daily tubing and casing annuli pressures and injection rates must be provided to the AOGCC for all injection wells for which well integrity failure or lack of injection zone isolation is indicated. Rule 8 Notification of Improper Class II 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. DONE at Anchorage, Alaska and dated August 21, 2024. Jessie L. Chmielowski Gregory C. Wilson 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. Gregory Wilson Digitally signed by Gregory Wilson Date: 2024.08.21 14:28:41 -08'00' Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2024.08.22 08:01:03 -08'00' From:Coldiron, Samantha J (OGC) To:AOGCC_Public_Notices Subject:[AOGCC_Public_Notices] Area Injection Order 44 (Oil Search) Date:Thursday, August 22, 2024 9:15:44 AM Attachments:aio 44.pdf THE APPLICATION OF Oil Search (Alaska), LLC for an order authorizing underground injection of fluids for enhanced oil recovery and oil storage in the Pikka Unit, Nanushuk Oil Pool 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 6 CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. From:Roby, David S (OGC) To:Coldiron, Samantha J (OGC) Subject:FW: Pikka AIO ownership question Date:Friday, August 16, 2024 4:31:36 PM Attachments:image001.png image002.png image003.png image004.png AIO-24-013 Dave Roby (907)793-1232 From: Jones, Tim (Tim) <Tim.Jones3@santos.com> Sent: Friday, August 16, 2024 3:58 PM To: Roby, David S (OGC) <dave.roby@alaska.gov> Cc: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>; Davies, Stephen F (OGC) <steve.davies@alaska.gov>; Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov>; Wallace, Chris D (OGC) <chris.wallace@alaska.gov> Subject: RE: Pikka AIO ownership question Dave, You are correct regarding the legal description – it is an error. The correct legal description for the pool and AIO is Section 1 of Township 11 North, Range 6 East is “Section 1 – E1/2 and E1/2W1/2”. The surface owner “Heirs, devisees and/or assigns of Neil Allen” was inadvertently left off the list of surface owners in the AIO application. The surface owner parcel is not located within a ¼ mile radius of the proposed injection wells but is located within the proposed Affected Area. Tim Jones – Land ManagerOil Search (Alaska), LLC a subsidiary of Santos Limited P.O. Box 240927 Anchorage, Alaska 99524-0927 o: +1.907.375-4624 | c:+1.907.538.1487 e: tim.jones3@santos.com Santos acknowledges the Traditional Owners and Custodians of the lands on which we operate. We pay our respects to their Elders past, present and emerging. From: Roby, David S (OGC) <dave.roby@alaska.gov> Sent: Friday, August 16, 2024 2:35 PM To: Jones, Tim (Tim) <Tim.Jones3@santos.com> Cc: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>; Davies, Stephen F (OGC) <steve.davies@alaska.gov>; Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov>; Wallace, Chris D (OGC) <chris.wallace@alaska.gov> Subject: ![EXT]: RE: Pikka AIO ownership question Also, It appears that the proposed affected area description in the AIO application and the defined is missing some acreage that’s in the unit boundary. Specifically, the pool rules and AIO application have the following highlighted legal description. But it looks like it should be “Section 1 – E1/2 and E1/2W1/2” Can you please verify this is the correct legal description for that section? If the legal description does need revising we’ll fix it in the AIO and also issued a corrected version of CO807. AIO Application: Thanks, Dave Roby (907)793-1232 From: Roby, David S (OGC) Sent: Friday, August 16, 2024 2:10 PM To: Jones, Timothy (Tim) - jonti <Tim.Jones3@santos.com> Cc: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>; Davies, Stephen F (OGC) <steve.davies@alaska.gov>; Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov>; Wallace, Chris D (OGC) <chris.wallace@alaska.gov> Subject: Pikka AIO ownership question Hi Tim, During the hearing for the Pikka pool rules the surface owners were given as: With the amended AIO application the surface owners are listed as: The proposed affected area for the AIO is the same as the affected area for the pool rules. Can you please explain why “The heirs, devisees and/or assigns of Neil Allen” was included with the pool rules application materials but is not included on the AIO’s application? Thanks, Dave Roby Senior Reservoir Engineer Alaska Oil and Gas Conservation Commission (907)793-1232 Santos Ltd A.B.N. 80 007 550 923Disclaimer: The information contained in this email is intended only for the use of the person(s) to whom it is addressed and may be confidential or contain privileged information. If you are not the intended recipient you are hereby notified that any perusal, use, distribution, copying or disclosure is strictly prohibited. If you have received this email in error please immediately advise us by return email and delete the email without making a copy. Please consider the environment before printing this email 5 Notice of Public Hearing STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION RE: Docket Numbers: AIO-24-013 By application dated April 16, 2024, Oil Search (Alaska), LLC (OSA), as the operator of the Pikka Unit (PU), requested that the Alaska Oil and Gas Conservation Commission (AOGCC) approve an Area Injection Order (AIO) to allow enhanced oil recovery (EOR) injection activities in the Nanushuk Oil Pool (Initial Application). The AOGCC held a hearing on OSA’s request on June 4, 2024. On June 11, 2024, OSA amended their application to include additional acreage in the affected area (Amended Application). Because the proposed affected area of the Amended Application expands on the proposed affected area of the Initial Application, and because the Amended Application requires notification of surface owners who were not required to be notified under the Initial Application the AOGCC must reopen the public comment period and provide the opportunity for a public hearing. Conservation Order 807 (CO 807), issued on July 20, 2023, defined the extents of the Nanushuk Oil Pool (NOP) and prescribed rules for its development. OSA is now seeking authorization to conduct an EOR injection project in the NOP in anticipation of beginning production from the PU in the coming years. The AOGCC approves injection orders for several purposes, including EOR, storage, and disposal either on an individual well or area wide basis in Alaska. EOR injection orders establish rules for conducting operations that are intended to increase the amount of oil or gas that could be recovered from a pool by one or more of the following mechanisms, maintain reservoir energy, sweeping oil through the reservoir to a production well, or modifying the properties of the oil to make it more mobile. This is consistent with the portion of the AOGCC’s mission that seeks to promote greater ultimate recovery. This notice does not contain all the information filed by OSA. To obtain more information, contact the AOGCC’s Special Assistant, Samantha Coldiron, at (907) 793-1223 or Samantha.Coldiron@alaska.gov. A public hearing on the matter has been tentatively scheduled for July 18, 2024, at 10:00 a.m. The hearing, which may be changed to full virtual, if necessary, will be held in the AOGCC hearing room located at 333 West 7th Avenue, Anchorage, AK 99501. The audio call-in information is (907) 202-7104 Conference ID: 324 917 237#. Anyone who wishes to participate remotely using MS Teams video conference should contact Ms. Coldiron at least two business days before the scheduled public hearing to request an invitation for the MS Teams. To request that the tentatively scheduled hearing be held, a written request must be filed with the AOGCC no later than 4:30 p.m. on July 1, 2024. If a request for a hearing is not timely filed, the AOGCC may issue an order without a hearing. To learn if the AOGCC will hold the hearing, call (907) 793-1223 after July 3, 2024. In addition, written comments regarding this application may be submitted to the AOGCC, at 333 west 7th Avenue, Anchorage, AK 99501 or samantha.coldiron@alaska.gov. Comments must be received no later than 4:30 p.m. on July 16, 2024, except that, if a hearing is held, comments must be received no later than the conclusion of the July 18, 2024, hearing. If, because of a disability, special accommodations may be needed to comment or attend the hearing, contact Samantha Coldiron, at (907) 793-1223, no later than July 11, 2024. Brett W. Huber, Sr. Chair, Commissioner Brett W. Huber, Sr. Digitally signed by Brett W. Huber, Sr. Date: 2024.06.12 17:02:35 -05'00' From:Coldiron, Samantha J (OGC) To:AOGCC_Public_Notices Subject:[AOGCC_Public_Notices] Public Hearing Notice (Oil Search (Alaska), LLC) Date:Wednesday, June 12, 2024 3:07:32 PM Attachments:AIO-24-013 public hearing notice establishing an AIO for the NOP in PU - Amended.pdf RE: Docket Numbers: AIO-24-013 By application dated April 16, 2024, Oil Search (Alaska), LLC (OSA), as the operator of the Pikka Unit (PU), requested that the Alaska Oil and Gas Conservation Commission (AOGCC) approve an Area Injection Order (AIO) to allow enhanced oil recovery (EOR) injection activities in the Nanushuk Oil Pool (Initial Application). The AOGCC held a hearing on OSA’s request on June 4, 2024. On June 11, 2024, OSA amended their application to include additional acreage in the affected area (Amended Application). Because the proposed affected area of the Amended Application expands on the proposed affected area of the Initial Application, and because the Amended Application requires notification of surface owners who were not required to be notified under the Initial Application the AOGCC must reopen the public comment period and provide the opportunity for a public hearing. 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 Lisi Misa being first duly sworn on oath deposes and says that she is a representative of the An- chorage Daily News, a daily newspaper. That said newspaper has been approved by the Third Judicial Court, Anchorage, Alaska, and it now and has been published in the English language continually as a daily newspaper in Anchorage, Alaska, and it is now and during all said time was printed in an office maintained at the afore- said place of publication of said newspaper. That the annexed is a copy of an advertisement as it was published in regular issues (and not in supplemental form) of said newspaper on AFFIDAVIT OF PUBLICATION ______________________________________ Notary Public in and for The State of Alaska. Third Division Anchorage, Alaska MY COMMISSION EXPIRES ______________________________________ 06/16/2024 and that such newspaper was regularly distrib- uted to its subscribers during all of said period. That the full amount of the fee charged for the foregoing publication is not in excess of the rate charged private individuals. Signed________________________________ Subscribed and sworn to before me Account #: 100869 ST OF AK/AK OIL AND GAS CONSERVATION COMMISSION333 W. 7TH AVE STE 100, ANCHORAGE, AK 99501 Order #: W0046397 Cost: $414.48 Notice of Public HearingSTATE OF ALASKAALASKA OIL AND GAS CONSERVATION COMMISSION RE: Docket Numbers: AIO-24-013 By application dated April 16, 2024, Oil Search (Alaska), LLC (OSA), as the operator of the Pikka Unit (PU), requested that the Alaska Oil and Gas Conservation Commission (AOGCC) approve an Area Injection Order (AIO) to allow enhanced oil recovery (EOR) injection activities in the Nanushuk Oil Pool (Initial Application). The AOGCC held a hearing on OSA’s request on June 4, 2024. On June 11, 2024, OSA amended their application to include additional acreage in the affected area (Amended Application). Because the proposed affected area of the Amended Application expands on the proposed affected area of the Initial Application, and because the Amended Application requires notification of surface owners who were not required to be notified under the Initial Application the AOGCC must reopen the public comment period and provide the opportunity for a public hearing. Conservation Order 807 (CO 807), issued on July 20, 2023, defined the extents of the Nanushuk Oil Pool (NOP) and prescribed rules for its development. OSA is now seeking authorization to conduct an EOR injection project in the NOP in anticipation of beginning production from the PU in the coming years. The AOGCC approves injection orders for several purposes, including EOR, storage, and disposal either on an individual well or area wide basis in Alaska. EOR injection orders establish rules for conducting operations that are intended to increase the amount of oil or gas that could be recovered from a pool by one or more of the following mechanisms, maintain reservoir energy, sweeping oil through the reservoir to a production well, or modifying the properties of the oil to make it more mobile. This is consistent with the portion of the AOGCC’s mission that seeks to promote greater ultimate recovery. This notice does not contain all the information filed by OSA. To obtain more information, contact the AOGCC’s Special Assistant, Samantha Coldiron, at (907) 793-1223 or Samantha.Coldiron@alaska.gov. A public hearing on the matter has been tentatively scheduled for July 18, 2024, at 10:00 a.m. The hearing, which may be changed to full virtual, if necessary, will be held in the AOGCC hearing room located at 333 West 7th Avenue, Anchorage, AK 99501. The audio call-in information is (907) 202-7104 Conference ID: 324 917 237#. Anyone who wishes to participate remotely using MS Teams video conference should contact Ms. Coldiron at least two business days before the scheduled public hearing to request an invitation for the MS Teams. To request that the tentatively scheduled hearing be held, a written request must be filed with the AOGCC no later than 4:30 p.m. on July 1, 2024. If a request for a hearing is not timely filed, the AOGCC may issue an order without a hearing. To learn if the AOGCC will hold the hearing, call (907) 793-1223 after July 3, 2024. In addition, written comments regarding this application may be submitted to the AOGCC, at 333 west 7th Avenue, Anchorage, AK 99501 or samantha.coldiron@alaska.gov. Comments must be received no later than 4:30 p.m. on July 16, 2024, except that, if a hearing is held, comments must be received no later than the conclusion of the July 18, 2024, hearing. If, because of a disability, special accommodations may be needed to comment or attend the hearing, contact Samantha Coldiron, at (907) 793-1223, no later than July 11, 2024. Brett W. Huber, Sr.Chair, Commissioner Pub: June 16, 2024 STATE OF ALASKA THIRD JUDICIAL DISTRICT ______________________________________2024-06-27 2024-07-14 Document Ref: DTEZW-XVNBP-SFQOQ-PTHHY Page 2 of 18 4 CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. From:Jones, Tim (Tim) To:Coldiron, Samantha J (OGC) Cc:Roby, David S (OGC) Subject:Modification and additional information related to AIO application - AIO-24-013 Date:Tuesday, June 11, 2024 5:22:07 PM Attachments:image001.png AIO 24-013 Request for Additional Information - FIT-LOT Data.pdf 20240611 Nanushuk AIO Modification - Additional Surface Owners.pdf Samantha, Please find attached information in response to Commissioner questions from the June 4, 2024 public hearing in support of OSA’s application for an Area Injection Order, Docket Number AIO-24-013. The attached information consists of the following: 1. Requested data related to determination of injection containment – FIT and LOT results 2. Modified Application for Area Injection Order, including the listing of additional surface owners in the section referencing 20 AAC 25.402 & 25.252(c)(2,3) and Attachment 1 – Affidavit A question was raised at the hearing regarding OSA’s intent to file an application for an Aquifer Exemption. OSA will not file an application for an Aquifer Exemption at this time. If there are any additional questions, please contact me. Thank you. Tim Jones – Land ManagerOil Search (Alaska), LLC a subsidiary of Santos Limited P.O. Box 240927 Anchorage, Alaska 99524-0927 o: +1.907.375-4624 | c:+1.907.538.1487 e: tim.jones3@santos.com Santos acknowledges the Traditional Owners and Custodians of the lands on which we operate. We pay our respects to their Elders past, present and emerging. Santos Ltd A.B.N. 80 007 550 923Disclaimer: The information contained in this email is intended only for the use of the person(s) to whom it is addressed and may be confidential orcontain privileged information. If you are not the intended recipient you are hereby notified that any perusal, use, distribution, copying or disclosure isstrictly prohibited. If you have received this email in error please immediately advise us by return email and delete the email without making a copy. Please consider the environment before printing this email Relevant tests for determining injection containment in the Pikka Unit are shown below. All tests obtained at NDB were taken within the Pikka NT3 reservoir and represent the breakdown gradient of the reservoir sandstone. Formation breakdown data for the Seabee Formation cap rock are applied from NDB near-offset wells. Gradients below are slightly higher than referenced in the AIO application due to being calculated from ground level elevation (GL) instead of the rig KB. Type Elev TVDGL TVD MD psi well name TVDGL grad Zone FIT 20 3407.0 3406.0 10763.4 2679 CRU CD4-595 PH1 0.79 Seabee FIT 20 3431.0 3458.0 10389.7 2733 CRU CD4-594 PH1 0.80 Seabee LOT 19.8 3017.8 3050.0 3943.2 2423 TOFKAT 1 0.80 Seabee FIT 22.8 4066.6 4113.6 11120.6 3000 PIKKA NDBi-044 0.74 NT3 reservoir FIT 17 4115.0 4135.0 4782.7 2580 QUGRUK 301 0.63 NT3 reservoir FIT 12.28 4147.6 4167.6 4417.7 2709 PIKKA C 0.65 NT3 reservoir FIT 22.8 4273.3 4320.9 10328.2 3369 PIKKA NDBi-043 0.79 NT3 reservoir FIT 22.8 4069.3 4116.0 11469.3 3210 PIKKA NDB-024 0.79 NT3 reservoir FIT 22.8 4276.3 4324.0 6518.3 3371 PIKKA NDB-032 0.79 NT3 reservoir LOT 20 4030 4063 14795 3547.76 CRU CD4-594 0.88 NT4 seal Nanushuk Area Injection Order Application April 16, 2024 (Modified June 11, 2024) Page | 1 List of Figures Figure 1: Pikka Unit map ............................................................................................................................... 2 Figure 2: Plat of Planned injection well locations for NOP development . .................................................. 4 Figure 3: The Qugruk 3 Type log with depths of Nanushuk Oil Pool. ........................................................... 5 Figure 4: Cross section of upper (Seabee) and lower confining intervals (Torok) for the NOP .................... 7 Figure 5: Nanushuk typical producer Completion with liner tieback ........................................................... 9 Figure 6: Typical well with 2‐stage cement job........................................................................................... 10 Figure 7: Nanushuk proposed NDB‐43 injector Completion ...................................................................... 11 Figure 8: Frac modelling of the Q‐8 well with perforations 20' below top of Nanushuk ........................... 13 Introduction Oil Search (Alaska), LLC, a subsidiary of Santos Ltd (“Santos”), in its capacity as operator of the Pikka Unit (shown in Figure 1) submits this document to the Alaska Oil and Gas Conservation Commission (“AOGCC” or “Commission”) on behalf of itself and other working interest owner (“WIO”) Repsol E&P USA LLC (Repsol).This application to the AOGCC seeks endorsement and authorization for enhanced recovery (water & gas) and storage injection operations in the Nanushuk Oil Pool (“NOP”) for which Pool Rules were finalized on July 20, 2023 under CO 807. A water injection pulse test is planned for June 2024 to confirm connectivity between wells and expected waterflood response. Well tests are being conducted to optimize development plans and storage avoids risks associated with hauling fluids to a non-Santos operated facility prior to field startup. Storage of produced oil from initial development well tests will prevent waste prior to full field startup. 20 AAC 25.402 & 25.252(c)(1) Location of proposed injection wells and ¼ mile offset penetrations A plat showing the location of each proposed injection well, abandoned or other unused well, production well, dry hole, or other well within a ¼ mile radius of each proposed injection well are shown in Figure 2. Nanushuk Area Injection Order Application April 16, 2024 (Modified June 11, 2024) Page | 2 Figure 1: Pikka Unit/Nanushuk Oil Pool map Nanushuk Area Injection Order Application April 16, 2024 (Modified June 11, 2024) Page | 3 20 AAC 25.402 & 25.252(c)(2,3) List and notification of operators and surface owners (Modified June 11, 2024) Operators within a ¼ mile radius of the proposed injection wells are ConocoPhillips Alaska; Inc (CPAI) and Oil Search (Alaska), LLC. The surface owners within the proposed Area Injection Order Affected Area are the Kuukpik Corporation, the State of Alaska, Katherine Brown, Jim T. Allen, and the Estate of Helen E. Tukle. An affidavit showing that a copy of this application has been provided to the operators and surface owners within proposed Area Injection Order Affected Area, including within a ¼ mile radius of each proposed injection well, is attached as Attachment 1. 20 AAC 25.402 & 25.252(c)(4) Description of the Proposed Operation Enhanced recovery operations within the NOP will employ a horizontal well line drive pattern with a Water Alternating Gas (“WAG”) or rich gas flood, to enhance oil recovery from the reservoir. Due to the highly laminated nature of the reservoir, all the wells (including the injectors) will be hydraulically fracture stimulated to enhance productivity and improve vertical injection sweep. Additionally, to remove potentially damaging fracturing gel and confirm rate capacity, frac flowbacks will be conducted; and accompanying oil production from the wells will be re-injected into the reservoir prior to startup to prevent waste. Only pre-production test fluids recovered beyond the initial load recovery will be re-injected, with volumes and injection pressures being tracked to ensure fracture gradients are not exceeded. For flexibility in dispersing pressure, test fluids may be injected in both producers and injectors which have been previously hydraulically fractured. Nanushuk Area Injection Order Application April 16, 2024 (Modified June 11, 2024) Page | 4 Figure 2: Plat of Planned injection well locations for NOP development. 20 AAC 25.402(c)(5) Description and Depth of Pool to be Affected The Nanushuk reservoir is a thick accumulation of deltaic shoreface deposits and is the up dip topset equivalent of the deeper water Torok Formation. The NOP is defined as the accumulation of hydrocarbons common to and correlating with the interval defined by the Nanushuk formation, between Nanushuk and Torok formation tops, from measured depths of 3,892 and 5,166 ft or 3,785 ft true vertical depth subsea (TVDSS) to 4,985 ft TVDSS shown on the Qugruk-3 well type log (Figure 3). Nanushuk Area Injection Order Application April 16, 2024 (Modified June 11, 2024) Page | 5 Figure 3: The Qugruk 3 Type log with depths of Nanushuk Oil Pool. Lower Confining Interval Torok Formation Lithologic Description: The Torok Formation underlies the target reservoir Nanushuk Formation and is dominantly comprised of claystones and silty shales and thick shale sequences. The formation grades Nanushuk Area Injection Order Application April 16, 2024 (Modified June 11, 2024) Page | 6 from silty shales in the shallower section to shale at the base of the Torok Formation. The shales are described in offset wells as very fine grained medium dark grey to dark brownish and greyish black. Soft to easily friable, occasionally firm. The succession is dominated by tabular to platy cuttings with very well- developed laminations, and high organic content overall with layers of organic/carbonaceous material. The fracture gradient for this sealing shale is 16.0-17.0 ppg. Depth & Thickness: 5,200 MD/5,135 TVDSS, ~250ft TVT Upper Confining Interval Seabee Formation Lithologic Description: The Seabee Formation immediately overlies the Nanushuk Formation. The base of the Seabee is the shale wall facies which is a marine flooding surface composed of condensed mudstone facies deposited during a maximum transgression and creates a good regional seal. Distant volcanism occurred during its deposition resulting in numerous bentonite interbeds. The overall Seabee Formation is a thick shale/claystone dominated unit which represents the distal deep-water slope and basinal deposits. The claystones within the Seabee Formation are described as medium grey to dark grey, soft and mushy to slightly firm, locally partings along laminations, commonly micas and scattered very fine lithic grains. Grading to weakly fissile shale. The fracture gradient for this sealing shale is 14.9- 16.8 ppg confirmed by a leak off test in well CD4-594 at 14,767 ft MD/4,059 ft TVD (16.8 ppg EMW or .87 psi/ft) and a formation integrity test in NDB-43 at 6,260 ft MD/4,323 ft TVD (14.9 ppg EMW or .77 psi/ft) Depth & Thickness: 3,175 ft MD/2,830 ft TVDSS, ~1,000 ft TVT Nanushuk Area Injection Order Application April 16, 2024 (Modified June 11, 2024) Page | 7 Figure 4: Cross section of upper (Seabee) and lower confining intervals (Torok) for the NOP. 20 AAC 25.402 (c)(6) Description of the Formation The Torok and Nanushuk Formations are the lower portion of the Brookian sequence and are Lower Cretaceous in age. The Lower Cretaceous section is a large-scale constructional siliciclastic clinoform system, where the topset unit is the Nanushuk Formation and the foreset unit is the Torok Formation. The internal architecture of the system is comprised of multiple clinoforms, of different order, accretionary deposited from west to east. The development of the NOP in the Pikka Unit contemplates the drilling of long horizontal wells across a number of different order clinoforms or prograding parasequence sets. The Nanushuk hydrocarbon bearing sandstones are often present at the topset of the clinoforms and comprised of amalgamated sands gradationally changing to clay-siltstone with abundant thinly laminated mudstones. 20 AAC 25.402 (c)(7) & 25.252(c)(5) Logs of Injection wells Well logs derived from each injection well to be provided with each wells completion report. 20 AAC 25.402(c)(6) & 25.252(c)(12) Mechanical Integrity of Injection Wells Surface holes will be drilled and set above the Tuluvak formation for proper anchorage, prevention of uncontrolled flow, and protection from permafrost thaw and freeze back. In the Pikka area there are Nanushuk Area Injection Order Application April 16, 2024 (Modified June 11, 2024) Page | 8 some known areas of shallow gas within the Tuluvak formation, so top-setting the Tuluvak will allow blowout prevention equipment (BOPE) to be installed prior to drilling the gas-bearing formation. This casing setting depth provides adequate depth for required kick tolerance to drill the intermediate section. Within the planned development area, the base of permafrost is interpreted to be between 750 ft and 1,400 ft TVDSS. Surface casing strings will be cemented in accordance with 20 AAC 25.030(d)(4). The blowout prevention equipment (BOPE) will be installed and tested in accordance with 20 AAC.25.035 requirements. A Formation Integrity Test (FIT) will be performed in accordance with 20 AAC 25.030(f). Intermediate sections will be drilled utilizing the latest directional techniques from surface casing, encountering the top of the Nanushuk at 40-85 degree inclination. Casing will be set and cemented with the shoe just above, or just into, the Nanushuk Reservoir and containment will be verified with a bond log. The Tuluvak will be cemented where gas is present. A gas-tight liner top packer will provide secondary containment above with the surface casing cement as additional protection against gas movement. The section between the Tuluvak and the top of the Nanushuk Reservoir consists primarily of mudstones and siltstones with no significant hydrocarbon zones. See figures below for a sketch of a typical producer well design for the first injector completed in the NOP, NDB-43. Nanushuk Area Injection Order Application April 16, 2024 (Modified June 11, 2024) Page | 9 Figure 5: Nanushuk typical producer Completion with liner tieback. Nanushuk Area Injection Order Application April 16, 2024 (Modified June 11, 2024) Page | 10 Figure 6: Typical well with 2‐stage cement job. Nanushuk Area Injection Order Application April 16, 2024 (Modified June 11, 2024) Page | 11 Figure 7: 7Nanushuk proposed NDB‐43 injector Completion. Depending on well length and inclination, one or more intermediate strings or two stage cement jobs may be deployed between the surface casing shoe and the top of the Nanushuk Reservoir, as determined by the required engineering design. Cementation of intermediate/production casing will comply with all other requirements of 20 AAC 25.030(d)(5) including coverage of Tuluvak sand when gas is present as stipulated in CO 807. The tubing/casing annulus pressure of each injection well will be tested and monitored in accordance with 20 ACC 25.412(c). Drilling and completion operations will be performed in accordance with applicable Nanushuk Area Injection Order Application April 16, 2024 (Modified June 11, 2024) Page | 12 AOGCC regulations. In accordance with 20 AAC 25.412(d), cement bond 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. 20 AAC 25.402(c)(9) & 20 AAC 25.252 (c)(7) Injection Fluid Analysis and Injection Rates The storage operation will involve re-injection of NOP crude oil, solution gas & minor amounts of water recovered from well tests prior to facility startup. Seawater with alternating gas-injection is proposed for enhanced recovery injection into the NOP. After water-breakthrough, individual well patterns may be swapped to produced water. Injection history at the Colville River Unit has demonstrated the compatibility of both produced water and sea water in Brookian age reservoirs, specifically the Nanushuk formation at the Qannik pool, over the past 10+ years. No issues are expected with injection of either seawater or produced water/gas into the Nanushuk formation. Liquid injection rates between 2,000 and 10,000 bbl/d and gas rates between 3 and 15 MMscf/day are expected at each injection well drilled for the project and will be managed to achieve and maintain a voidage replacement ratio of 1. Proposed allowable injection fluids include: Beaufort seawater sourced from the Pikka or Kuparuk seawater treatment plant. Produced water from all present and yet -to -be defined oil pools within the Pikka, Colville, and Kuparuk River Units so long as produced water salinity is within range of that produced in offset Units. Lean and enriched gas from the Pikka Unit as well as gas imported from outside the Unit. 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 Nanushuk injection wells. These fluids are not planned for continuous injection, or as a means for enhanced recovery. The volumes of these other fluids are not expected to hinder the recovery efficiency of performance. These other fluids include: a. Fluids used during hydraulic stimulation, including reservoir oil and solution gas from flowback testing prior to production facility startup. b. Tracer survey fluids to monitor reservoir performance. c. Fluids used to improve flowbacks or near wellbore injectivity (nitrogen, acid, solvents, etc.) d. Fluids associated with freeze protection (diesel, crude, glycol, methanol, etc.) e. Standard oilfield chemicals (corrosion inhibitor, scale inhibitor, etc.) f. Sump fluid, hydrotest fluid, rinsate generated from washing mud hauling trucks, excess well work fluids, and treated camp effluent and mixtures involving such fluids. 20 AAC 25.402 (c)(10) & 25.252(c)(8) Estimated Average and Maximum Injection Pressures The flowing bottom hole pressure of the injection wells will be maintained within the strength of the K-3 seal. Analysis of available data in the seal interval yielded a fracture gradient as high as 0.87 psi/ft. The project will target an injection gradient of 0.7 psi/ft with an operating maximum at 0.8 psi/ft, but this is subject to change as more information is gathered. The project will operate near the fracture gradient of the NOP reservoir sandstone which has demonstrated a fracture gradient of 0.6 to 0.7 psi/ft in the multiple exploration fracture tests. Nanushuk Area Injection Order Application April 16, 2024 (Modified June 11, 2024) Page | 13 At 4,100' TVDSS the typical bottomhole injection pressure will be less than 2,875 psi (0.75 psi/ft), with temporary operational deviations up to a maximum of 3,280 psi (0.8 psi/ft). The maximum surface operating pressure of each injector will be set based on the realized depth of the reservoir and hydrostatic gradient of fluid injected. 20 AAC 25.402(c)(11) & 25.252(c)(9) Fracture Information In the Pikka Unit area, the NOP is overlain by a 240 to 310 foot TVD claystone section with thin siltstone beds from the K-3 marker to the top NOP sandstone; part of the Cretaceous Nanushuk Group, here referred to as the K-3 Seal. The underlying confining zone beneath the NOP consists of 25-100 feet TVD of shaley slope mudstones and shales that thicken to the east/southeast. The calculated hydraulic fracture gradient for the K-3 Seal is based on the available leak-off tests (LOT) and formation integrity tests (FIT) in the immediate area that include one LOT within the seal interval that exceeded 3,500 psig. Fracture modelling indicates that fractures are contained within the reservoir. Fracture modelling is done with StimPlan software heavily used in industry and validated with rock mechanical properties obtained from core, well logs, and appraisal well fracture tests. Figure 8: Frac modelling of the Q‐8 well with perforations 20' below top of Nanushuk. 20 AAC 25.402 (c)(12) & 25.252(c)(10) Quality of Formation Water A water sample was obtained from the Pikka B well at 4,784’ approximately 600’ below the top of the Nanushuk. The salinity of this water was found to be about 17,000 ppm with relatively low calcium and barium concentrations as shown below. No downhole scaling issues are expected with either seawater or produced water, and only minor scale inhibition is expected to be needed at the surface production heater. Nanushuk Area Injection Order Application April 16, 2024 (Modified June 11, 2024) Page | 14 Table 1: Water analysis from NOP well Pikka B. 4834' MD sample Cations Test Method (mg/l) Meq/l Pikka B Barium Ba+2 ICP 8.9 0.16 Cadmium Cd+2 ICP <0.006 0.00 Calcium Ca+2 ICP 79 4.94 Chromium Cr+3 ICP <0.007 0.00 Cobalt Co+2 ICP <0.01 0.00 Copper Cu+2 ICP <0.009 0.00 Iron (total) Fe+2 ICP 8.1 0.00 Lead Pb+2 ICP <2.2 0.00 Lithium Li+ ICP 1.7 0.29 Magnesium Mg+2 ICP 24 1.55 Manganese Mn+2 ICP 0.0 0.00 Molybdenum Mo+6 ICP <0.044 0.00 Nickel Ni+2 ICP <0.02 0.01 Phosphorus P+3 ICP <0.17 0.00 Potassium K+ ICP 37 1.24 Silicon Si+4 ICP 10 2.16 Sodium Na+ ICP 6,420 302.09 Strontium Sr+2 ICP 4.2 0.10 Vanadium V+2 ICP <0.01 0.00 Zinc Zn+2 ICP 0.0 0.00 Anions Test Method (mg/l) Meq/l Bicarbonate HCO3- Titration 575 63.97 Borate B(OH)4- ICP 7.9 0.18 Bromide Br- Titration / IC 87 1.02 Carbonate CO3-2 Titration 18 0.00 Chloride Cl- Titration / IC 9,430 259.13 Fluoride F- IC <2 0.00 Iodide I- Titration / IC 30 0.30 Nitrate NO3-2 IC <2 0.00 Nitrite NO2- IC <2 0.00 Phosphate PO4-3 IC <2 0.00 Nanushuk Area Injection Order Application April 16, 2024 (Modified June 11, 2024) Page | 15 Sulfate SO4-2 IC 27 0.43 Sulfide S-2 IC 0.0 0.00 Bicarbonate HCO3- Rice Titration 401 Organic Acids Test Method (mg/l) Meq/l Acetate CH3COO- IC 3,170 53.71 Butyrate CH3(CH2)2CO2- IC 30 0.35 Formate HCOO- IC <10 0.00 Glycolate CH2OHCOO- IC <10 0.00 Propionate CH3CH2CO2- IC 315 4.33 Valerate CH3(CH2)3CO2- IC <10 0.04 Total Cation Meq's 313 Stability Index at 100 °F -0.42 Total Anion Meq's 325 Stability Index at 200 °F 1.47 TDS (mg/l) 17,169 TDS (ppm) 16,953 % Deviation in Meq. Bal. 10.19 Ion Balance 0.102 % Deviation in TDS 3.62 20 AAC 25.402(c)(13) & 25.252(c)(11) Aquifer Exemption Reference Santos is not aware of any Aquifer Exemption Orders in the proposed area. Examination of well log data from exploratory wells in and near the proposed NOP confirms that there are no freshwater aquifers within the affected area that could serve as underground sources of drinking water. None of the subsequent oil pools and area injection orders in the adjacent units have found any freshwater aquifers to exist within the Colville River, Oooguruk, or Kuparuk unit areas. 20 AAC 25.4O2(c)(14) Incremental Hydrocarbon Recovery The NOP will be developed in a phased approach initiated from existing infrastructure. Development will be completed in discrete phases to apply knowledge gained from previous phases and improve recovery. The initial targets will be accessed from the NDB drill site and future targets may be accessed via additional drill sites. The table below summarizes the potential resources associated with full NOP development. Table 2: Estimated Nanushuk oil in place with recoverable volumes associated with different recovery mechanisms. Nanushuk Reservoir low high Original Oil in Place (OOIP) 2,297 - 2,814 MMSTB Primary Recovery 161 - 253 MMSTB Primary + Waterflood 532 - 718 MMSTB Primary + Waterflood + WAG 592 - 868 MMSTB Nanushuk Area Injection Order Application April 16, 2024 (Modified June 11, 2024) Page | 16 The NOP will employ a horizontal well line drive pattern with the intent to convert to a Water Alternating Gas (“WAG”) or rich gas flood, to enhance oil recovery from the reservoir. Due to the highly laminated nature of the reservoir, all the wells (including the injectors) will be hydraulically fracture stimulated to enhance productivity and improve vertical injection sweep. 20 AAC 25.402 & 25.252(c)(15) Mechanical Condition of Wells Within 1/4 Mile of Proposed Area The only wells which penetrate the NOP interval within 1/4 mile of proposed injection operations are exploration wells which have been cemented across and plugged above the NOP and will be documented with the drilling permit for proposed injectors. Proposed wells will be drilled in accordance with applicable AOGCC drilling regulations. Proposed Rules Underground injection of fluids for oil storage, pressure maintenance and enhanced recovery to be 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 Township 10 North, Range 5 East Sections 2-4 – All Section 5 – E1/2, SE1/4NW1/4, E1/2SW1/4, and SW1/4SW1/4 Township 11 North, Range 5 East Section 1 – E1/2 and E1/2W1/4 Sections 12-13 – All Section 14 – E1/2, E1/2NW1/4, SW1/4NW1/4 and SW1/4 Section 15 – SE1/4SE1/4 Section 22 – E1/2, E1/2SW1/4, and SW1/4SW1/4 Sections 23-27 – All Sections 34-36 – All Township 11 North, Range 6 East Sections 1-12 – All Sections 17-20 – All Township 12 North, Range 5 East Sections 24-25 – All Section 26 – NE1/4, NE1/4NW1/4, and Nanushuk Area Injection Order Application April 16, 2024 (Modified June 11, 2024) Page | 17 E1/2SE1/4 Section 36 – N1/2, N1/2SW1/4, SE1/4SW1/4, and SE1/4 Township 12 North, Range 6 East All Township 13 North, Range 5 East Sections 1-3 - All Sections 11-14 – All Sections 23-25 - All Township 13 North, Range 6 East Sections 1-2 – All Sections 6-36 – All Township 14 North, Range 5 East Sections 24-27 - All tide and submerged lands lying shoreward of the line fixed by coordinates found in Exhibit A of the Final Decree in U.S. v. Alaska, No. 84 Original Sections 34-36 - All Township 14 North, Range 6 East Section 19 – All tide and submerged lands lying shoreward of the line fixed by coordinates found in Exhibit A of the Final Decree in U.S. v. Alaska, No. 84 Original Sections 30 & 31 - All Rule 1: Authorized Injection Strata The Nanushuk Oil Pool as defined as the accumulation of oil and gas common to and correlating to the stratigraphic interval between 3,892 and 5,166 feet measured depth in the Qugruk-3 well and its lateral equivalents. Rule 2: Well Construction Packers in injection wells may be located more than 200 feet measured depth above the top of the injection zone; however, packers must not be located above the confining zone. In cases where the distance is more than 200 feet, the production casing cement volume should be sufficient to place cement a minimum 300 feet measured depth above the planned packer depth as well as coverage of the Tuluvak as stipulated in the pool rules. Rule 3: Authorized fluids for injection 1. For storage operations: re-injection of crude oil, solution gas & minor amounts of fracturing fluid water recovered from NOP well tests prior to facility startup. 2. For Enhanced Recovery operations: a. Beaufort seawater sourced from the Pikka or Kuparuk seawater treatment plant. b. Produced water from all present and yet -to -be defined oil pools within the Pikka, Colville, and Kuparuk River Units so long as produced water salinity is within range of that produced in offset Units. c. Lean and enriched gas from the Pikka Unit as well as gas imported from outside the Unit. 3. Minor amounts of the following fluids: a. Tracer survey fluids to monitor reservoir performance. Nanushuk Area Injection Order Application April 16, 2024 (Modified June 11, 2024) Page | 18 b. Fluids used to improve flowbacks or injectivity (nitrogen, acid, solvents, etc.) c. Fluids associated with freeze protection (diesel, crude, glycol, methanol, etc.) d. Standard oilfield chemicals (corrosion inhibitor, scale inhibitor, etc.) e. Sump fluid, hydrotest fluid, rinsate generated from washing mud hauling trucks, excess well work fluids, and treated camp effluent and mixtures involving such fluids. Rule 4: Authorized Injection pressures At 4,100' TVDSS the target bottomhole injection pressure will be less than 3,280 psi (0.8 psi/ft). The maximum surface operating pressure of each injector will be set based on the realized depth of the reservoir and hydrostatic gradient of fluid injected. Rule 5: Tubing-Casing Annulus Pressure monitoring The operator shall monitor each injection well daily to check for sustained pressure, except if prevented by extreme weather conditions, emergency situations, or unavoidable circumstances. Monitoring results shall be made available for AOGCC inspections. Rule 6: Demonstration of Mechanical Integrity At the time of installation or replacement, the operator shall conduct and document a pressure test of tubulars and completion equipment in each production well that is sufficient to demonstrate that planned well operations will not result in failure of well integrity, uncontrolled release of fluid or pressure, or threat to human safety. 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. Mechanical integrity must be demonstrated by a tubing/casing annulus pressure using a surface pressure of 1,500 psi that shows stabilizing pressure that does not change more than 10 percent during a 30-minute test period. 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. Rule 7: Well Integrity and Confinement The operator shall notify the AOGCC within one business day and submit a plan for corrective action via Form 10-403 after identifying a well as having lost injection zone isolation as indicated by injection rate, pressure, log or other evidence. Rule 8: Notification of Improper Class II Injection AOGCC shall be notified of injection of fluids other than those listed in Rule 3 and provide details of the operation and propose actions to prevent reoccurrence. Rule 9: Other Conditions If fluids are found to be fracturing the confining zone or migrating out of the approved injection strata, the Operator must immediately shut in the injection well and notify AOGCC. Injection may not be restarted unless approved by the AOGCC. ATTACHMENT 1 Affidavit (Modified June 11, 2024) State of Alaska, Third Judicial District Personally appeared before me, Timothy Jones, who, being duly sworn according to law, deposes and says: 1. I, Timothy Jones, am the Land Manager for Oil Search (Alaska), LLC and a Registered Professional Landman #84167. 2. I caused copies of the Nanushuk Area Injection Order application to be provided to the following operators and surface owners within the Area Injection Order Affected Area. Operators: Oil Search (Alaska), LLC Attn: Land Manager P.O. Box 240927 Anchorage, AK 99524-0927 ConocoPhillips Alaska, Inc. Attn: Land Manager P.O. Box 100360 Anchorage, AK 99510-0360 Surface Owners: Kuukpik Corporation 582 E. 36th Avenue Anchorage, AK 99503 State of Alaska Department of Natural Resources Alaska Division of Oil and Gas 550 W 7th Avenue, Suite 1100 Anchorage, AK 99501-3560 Katherine Brown 1805 Lilac Ave. Fairbanks, AK 99712 Jim T. Allen PO Box 200013 Anchorage, AK 99520-0013 Nanushuk Area Injection Order Application April 16, 2024 (Modified June 11, 2024) Page | 2 Estate of Helen E. Tukle ATTN: Eunice Sielak, Personal Representative PO Box 89047 Nuiqsut, AK 99789 Further the affiant sayeth naught. ____________________________________________ __________________ Timothy Jones Date RPL #84167 UNITED STATES OF AMERICA § § STATE OF ALASKA § Subscribed and sworn to before me on the _____ day of June, 2024. Notary Public My commission expires: 3 AOGCC 6/4/2024 ITMO: APPLICATION OF OIL SEARCH AK FOR AN AREA INJECTION DOCKET No. AIO-24-013 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 ALASKA OIL AND GAS CONSERVATION COMMISSION In the Matter of the Application of ) Oil Search Alaska for an Area Injection ) Order for the Nanushuk Oil Pool, Pikka ) Unit. ) __________________________________________) Docket number: AIO-24-013 PUBLIC HEARING June 4, 2024 10:00 o'clock a.m. BEFORE: Brett Huber, Chairman Jessie Chmielowski, Commissioner Greg Wilson, Commissioner AOGCC 6/4/2024 ITMO: APPLICATION OF OIL SEARCH AK FOR AN AREA INJECTION DOCKET No. AIO-24-013 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 Page 2 1 TABLE OF CONTENTS 2 Opening remarks by Commissioner Huber 03 3 Testimony by Mr. Bond 09 4 Testimony by Mr. Jones 09 5 Testimony by Mr. Noll 10 6 Testimony by Mr. Terpack 32 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 AOGCC 6/4/2024 ITMO: APPLICATION OF OIL SEARCH AK FOR AN AREA INJECTION DOCKET No. AIO-24-013 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 Page 3 1 P R O C E E D I N G S 2 (On record - 10:00 a.m.) 3 CHAIRMAN HUBER: Again this is approximately 4 10:00 a.m. on Tuesday, June 4th, 2024. This is a 5 public hearing on docket number AIO-24-013 to establish 6 an area injection order for the Nanushuk Oil Pool. My 7 name's Brett Huber, I'm the Public Member of the 8 Commission and the Chairman. With me is Jessie 9 Chmielowski, Commissioner and Petroleum Engineer, 10 Commissioner Greg Wilson, Petroleum Geologist. They 11 occupy the seats designated for their discipline. 12 Today's meeting is being held in person and via 13 Microsoft Teams at 333 West 7th Avenue. For those on 14 Teams please be mindful of any background noise and 15 make sure if you could that you're muted when you're 16 not testifying. 17 If you require any special accommodation to 18 participate in the hearing today you can contact 19 Samantha Coldiron, she will help you. She can be 20 reached at 793-1223 or through the Teams' chat icon. 21 If you have special accommodations that are necessary 22 please let Sam know and we'll do our best to 23 accommodate you. 24 Sam will also be recording today's hearing. So 25 upon completion and preparation of the transcript AOGCC 6/4/2024 ITMO: APPLICATION OF OIL SEARCH AK FOR AN AREA INJECTION DOCKET No. AIO-24-013 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 Page 4 1 anyone desiring a copy will be able to obtain it by 2 contacting Computer Matrix. 3 Today's hearing is being held in accordance 4 with Alaska statute 44.62 and 20 AAC 25.540 of the 5 Alaska Administrative Code. Notice of the hearing was 6 published on the State of Alaska Online Notices website 7 as well as AOGCC's website and was sent through our 8 email listserv on April 30th, 2024. Notice is also 9 published in a statewide newspaper, the Anchorage Daily 10 News, on May 1st, 2024. To date AOGCC has received no 11 public comments on the matter. 12 So just a quick background on the injection 13 order. The AOGCC approves injection orders for several 14 purposes, including enhanced oil recovery, storage and 15 disposal either on an individual well or area wide 16 basis for Alaska -- in Alaska. EOR injection orders 17 establish rules for conducting operations that are 18 intended to increase the amount of oil or gas that 19 could be recovered from a pool by one or more of the 20 following mechanisms, maintaining reservoir energy, 21 sweeping oil through the reservoir into production well 22 or modifying the properties of the oil to make it more 23 mobile. This is consistent with the portion of AOGCC's 24 mission that seeks to promote greater ultimate 25 recovery. AOGCC 6/4/2024 ITMO: APPLICATION OF OIL SEARCH AK FOR AN AREA INJECTION DOCKET No. AIO-24-013 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 Page 5 1 At the close of today's hearing the AOGCC will 2 review the information presented today, any additional 3 written comments received before the record's closed, 4 any additional information requested from the operator 5 by Commissioners during this hearing. And upon 6 completion of that review under deliberations the 7 Commission expects to issue a written decision 8 regarding the application to establish an area 9 injection order for the Nanushuk Oil Pool. 10 Questions of the presenters today will come 11 from myself or Commissioner Chmielowski or Commissioner 12 Wilson. However should a member of the public or the 13 audience have a question that they desire to be asked 14 please submit that question in writing to Samantha. 15 You can send it in via Teams' chat or email as well. 16 She'll provide the questions to the Commissioners for 17 review and if we believe the question will help in our 18 deliberations or bring information to the public -- to 19 the public we will ask that question. In either case 20 the question will be added to the record of today's 21 hearing. 22 I should note we might take a number of breaks 23 during the hearing today should we decide we need to 24 consult with each other or confer with Staff. That 25 break helps us to make sure that we've covered all the AOGCC 6/4/2024 ITMO: APPLICATION OF OIL SEARCH AK FOR AN AREA INJECTION DOCKET No. AIO-24-013 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 Page 6 1 relevant subjects and that we've made sure we've got 2 everything on the record and that we're providing the 3 most complete information to the public. 4 So today we will begin today's hearing with the 5 presentation from Oil Search as the operator seeking 6 this area injection order. Representatives from Oil 7 Search, I see you're all there. Are you ready to 8 introduce yourselves, please, your names and job titles 9 clearly for the record, please. 10 MR. NOLL: I'm Christian Noll, Senior GSI 11 Manager at Oil Search Santos. 12 MR. BOND: Andy Bond, Senior Subsurface 13 Engineering Manager at Santos. 14 MR. TERPACK: Rob Terpack, Senior Drilling 15 Manager for Santos. 16 MR. JONES: Tim Jones, Land and Units Manager 17 at Santos Oil Search. And you may hear us refer to us 18 today either by our operator name which is Oil Search 19 Alaska or by Santos which is our parent company. 20 CHAIRMAN HUBER: Excellent, gentlemen, I 21 appreciate that. And you understand now that you need 22 to key the microphone for an on button, speak directly 23 into it and then key it when you're done. Also it 24 would be helpful if you could identify yourselves 25 individually as we're trading from speakers just to AOGCC 6/4/2024 ITMO: APPLICATION OF OIL SEARCH AK FOR AN AREA INJECTION DOCKET No. AIO-24-013 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 Page 7 1 make sure that we capture it for the public record and 2 also on our transcripts. 3 At this point I'd like to ask you gentlemen if 4 you all want to be considered experts in your testimony 5 for today and if so if you could just briefly recount 6 name and credentials for that expert testimony, please. 7 MR. BOND: So Andy Bond, again Senior 8 Subsurface Engineering Manager for Santos. I've been 9 working Alaska for 37 years with various operators 10 across the entire North Slope. I would like to be 11 considered as an expert in reservoir engineering, 12 production engineering and stimulation. 13 CHAIRMAN HUBER: Thank you. Any others today, 14 gentlemen? 15 MR. NOLL: Christian Noll, Senior Geoscience 16 Manager, 26 years in industry, four of those here in 17 Alaska. I'm seeking to be an expert witness in 18 geoscience. 19 CHAIRMAN HUBER: Excellent. 20 MR. TERPACK: Rob Terpack, Senior Drilling 21 Engineer, Engineering Manager at Santos. Thirty-five 22 years in the industry, 24 years in Alaska. Seeking 23 expert in joint. 24 CHAIRMAN HUBER: Thank you, gentlemen. 25 Commissioner Chmielowski, Commissioner Wilson, do the AOGCC 6/4/2024 ITMO: APPLICATION OF OIL SEARCH AK FOR AN AREA INJECTION DOCKET No. AIO-24-013 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 Page 8 1 credentials meet your desired level? 2 COMMISSIONER CHMIELOWSKI: I have no 3 objections. 4 COMMISSIONER WILSON: No objections from me. 5 CHAIRMAN HUBER: Hearing no objections and 6 after that we will recognize the witnesses that 7 identified themselves as expert and we'll now swear in 8 the witnesses today. Would you all please raise your 9 right hand and respond. 10 (Oath administered) 11 IN UNISON: I do. 12 CHAIRMAN HUBER: Let the record show that all 13 the witnesses answered in the affirmative. 14 And, gentlemen, with that -- unless, 15 Commissioners, do you have anything to add before we 16 begin the presentation from Oil Search, Commissioner 17 Wilson, Commissioner Chmielowski. 18 COMMISSIONER WILSON: I'm ready. 19 COMMISSIONER CHMIELOWSKI: Nope. 20 CHAIRMAN HUBER: Again, gentlemen, I don't know 21 who's going to lead off, make sure you recognize 22 yourselves as you change speakers and if you could also 23 refer to the slide numbers that would be helpful for 24 our committee record or hearing record as well. 25 Thank you. AOGCC 6/4/2024 ITMO: APPLICATION OF OIL SEARCH AK FOR AN AREA INJECTION DOCKET No. AIO-24-013 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 Page 9 1 ANDY BOND 2 previously sworn, called as a witness on behalf of Oil 3 Search Alaska, testified as follows. 4 MR. BOND: All right. Good morning. Andy Bond 5 again. We're here in support of our area wide 6 injection order application for the Nanushuk Oil Pool. 7 Here's our planned agenda for the day. I'll give a 8 brief introduction and then I'll hand over to Tim 9 Jones, our Land Manager, to discuss the ownership and 10 development area. Then Christian will go over a 11 geoscience overview for you and then I'll come back and 12 give the overview of the planned operations and Rob 13 Terpack will wrap up with well construction. 14 Again here's our biographies showing our 15 background information. 16 All right. I'm going to hand off to Tim. 17 TIM JONES 18 previously sworn, called as a witness on behalf of Oil 19 Search Alaska, testified as follows. 20 MR. JONES: All right. Thank you, Andy. Once 21 again my name is Tim Jones, I'm the Land and Unit 22 Manager. The application that we are here in support 23 of today is for an area injection order for the 24 Nanushuk Oil Pool. The Nanushuk Oil Pool was 25 established by the Commission order 807 last year and AOGCC 6/4/2024 ITMO: APPLICATION OF OIL SEARCH AK FOR AN AREA INJECTION DOCKET No. AIO-24-013 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 Page 10 1 is contiguous with the Pikka Unit that we have formed 2 with the DNR and ASRC. And the area injection order 3 that we're requesting today is for the entire Nanushuk 4 Oil Pool, however there are some proposed wells that we 5 will show in a later slide in more detail. And we have 6 identified the surface owners within a quarter-mile 7 radius of those proposed injection wells as the Kuukpik 8 Corporation and the State of Alaska and the operators 9 within a quarter-mile radius of the proposed injection 10 wells as ConocoPhillips Alaska, Inc. and Oil Search 11 Alaska, LLC. 12 CHRISTIAN NOLL 13 previously sworn, called as a witness on behalf of Oil 14 Search Alaska, testified as follows. 15 MR. NOLL: Thanks, Tim. So this is Christian 16 Noll. I'll provide a brief summary of the Pikka Unit 17 geoscience. So I'm switching now to slide number 7. 18 Just by way of context and a little bit of a 19 refresh from the previous discussion on the Nanushuk 20 Oil Pool hearing, the Nanushuk Pool as you can see on 21 the right-hand side on the -- on the Qugruk 3 discovery 22 well type log, the pool itself is defined by the top 23 Nanushuk that you can see in red, to the top of the 24 Torok formation. The upper confining interval to the 25 pool is the CV formation which overlies the top AOGCC 6/4/2024 ITMO: APPLICATION OF OIL SEARCH AK FOR AN AREA INJECTION DOCKET No. AIO-24-013 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 Page 11 1 Nanushuk, it's around a thousand feet TVT of -- or up 2 to a thousand feet TVT of largely claystone dominated 3 mudstone deposits that represent the basinal deposits 4 of the Torok formation. So that provides an excellent 5 top seal to the Nanushuk Oil Pool. Likewise the lower 6 confining interval, roughly 250 feet TVT of mostly 7 claystone and -- and silty shale sequences within the 8 Torok formation itself which is essentially the basinal 9 equivalent of the subset sand in the Nanushuk 10 formation. 11 Switching now to slide number 8. Again just as 12 a refresh on the available data on the geoscience side, 13 there is a map of the Pikka Unit on the right-hand 14 side. It's actually a structure map of the top of the 15 Nanushuk 3 which is the main focus for the NDB 16 development interval. We have roughly 20 well 17 penetrations so we have an excellent appraisal dataset 18 that helps define not only the structural architecture, 19 but also helps us define the reservoir characterization 20 and flow test information. Three of those wells have 21 continuous whole core in excess of a thousand feet, in 22 particular the Pikka B wells to the south and the 23 Qugruk 8 well which lies directly within the NDB 24 development area. So that helps establish that 25 depositional setting and reservoir characterization AOGCC 6/4/2024 ITMO: APPLICATION OF OIL SEARCH AK FOR AN AREA INJECTION DOCKET No. AIO-24-013 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 Page 12 1 efforts. In addition to the continuous whole core we 2 have 10 wells with rotary sidewall cores, roughly 156 3 of those in total. In terms of the appraisal dataset 4 itself, nine wells with high definition image logs. 5 Those image logs and other y-line drive high definition 6 logs are crucial for our reservoir characterization 7 efforts again and five plus wells with successful flow 8 test data also. 9 COMMISSIONER WILSON: I do have sort of a 10 general question. You know, we met for the pool rules 11 last July and there's been considerable drilling since 12 then. And I was just curious if there's anything new 13 of significance that you've encountered in the drilling 14 including faulting and if so how that might, you know, 15 change the course of events at all? 16 MR. NOLL: Yeah, thanks, Greg. So this is 17 Christian. So we're -- as you know, we're active in 18 the Pikka phase 1 NDB area. So we've drilled a number 19 of wells since our last meeting. I -- it's -- I think 20 it's fair to say that the results are coming in as 21 expected, no great surprises, largely as expected in 22 terms of the stratigraphic architecture the amount of 23 net that we've encountered and also the structural 24 architecture. So coming in on depth as expected and 25 minimal faulting as expected. Pretty good fault AOGCC 6/4/2024 ITMO: APPLICATION OF OIL SEARCH AK FOR AN AREA INJECTION DOCKET No. AIO-24-013 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 Page 13 1 resolution on very good seismic datasets and largely 2 coming in as expected. 3 COMMISSIONER WILSON: Thank you. 4 MR. NOLL: So I'll switch now to slide number 5 9. Once again just to round out the geologic overview 6 you'll see a structure map on the right-hand side of 7 the slide, that's actually a structure map of the top 8 Nanushuk so immediately overlying this is the upper 9 confining interval of the CV formation. What you can 10 see across the bulk of the development area is the 11 structure is really quite flat, typically dipping at 12 one to two degrees towards the east or southeast so 13 very flat across the development area. We really only 14 image one large -- one -- one fault system, it's a -- 15 it's a basement reactivated, post-depositional fault 16 system that you can see in between the development 17 wells in blue and say the Pikka C location. As you can 18 see those faults which are actually part of the fjord 19 fault system are (indiscernible) in nature, typically 20 around 30 to 90 feet so it does not offset the 21 reservoir. And as you can see those faults are open 22 and provide -- don't provide great or any indication of 23 discontinuity from the southern area to the northern 24 area of the unit. So pretty open across that fjord 25 fault system. AOGCC 6/4/2024 ITMO: APPLICATION OF OIL SEARCH AK FOR AN AREA INJECTION DOCKET No. AIO-24-013 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 Page 14 1 The reservoir itself is deltaic. The shelfal 2 deposits that represent the top sands within the 3 Nanushuk, the trend is largely elongate parallel to the 4 north/northeast shelf margin orientation so long -- 5 elongate trying to form geometries parallel to that 6 shelf margin. Depth's typically around 3,900 feet to 7 4,250 feet within the Nanushuk 3 reservoir itself. 8 It's a combined structural and stratigraphic trap. So 9 largely a stratigraphic trap with enough dip, thinning 10 and pinch out to the west and of course the shelfal 11 termination which lends the sand, the top set sand, 12 onto the slope and becomes predominantly shale down 13 dip. Both lithologies define a very fine grain 14 interbedded sandstone, silt and clays within the target 15 interval. 16 Oil quality does vary. We do see 24 to 27 17 degree API in the southern portion of the field around 18 the Pikka B area to the south of the unit and typically 19 29 to 30 to 32 degree API within the development area 20 itself. Net pay averages 140 feet on average with 22 21 percent porosity and roughly 60 millidarcy in terms of 22 permeability with an average water saturation of 41 23 percent. 24 And if I switch now to slide number 10 you'll 25 see the same text on the left-hand side and I'm just AOGCC 6/4/2024 ITMO: APPLICATION OF OIL SEARCH AK FOR AN AREA INJECTION DOCKET No. AIO-24-013 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 Page 15 1 illustrating the -- once again the structural map at 2 the top of the development interval, the Nanushuk 3 max 3 flooding surface which defines the uppermost portion of 4 the Torok/Nanushuk 3 reservoir. Once again you can see 5 fairly flat, open structure dipping again at one to two 6 degrees to the east and southeast. Only one fault 7 system that -- that's mapped once again 30 to 90 feet 8 (indiscernible). These faults are not anticipated to 9 provide any significant discontinuity within the 10 northern portion of the NDB area. 11 And now switching to slide number 11, it's a 12 stratigraphic section that is oriented from A to A 13 prime. You can see on the structure map to the right- 14 hand side of the slide A is to the northwest, A prime 15 is to the southeast. So this is a dip oriented 16 stratigraphic section and we're illustrating the Fjord 17 3 well to the left, the Q3 well which is the discovery 18 well in the heart of the Nanushuk 3 (indiscernible). 19 And then stepping across the -- effectively across the 20 Nan 3 or the Nanushuk 3 shelf margin into the Colville 21 River 1 area. And you can very clearly see the 22 geometry of the progradational system, very thin to 23 fjord 3 and eventually thins to the west providing that 24 updip stratigraphic closure into the heart of the 25 Nanushuk 3 where we have around 200 feet of pay at the AOGCC 6/4/2024 ITMO: APPLICATION OF OIL SEARCH AK FOR AN AREA INJECTION DOCKET No. AIO-24-013 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 Page 16 1 Q3 location and the Qugruk 3 location. And then 2 minimal pay as we step over the slope and towards the 3 basinal portion of the system at Colville River 1. So 4 illustrates that geometry quite nicely. 5 That is it for me. I'll hand over to Andy. 6 MR. BOND: All right. Andy Bond again. I'm on 7 slide 13 here and I'm going to discuss the proposed 8 development. Again we have 41 Nanushuk development 9 plan -- wells planned for phase one. We have 10 alternating rows of injectors and producers in a line 11 drive pattern. My wells are oriented at 330 degrees 12 based on a lot of geomechanical work that we've done. 13 Our wells average about 6,000 foot as far as the 14 horizontal in the Nanushuk Reservoir and we're fracking 15 with nine to 12 fracks per lateral. We of course want 16 to get the frack height to link all the laminated 17 layers to maximize our sweep efficiency there. Our 18 interwell spacing is 1,800 feet and we plan to land 19 most of the wells approximately 60 feet below the top 20 of the Nanushuk Reservoir and that's really a key for 21 us to land this at the base of an amalgamated sand 22 there to improve fracture initiation as well as long 23 term connection between the fracture and the wellbore. 24 After we are completing operations we are flowing the 25 wells back to clean up and get back the load water. AOGCC 6/4/2024 ITMO: APPLICATION OF OIL SEARCH AK FOR AN AREA INJECTION DOCKET No. AIO-24-013 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 Page 17 1 Those fluids are being disposed of onsite into our 2 class I disposal well. And one thing we're going to 3 ask for later is the potential to store some of that 4 oil in existing wells rather than injecting it into the 5 disposal well once it's cleaned up to a minimum 6 standard. 7 Another key piece of information we plan to 8 collect here in July is an interwell pulse test. We'll 9 be pulsing in a -- in the B30 well and monitoring in an 10 offset well to the north one spacing distance away and 11 then a well to the south two spacing units away. And 12 that'll be a key piece of information for us to fully 13 analyze interwell connectivity and to further calibrate 14 our reservoir models. 15 COMMISSIONER CHMIELOWSKI: Mr. Bond, since 16 you've started drilling have there been any changes to 17 your drilling and completion strategy like interwell 18 spacing or anything like that? 19 MR. BOND: No, we are continuing on with the 20 1,800 foot spacing. Once we gather this pulse test 21 information that'll be a key piece of data that may 22 indicate we want to change spacing at some point in the 23 future. Likely as we move to the south the reservoir 24 properties improve, we get higher permeability, that 25 might be an area where we might increase spacing, but AOGCC 6/4/2024 ITMO: APPLICATION OF OIL SEARCH AK FOR AN AREA INJECTION DOCKET No. AIO-24-013 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 Page 18 1 right now we're very happy with our 1,800 foot well 2 spacing. 3 CHAIRMAN HUBER: May I add to that. So what I 4 heard Mr. Noll say as well was that your initial 5 thoughts of what your expectations of the field is 6 being proven now by your drilling program thus far, you 7 find a really good correlation? 8 MR. NOLL: That's correct. We entered the 9 drilling program with obviously a range of 10 expectations. The -- we carry a range of deterministic 11 geologic models that define our low emit and high case 12 and the results well and truly fall within that range 13 and largely as expected. 14 MR. BOND: All right. I'm now on slide 14. 15 This describes the fluid properties for the Nanushuk 3 16 reservoir. You can see in the lower left-hand corner 17 we've got the API gravity versus depth that Christian 18 discussed. We see a range from about 24 API all the 19 way up to 31 API. And then on the right-hand side 20 we've got the PBT results from the Q8 well, the Qugruk 21 8 well, and that's a pretty good representative well of 22 the fluid properties for the majority of the area we're 23 developing currently. About 29 degrees API fluid 24 velocity, that let two (indiscernible) in the reservoir 25 and our solution GOR ranges from about 350 to 450 again AOGCC 6/4/2024 ITMO: APPLICATION OF OIL SEARCH AK FOR AN AREA INJECTION DOCKET No. AIO-24-013 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 Page 19 1 across the field depending on where we are. 2 All right. As far as injection plans, we plan 3 to implement a WAG program where we'll be alternating 4 seawater injection with our indigenous return to gas. 5 It'll be a near miscible flood, we'll be miscible near 6 the injection point where we have higher pressure and 7 then we'll go non-miscible as the gas travels across. 8 We don't expect any issues with the seawater or 9 produced water we plan to inject into this reservoir. 10 We've done a number of studies for flow assurance to 11 ensure that. And as you'll see here in a moment we'll 12 talk about our new build seawater treatment plant which 13 has ultra filtration and sulfate removal to further 14 enhance the quality of the water we'll be injecting. 15 And one of the big benefits of that is we'll reduce the 16 amount of SRBs and therefore H2S and corrosion in 17 pipelines, souring of the reservoir, et. cetera. Again 18 we plan to reinject our solution gas as part of that 19 WAG program. It'll range anywhere from about 61 to 70 20 percent methane content within the heavier ends as well 21 to enhance that fluid for additional oil recovery. Our 22 liquid injection rates are expected to range from about 23 2,000 to 10,000 with most of the wells being choked at 24 about 8,000 barrels a day, that's our plan based on our 25 reservoir modeling to date. And our gas injection AOGCC 6/4/2024 ITMO: APPLICATION OF OIL SEARCH AK FOR AN AREA INJECTION DOCKET No. AIO-24-013 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 Page 20 1 rates will range from about 3 million to 15 million 2 cubic -- standard cubic feet a day of gas. Again 3 depending on reservoir quality, the amount of gas we're 4 producing and the amount of wells we have on gas 5 injection at any one time. And our long term goal is 6 to maintain a void replacement ratio of one. 7 As I mentioned earlier we are seeking 8 permission to be able to reinject produced oil from 9 these wells back into existing wells as a storage 10 mechanism. We're still evaluating that, but we'd like 11 that to be an option that's available to us if we deem 12 that's a way to enhance our operations and save some of 13 the oil that would otherwise be disposed. 14 And then the final bullet on this slide just 15 shows the laundry list of proposed fluids that we plan 16 to be able to inject over time just to make sure that 17 we're covered for all possible operations that occur -- 18 could occur during the life of the field. 19 Is there any questions on that before I 20 proceed? 21 COMMISSIONER WILSON: I was just curious, the 22 volume I guess of the reinjected oil. Do you have any 23 idea what kind of volumes you're talking about? 24 MR. BOND: I would imagine it would be on the 25 order of about 5,000 barrels for a particular flowback. AOGCC 6/4/2024 ITMO: APPLICATION OF OIL SEARCH AK FOR AN AREA INJECTION DOCKET No. AIO-24-013 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 Page 21 1 COMMISSIONER CHMIELOWSKI: Barrels per day? 2 MR. BOND: Barrels total. 3 COMMISSIONER CHMIELOWSKI: Barrels total. 4 Okay. 5 MR. BOND: Yeah. 6 COMMISSIONER CHMIELOWSKI: And this was..... 7 MR. BOND: And it..... 8 COMMISSIONER CHMIELOWSKI: Oh, go ahead. 9 MR. BOND: .....could range anywhere from a 10 couple thousand to 10,000, but I'm just speculating 11 about 5,000 barrels. 12 COMMISSIONER CHMIELOWSKI: And this came about 13 due to some conversations about what, truck metering 14 and trucking of oil to other locations; is that right? 15 MR. BOND: Well, so right now we are disposing 16 of all of it locally, we aren't having to truck it 17 offsite. So we certainly would like to not have to 18 truck fluids offsite and we'd like to be able to 19 preserve some of the oil. Just want it -- we want it 20 available as an option. 21 COMMISSIONER CHMIELOWSKI: Question about 22 produced water from the Colville and Kuparuk River 23 Unit. Is that like a contingency or does -- does that 24 -- do you have plans for that? 25 MR. BOND: Exactly. We're just trying to cover AOGCC 6/4/2024 ITMO: APPLICATION OF OIL SEARCH AK FOR AN AREA INJECTION DOCKET No. AIO-24-013 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 Page 22 1 our basis there. We don't plan to be able -- use that 2 fluid, but just wanted to make sure that we had that 3 option if it became available to us someday. 4 COMMISSIONER CHMIELOWSKI: Okay. And what is 5 the salinity range that you're looking for in that 6 produced water? 7 MR. BOND: So our -- that's a good question. I 8 don't know the exact value. Our indigenous water's 9 about 17,000 parts per million. So the produced water 10 itself would probably be in that same range. 11 COMMISSIONER CHMIELOWSKI: But too high or too 12 low could affect compatibility of fluids in the 13 reservoir, is that your thinking? 14 MR. BOND: Yeah. I mean, you certainly 15 wouldn't want to have freshwater going in. You know, 16 typically for our frack treatments for example using 4 17 percent KCL so we would certainly want to have 18 something in the order of 17,000 or thereabouts. 19 COMMISSIONER CHMIELOWSKI: And is the same true 20 for gas imported from outside the unit, is that a 21 contingency or a plan? 22 MR. BOND: Correct. Yes. 23 COMMISSIONER CHMIELOWSKI: Okay. 24 MR. BOND: We do plan to import gas for fuel, 25 but we do not at this point plan to import gas for AOGCC 6/4/2024 ITMO: APPLICATION OF OIL SEARCH AK FOR AN AREA INJECTION DOCKET No. AIO-24-013 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 Page 23 1 injection, but we would like to have that option at 2 some point in the future if that became available. 3 COMMISSIONER CHMIELOWSKI: Okay. So you do 4 have plans to import fuel gas? 5 MR. BOND: Yes. 6 COMMISSIONER CHMIELOWSKI: And do you have a 7 plan for metering that as a -- as a sales product from 8 another location? 9 MR. BOND: Yes. 10 COMMISSIONER CHMIELOWSKI: Okay. Thanks. 11 MR. BOND: All right. So here's some details 12 on our new build seawater treatment plant. This is 13 currently being built in Southeast Asia and the plan is 14 to float it around to Oliktok Point next summer. 15 During this past winter the graving dock at Oliktok 16 Point has been constructed and is ready to accept this 17 barge when it arrives next summer. Again this barge 18 will have approximately 100,000 barrels a day of 19 capacity and we'll be using ultrafiltration and sulfate 20 removal. So we'll have probably the cleanest seawater 21 that's ever been developed on the North Slope for 22 injection. Again we see that having significant 23 benefits to reduce pipeline corrosion, tubular 24 corrosion, prevent the introduction of SRBs and H2S 25 into the reservoir which will also reduce the amount of AOGCC 6/4/2024 ITMO: APPLICATION OF OIL SEARCH AK FOR AN AREA INJECTION DOCKET No. AIO-24-013 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 Page 24 1 barium sulfate potential. We have very low scaling 2 tendencies to start with, but this will further reduce 3 those scaling tendencies. And we've done a number of 4 third party studies again for flow assurance to confirm 5 these benefits. 6 One of the reasons we're wanting the 7 ultrafiltration is the Nanushuk Reservoir generally 8 does have small pore throats so we want to make sure we 9 reduce as many particles as we can to prevent any 10 formation plugging. The multi stage fracks greatly 11 assist us in that area, opens up a huge surface area to 12 reduce the potential for any wellbore plugging from any 13 particulates. 14 And then as I mentioned also we have our gas 15 EOR/WAG program planned. We'll have a capacity, I'll 16 show you here on the next slide, for about 40 million 17 cubic feet a day of gas injection. 18 COMMISSIONER CHMIELOWSKI: Remind me, do you 19 frack the injectors and the producers? 20 MR. BOND: Yes, we're fracking..... 21 COMMISSIONER CHMIELOWSKI: Yeah. 22 MR. BOND: .....each well..... 23 COMMISSIONER CHMIELOWSKI: Okay. 24 MR. BOND: .....yes. So here's a schematic 25 view on slide 17 of our enhanced oil recovery project. AOGCC 6/4/2024 ITMO: APPLICATION OF OIL SEARCH AK FOR AN AREA INJECTION DOCKET No. AIO-24-013 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 Page 25 1 Again we'll have capacity to inject up to 40 million 2 cubic feet a day of gas if we're producing sufficient 3 oil rates and gas rates to have that amount of gas 4 injection. As I mentioned you can see we have gas 5 import coming in from offsite for fuel gas. The fuel 6 gas and our produced gas will not mix together at all, 7 we'll keep those two systems separate. We do have the 8 ability to burn our own indigenous gas for fuel if at 9 some point we decided to stop importing fuel gas, but 10 right now we would prefer to save that rich, sweet, 11 indigenous gas for our enhanced recovery program. 12 All right. I'm going to shift gears here on 13 slide 18 and talk about fracture containment. What 14 you're looking at on the right-hand side is an output 15 from our stim plan fracture modeling software which is 16 an industry standard software used to model fracturing. 17 You can see that the -- our fracture is nicely 18 contained within the Nanushuk Reservoir. We have a 19 very good top seal and bottom seal as Christian 20 described. You can see the little dot there, I'll 21 point it out, this is our planned landing depth 22 approximately 60 feet below the top of the reservoir 23 and that seems to be an optimum location for us to get 24 the maximum frack height in order to link up all the 25 laminated layers and maximize our flood recovery here. AOGCC 6/4/2024 ITMO: APPLICATION OF OIL SEARCH AK FOR AN AREA INJECTION DOCKET No. AIO-24-013 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 Page 26 1 As far as our long term operations we plan to 2 operate the wells below frack pressure once we're on 3 water injection or gas injection. Our typical frack 4 gradients are in the .6 to .7 PSI per flit range. We 5 would like to get permission to be able to operate at a 6 maximum of .8 PSI per foot in case in some wells we do 7 need to increase the pressure to get sufficient 8 injection rates. But again that operating pressure 9 will still be below any fracturing pressure required to 10 fracture the top seal which we've got a good test at 11 .87 PSI per foot. 12 So any questions on fracturing or containment. 13 COMMISSIONER WILSON: I do have maybe a couple 14 of questions or just a little bit for clarity. Either 15 here or in the application, you know, we've seen I 16 guess the range on the gradients for the CV formation 17 and then also for the K3 seal using the same numbers, 18 the .77 to the .87. So I'm assuming it's a mix of shoe 19 tests both in the CV and in the K3 interval? 20 MR. BOND: That's correct. 21 COMMISSIONER WILSON: Yeah, okay. So that's 22 the range and they're the same in both. Then based on 23 the comments you just made, you know, occasionally 24 operating up to .8 PSI per foot and I guess the .77 was 25 from a FIT and not a leakoff. So you're kind of AOGCC 6/4/2024 ITMO: APPLICATION OF OIL SEARCH AK FOR AN AREA INJECTION DOCKET No. AIO-24-013 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 Page 27 1 financing there, I guess getting fairly close to your 2 fracturing the -- potentially fracturing your top 3 seal. 4 MR. BOND: Yeah, but I will say that when we're 5 fracturing with extremely high pressures at 40 barrels 6 a minute we're not getting much frack height beyond the 7 top of the reservoir. So we certainly don't anticipate 8 any containment issues when we'll be pumping at much 9 lower rates and much lower pressures on actual 10 operations. So yeah. Yes to your question. 11 COMMISSIONER WILSON: Yeah. No, I just wanted 12 to give you an opportunity for the record to..... 13 MR. BOND: Yeah. 14 COMMISSIONER WILSON: .....for clarity on that 15 one. 16 MR. BOND: Yeah. 17 COMMISSIONER WILSON: That's it on that one. 18 MR. BOND: Okay. Okay. As I mentioned we do 19 have one water sample that we collected from the 20 Nanushuk Reservoir and the Pikka B well. It was 21 collected about 600 feet below the top of the reservoir 22 and the salinity of this sample was about 17,000 PPM. 23 Again it had very low calcium and low barium 24 concentrations so it -- again that points us towards 25 relatively low scaling tendencies. Again by removing AOGCC 6/4/2024 ITMO: APPLICATION OF OIL SEARCH AK FOR AN AREA INJECTION DOCKET No. AIO-24-013 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 Page 28 1 the sulfate we should further eliminate the barium 2 sulfate potential issues. We do expect potentially 3 minor scaling issues at our -- like our surface 4 production heater where the process flow is heated up 5 to higher temperatures. So we'll need to use some 6 minor scale inhibitions on surface to prevent calcium 7 carbonate scaling on that location. 8 And then finally we'd like to get an aquifer 9 exemption. Of course we don't -- there's no identified 10 freshwater aquifers in our area. 11 COMMISSIONER WILSON: I do have a question 12 there also. In looking back to conservation order 807 13 it's stated in there that no contacts had been 14 encountered in the field. I was just curious, the 15 water sample in Pikka B at 4,784, the 17,000 PPM, was 16 that a wet sand, was that below an oil/water contact 17 or..... 18 MR. BOND: I think I'll defer to Christian on 19 that one if you don't..... 20 MR. NOLL: I don't have that sample in front of 21 me or at the forefront of my mind so I'd probably have 22 to take that question and report back to you actually. 23 COMMISSIONER WILSON: Yeah, it's not a issue, 24 it's a curiosity. But because of the earlier statement 25 that there were no oil/water contacts and then this AOGCC 6/4/2024 ITMO: APPLICATION OF OIL SEARCH AK FOR AN AREA INJECTION DOCKET No. AIO-24-013 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 Page 29 1 sounds like it's a water sample. So..... 2 MR. NOLL: Typically we see water saturation 3 increase with depth with degrading reservoir quality. 4 So yeah, that's the -- sort of the typical trend that 5 we do see within the top set sands. 6 COMMISSIONER WILSON: But in general the 7 earlier statement stands that there's not an oil/water 8 contact per se? 9 MR. NOLL: Correct. 10 MR. BOND: Yeah. 11 COMMISSIONER CHMIELOWSKI: So quick question. 12 You are planning to apply for an aquifer exemption or 13 you are not? 14 MR. BOND: Yes. 15 COMMISSIONER CHMIELOWSKI: You are. Okay. 16 MR. BOND: All right. And then slide 20 17 discusses the estimated incremental hydrocarbon 18 recovery from our enhanced recovery project. So you 19 can see we've got a range of volumes here. The first 20 line is original oil in place and then we've got it 21 broken out with primary recovery, primary recovery plus 22 waterflood only and then primary recovery plus 23 waterflood plus WAG gas injection. So you can see the 24 range of recoveries that we expect. This again is for 25 the entire Pikka Unit whereas right now we're only AOGCC 6/4/2024 ITMO: APPLICATION OF OIL SEARCH AK FOR AN AREA INJECTION DOCKET No. AIO-24-013 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 Page 30 1 developing a central portion of it, but this covers the 2 entire unit. 3 COMMISSIONER WILSON: And I don't recall off 4 the top of my head, but these are the same numbers that 5 were in the pool..... 6 MR. BOND: They're identical. 7 COMMISSIONER WILSON: .....application? 8 MR. BOND: Yes. 9 COMMISSIONER CHMIELOWSKI: I've a quick 10 question again about injection fluids. Maybe we could 11 go back to slide 17. Where would -- what are the 12 potential sources of gas from outside the unit, where 13 would imported gas come from? 14 MR. BOND: So could come from the Kuparuk River 15 Unit, the Prudhoe Bay Unit, Colville River Unit. Those 16 are probably the primary sources. 17 COMMISSIONER CHMIELOWSKI: And you have -- you say 18 you have a line set up to import gas and..... 19 MR. BOND: Yes, we do. 20 COMMISSIONER CHMIELOWSKI: .....where is that 21 coming from, it's from all of those or..... 22 MR. BOND: I guess I'll defer to Tim. Sorry. 23 MR. JONES: So the gasline will tie in the 24 Kuparuk River Unit. 25 COMMISSIONER CHMIELOWSKI: Kuparuk River Unit. AOGCC 6/4/2024 ITMO: APPLICATION OF OIL SEARCH AK FOR AN AREA INJECTION DOCKET No. AIO-24-013 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 Page 31 1 Okay. So that's the one you planned for, but 2 contingencies for the others? 3 MR. BOND: Right. 4 COMMISSIONER CHMIELOWSKI: And you talked about 5 contingencies of importing produced water and other 6 gasses. What are -- what circumstances would make you 7 enact the contingency plan? 8 MR. BOND: I suppose if we needed additional 9 fluids beyond our capacity of our seawater treatment 10 plant for example, if we have less gas available over 11 time. I think those would be the main contingencies. 12 We don't have any flowlines set up for -- to provide 13 any of those fluids at this point in time so it would 14 require an additional project in the future. Again 15 it's just a contingency that we probably will not 16 exercise. 17 COMMISSIONER CHMIELOWSKI: So it's just to keep 18 your voidage? 19 MR. BOND: Yes. 20 COMMISSIONER CHMIELOWSKI: Is there any 21 anticipation that the seawater treatment plant wouldn't 22 be enough? 23 MR. BOND: Not at this point in time. 24 COMMISSIONER CHMIELOWSKI: Not at this point. 25 Okay. Thank you. AOGCC 6/4/2024 ITMO: APPLICATION OF OIL SEARCH AK FOR AN AREA INJECTION DOCKET No. AIO-24-013 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 Page 32 1 MR. BOND: All right. Any further questions 2 before we hand over to drilling? 3 (No comments) 4 ROB TERPACK 5 called as a witness on behalf of Oil Search Alaska, 6 testified as follows. 7 MR. TERPACK: Morning. Rob Terpack. I'll 8 cover the well construction this morning. I'm on slide 9 22. 10 Well, on the right wellbore diagram of a 11 typical injector all of our -- most of our wells will 12 be with 13 and three-eights surface casing followed by 13 nine and five-eights intermediate casing within the 14 lower completion going into Nan. As the wells get 15 longer and longer we'll have to add a second 16 intermediate string, that's not depicted in this 17 diagram, but we'll roughly split that intermediate hole 18 in half and nine and five-eights halfway down and then 19 seven inch to top set the reservoir. 20 We're using the latest drilling -- directional 21 drilling techniques. Our hole angles with these step 22 outs, hole angles range from 40 up to 85 degrees on the 23 longest wells. The intermediate casing shoe will be 24 set just at or just above the Nanushuk 3. We'll cement 25 per the regulations 250 feet TVD above the Nanushuk to AOGCC 6/4/2024 ITMO: APPLICATION OF OIL SEARCH AK FOR AN AREA INJECTION DOCKET No. AIO-24-013 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 Page 33 1 provide isolation and containment. Then we'll log that 2 cement prior to any stimulation or injection 3 activities. 4 I discussed the additional intermediate string 5 there as needed as the wells get longer and longer. 6 Cementing of the intermediate slash production will 7 comply with the 20 AAC 25.030, including the tulavac 8 (ph) as when we have the significant hydrocarbon gas 9 present. The lower completion will be uncemented, it 10 consists of mechanical isolation packers and frack 11 sleeves. As Andy said those are roughly 6,000 foot 12 long in each horizontal well. The upper completion 13 will sting into the lower, it will all be a four and a 14 half monobore, completion jewelry right now is downhole 15 pressure and temperature gauge on the injectors. After 16 upper and lower completions are set and tested the 17 tubing and the tubing casing annulus of each injector 18 will be tested and monitored in accordance with 20 ACC 19 25.412. 20 COMMISSIONER CHMIELOWSKI: I have a question. 21 So on this page you say that the tulavac would be 22 cemented when gas is present, but I think in your 23 application you have a rule two that says cementing the 24 tulavac as required by the pool rules. So which one 25 are you proposing? AOGCC 6/4/2024 ITMO: APPLICATION OF OIL SEARCH AK FOR AN AREA INJECTION DOCKET No. AIO-24-013 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 Page 34 1 MR. TERPACK: The pool rules say cement the 2 tulavac and our -- we have an amendment in there cement 3 the tulavac when significant hydrocarbons are present 4 amendment. 5 COMMISSIONER CHMIELOWSKI: So the plan would be 6 to follow the pool rules? 7 MR. TERPACK: Yeah. 8 COMMISSIONER CHMIELOWSKI: As those have been 9 done. Okay. Great. 10 MR. TERPACK: Yeah. 11 COMMISSIONER CHMIELOWSKI: Thanks. 12 MR. TERPACK: That's all I have on well 13 construction. 14 CHAIRMAN HUBER: Thank you, gentlemen. 15 Additional testimony or presentation. 16 MR. BOND: That wraps up our planned statements 17 for now. 18 COMMISSIONER CHMIELOWSKI: I had another 19 question. Actually I think it's the same slide 17. 20 You show the Alpine before the Nanushuk and I was just 21 curious if there's anything you can speak to about 22 plans for the Alpine? 23 MR. BOND: So we do have some small Alpine C 24 accumulation sin our unit. We do plan to come to you 25 at some point in the future for pool rules and an area AOGCC 6/4/2024 ITMO: APPLICATION OF OIL SEARCH AK FOR AN AREA INJECTION DOCKET No. AIO-24-013 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 Page 35 1 wide injection order for that unit. Right now with our 2 current NDB drillsite phase one we have one producing 3 well and one injection well planned for that Alpine, 4 but it's quite a bit later in our drilling schedule so 5 we'll come to you at the appropriate time for those. 6 COMMISSIONER CHMIELOWSKI: Okay. But you might 7 access Alpine from the same location? 8 MR. BOND: Correct. 9 COMMISSIONER CHMIELOWSKI: Yeah. 10 MR. BOND: Yeah. 11 COMMISSIONER CHMIELOWSKI: Okay. Thank you. 12 CHAIRMAN HUBER: Additional questions, 13 Commissioners. 14 COMMISSIONER WILSON: I guess to follow-up on 15 that Alpine question, the fluids from the Alpine 16 interval would be included in this present discussion 17 then for reinjection? 18 MR. BOND: Yes. Exactly. Yes. 19 COMMISSIONER CHMIELOWSKI: I guess maybe you 20 can talk about this. When do you plan to start 21 injection operations? 22 MR. BOND: So our base plan right now is to 23 have our facilities in place and ready in approximately 24 May of 2026. 25 COMMISSIONER CHMIELOWSKI: May of 2026. Okay. AOGCC 6/4/2024 ITMO: APPLICATION OF OIL SEARCH AK FOR AN AREA INJECTION DOCKET No. AIO-24-013 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 Page 36 1 That's all I have for now. 2 CHAIRMAN HUBER: Commissioner Wilson. 3 COMMISSIONER WILSON: That's all I have for 4 now. 5 CHAIRMAN HUBER: Commissioners, would you like 6 us to take a brief break so we can confer with Staff? 7 COMMISSIONER CHMIELOWSKI: Yes. 8 CHAIRMAN HUBER: We're going to go ahead and go 9 off record. We'll take a break. It's 20 minutes to 10 11:00 by the wall clock now. We'll come back in at 11 11:00 o'clock and look forward to seeing you all back 12 at that time. 13 Thank you. 14 (Off record) 15 (On record - 10:58 a.m.) 16 CHAIRMAN HUBER: 10:58 on my watch, a little 17 bit short of 11:00 on the wall clock. But Sam has just 18 informed me that we had nobody drop off except for an 19 AOGCC employee during the break. So I don't think that 20 we're starting without giving anybody in the public 21 notice. Let's go ahead and take just a couple minutes 22 to make sure that if anybody from the public want to 23 sign on and testify that they have that opportunity. 24 Again a call for members of the public that 25 wish to provide testimony on the area injection order AOGCC 6/4/2024 ITMO: APPLICATION OF OIL SEARCH AK FOR AN AREA INJECTION DOCKET No. AIO-24-013 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 Page 37 1 before the Commission today. Anybody online from the 2 public that wishes to testify. We'll give you 60 3 seconds to unmute, that's a star, six on your phone to 4 unmute. Also known as the longest 60 seconds of 5 anybody's day. 6 (No comments) 7 CHAIRMAN HUBER: Has anybody else joined us, 8 Sam, or do we have the same folks online? 9 MS. COLDIRON: Same folks. 10 CHAIRMAN HUBER: Okay. Hearing no interest in 11 participation online we'll go to the room. Is there 12 anybody today in the room that would like to provide 13 public testimony before the Commission. 14 (No comments) 15 CHAIRMAN HUBER: Going once. Going twice. We 16 have nobody signed up here in the room. We have 17 allowed an opportunity for those online to unmute and 18 testify. One more call for anybody online. 19 (No comments) 20 CHAIRMAN HUBER: Apparently that concludes our 21 public testimony presentation or portion of today's 22 hearing with nobody participating from the public. 23 We'll go back to the Commissioners to see if there's 24 some additional questions after follow-up with Staff, 25 Commissioner Wilson. AOGCC 6/4/2024 ITMO: APPLICATION OF OIL SEARCH AK FOR AN AREA INJECTION DOCKET No. AIO-24-013 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 Page 38 1 COMMISSIONER WILSON: Yes. So we had a little 2 bit of discussion about your fracture gradients out of 3 the room and two issues. I guess one is it was 4 mentioned there's a thousand feet of continuous core 5 and just curious do you know if the top seal was cored 6 anywhere? 7 MR. NOLL: We did not core the top seal to the 8 Nanushuk 3. So we cored within the uppermost 9 transgressive sequence track, but not the absolute top 10 seal of that section, we've not -- we've not cored the 11 max flood surface. 12 COMMISSIONER WILSON: Okay. And -- gotcha. 13 CHAIRMAN HUBER: For the record that was Mr. 14 Noll. 15 COMMISSIONER WILSON: And then a second 16 question regarding your fracture gradients. There was 17 a possible recollection of a leakoff test that was 13 18 something or equating to about a .7 PSI per foot. But 19 it's something we would have to go back and check. And 20 so we're asking that the record remain open through the 21 end of the week and request that a table of the leakoff 22 tests and the data that has gone into the range for the 23 fracture gradients.f 24 MR. BOND: Okay. So you're talking about the -- 25 our existing well that we've just recently drilled or AOGCC 6/4/2024 ITMO: APPLICATION OF OIL SEARCH AK FOR AN AREA INJECTION DOCKET No. AIO-24-013 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 Page 39 1 everything available in the unit or..... 2 COMMISSIONER WILSON: It would be the data 3 that's gone into the fracture gradients that you're 4 proposing here. 5 MR. BOND: Yeah. Okay. All right. 6 CHAIRMAN HUBER: Do you have clarity on the 7 information that we're seeking, gentlemen? 8 MR. BOND: Yes. 9 CHAIRMAN HUBER: Great. Commissioner 10 Chmielowski, anything from you. 11 COMMISSIONER CHMIELOWSKI: Yes, are you 12 planning to do more testing to better understand your 13 fracture gradients? 14 MR. BOND: Not at this point in time, no. 15 COMMISSIONER CHMIELOWSKI: Okay. And you 16 mentioned applying for an aquifer exemption. So that -- 17 just to make sure you're aware that requires a 18 separate application and public notice or it can be 19 applied for through the EPA. You could consider 20 talking with AOGCC Staff about whether or not that's 21 necessary. 22 MR. BOND: Okay. That sounds good. 23 COMMISSIONER CHMIELOWSKI: Okay. Thank you. 24 Oh, I had one more thing. You know, part of this 25 application and order requires notification of parties AOGCC 6/4/2024 ITMO: APPLICATION OF OIL SEARCH AK FOR AN AREA INJECTION DOCKET No. AIO-24-013 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 Page 40 1 in an affected area. And I believe from your 2 presentation you notified parties within the radius of 3 the current wells, but, you know, the area injection 4 would include a larger area. Is there any difference 5 in notification for a larger area for the area 6 injection order versus what you've currently drilled so 7 far? 8 MR. JONES: So there are a couple of additional 9 -- sorry, this is Tim Jones again. There are a couple 10 additional surface owners, small Native allotments in 11 the larger area, but not within the immediate area of 12 the wells. So that is -- that's something that we can 13 make additional notification if necessary. 14 COMMISSIONER CHMIELOWSKI: Okay. I'm just 15 going to look at Dave and do we need to do anything 16 with that? 17 CHAIRMAN HUBER: Go off the record for just a 18 quick second. 19 (Off record) 20 (On record) 21 COMMISSIONER CHMIELOWSKI: So we're back on the 22 record talking about the notification for affected 23 parties. And it sounds as though we can issue an area 24 injection order for the immediate area of interest for 25 you and expand it later once notification to additional AOGCC 6/4/2024 ITMO: APPLICATION OF OIL SEARCH AK FOR AN AREA INJECTION DOCKET No. AIO-24-013 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 Page 41 1 parties has taken place or since you have time we could 2 consider another notification period. And, you know, 3 let's -- you could let us know what you prefer. Do you 4 have a preference or..... 5 MR. JONES: Let us take that back and then 6 we'll be back in touch here shortly. 7 COMMISSIONER CHMIELOWSKI: Great. I think 8 we're keeping the record open until close of business 9 Friday. So that, you know, hopefully will give you 10 time to think about it. 11 MR. JONES: Okay. Thank you. 12 CHAIRMAN HUBER: All right. Thank you. That's 13 all I have. 14 COMMISSIONER WILSON: That's all I have. 15 CHAIRMAN HUBER: Again thanks for everybody who 16 showed interest today and came out and participated. 17 Oil Search, appreciate your presentation and the 18 application. We will hold the record on this topic 19 open until the close of business on Friday. You're 20 going to bring back a table with some leakoff testing 21 for us and also an answer on how you'd like to deal 22 with the area injection order. It'll give you a chance 23 to confer with Staff on the -- on the salinity and 24 aquifer exemption potential needs as well. 25 Hearing no additional business to come before AOGCC 6/4/2024 ITMO: APPLICATION OF OIL SEARCH AK FOR AN AREA INJECTION DOCKET No. AIO-24-013 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 Page 42 1 the Commission this hearing is adjourned at 11:05 a.m. 2 (Off record - 11:05 a.m.) 3 (END OF PROCEEDINGS) 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 AOGCC 6/4/2024 ITMO: APPLICATION OF OIL SEARCH AK FOR AN AREA INJECTION DOCKET No. AIO-24-013 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 Page 43 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. OTH-17-007 was transcribed to the best of our 8 ability; 9 IN WITNESS WHEREOF I have hereunto set my hand 10 and affixed my seal this 3rd day of July 2024. 11 12 __________________________________ Salena A. Hile 13 Notary Public, State of Alaska My Commission Expires: 09/16/2026 14 15 16 17 18 19 20 21 22 23 24 25 Area Injection Order ApplicationNanushuk Oil Pool04 June 20241NANUSHUK AIO 2AgendaPikka Unit AIO ApplicationSpeakerTimeSubjectAndy Bond5 minPresentation IntroductionTim Jones5 min1. Ownership & Development AreaChristian Noll10 min2. Geoscience Overview- Nanushuk Formation & Confining LayersAndy Bond20 min3. Proposed operation- Development Plan- Injection Fluids & Properties- Fracture information- Projected recoveryRob Tirpack10 min4. Well Construction- Injection wells & Mechanical integrityNANUSHUK AIO 3Presenter BiographiesNANUSHUK AIOTim Jones• Santos Alaska• Land and Unit Manager• Registered Professional Landman• 17 years industry experience, all in AlaskaRob Tirpack• Santos Alaska• Senior Drilling Manager• BS Petroleum Engineering, Marietta College• 35 years industry experience, including 24 years in Alaska• Expert Witness: Drilling EngineeringChristian Noll• Santos Alaska• Senior Geoscience Manager• PhD Geology, Monash University• 26 years industry experience, including 4 years in Alaska• Expert Witness: GeoscienceAndy Bond• Santos Alaska• Senior Subsurface Engineering Manager• BS Petroleum Engineering, Colorado School of Mines• 37 years industry experience, all in Alaska(Kuparuk, Prudhoe, Oooguruk, Exploration)• Expert Witness: Stimulation, Res & Prod Eng PikkaOwnership & Development AreaTim Jones4NANUSHUK AIO 5Nanushuk Oil Pool/Injection AreaNANUSHUK AIOOwnership and Development Area+Nanushuk Oil Pool established by CO 807 is co-incident with Pikka Unit+Santos, through its subsidiary Oil Search (Alaska), LLC, is Operator and 51% working interest owner of the Pikka Unit; Repsol E&P USA LLC owns the remaining 49% working interest+Surface owners within a ¼ mile radius of the proposed injection wells are:─Kuukpik Corporation ─the State of Alaska +Operators within a ¼ mile radius of the proposed injection wells are:─ConocoPhillips Alaska, Inc ─Oil Search (Alaska), LLCNanushuk Oil Pool PikkaGeoscience OverviewChristian Noll6NANUSHUK AIO 7Nanushuk Oil Pool DefinitionNanushuk Oil PoolTop NanushukTop Torok FmTop NT3Upper Confining Interval – Seabee FormationLithologic Description:Thick claystone-dominated unit which represents the distal deep-water slope and basinal deposits of Tuluvak topset (shelfal) reservoir sandstoneFracture gradient:14.9-16.8ppgDepth & Thickness:3175 ft MD/2830 ft TVDSS, ~1000 ft TVTLower Confining Interval – Torok FormationLithologic Description:Dominantly comprised of thick claystone & silty-shale sequencesFracture gradient:16.0-17.0ppgDepth & Thickness:5200 MD/5135 TVDSS, ~250ft TVTNANUSHUK AIOSeabee Fm 8Pikka Exploration & Appraisal DataIntegrated Reservoir Characterization from TeraMerge 3D Seismic, Appraisal Well Logs & Whole Core tuned to Flow Test results+Subsurface characterization is built upon robust appraisal dataset across the Pikka Unit and adjacent areas:─20+ well penetrations─3+ wells with continuous core: 1,084 ft─10 wells with RSWCs (156 in total)─9 wells with high-definition image logs─5+ wells with successful flow test dataOverviewNanushuk Exploration & Appraisal DataPikka B / B ST1 8 (Oil Search 2019)High Res Wireline / LWDLogs780’ Whole CoreSide wall coresCoreSingle Frac Production TestPeak Rate 2,800 BOPDTestPikka C / C ST1 (Oil Search 2019)High Res Wireline / LWDLogsSide wall coresCoreHorizontal 6 stage FracProduction TestPeak Rate 2,000 BOPDTestFiord 2 & 3 (ARCO 1994 /1995)Low Res LWD/WLLogsSide wall coresCoreQugruk 7 (Repsol 2014)Low Res LWDLogsProduction TestPeak Rate: unstableAverage Rate 24 BOPDTestQugruk 3 (Repsol 2013)High Res WirelineLogsSide wall coresCoreQugruk 8 (Repsol 2015)High Res WirelineLogs240’ Whole CoreSide wall coresCoreSingle Frac Production TestPeak Rate 2,000 BOPDTestQugruk 9/9A (Repsol 2015)High Res WirelineLogsSide wall coresCoreQugruk 1 (Repsol 2013)Low Res LWD/WLLogsSide wall coresCoreQugruk 301 (Repsol 2015)Low Res LWDLogsHorizontal 6 stage Frac Production TestPeak Rate 3,900BOPDTestNANUSHUK AIO 9+Depositional Setting: deltaic shelfal deposits representing the topset equivalent of deeper water shale-dominated Torok Fm (deposition from overall west to east prograding clinoform system with wave reworking along the shelf)+Trend: Elongate reservoir geometry associated with NNE shelf margin orientation +Depth: 3900 – 4250ft SSTVD+Trap: combined structural & stratigraphic trap (updip thinning to west and shelfal termination to shale downdip). Robust topsealfrom overlying Seabee Formation, and significant internal top seals for each major clinothem+Lithology: fine to very fine grained interbedded sandstone, siltstone and claystone+Oil quality: 24- 30° API oil gravity+Net pay: 140 ft average+Porosity: 22% average+Permeability: 60 mD average+Water Saturation: 41% averageGeology Overview – Pikka Nanushuk 3 Top Nanushuk IntersectionExploration / Appraisal WellsExisting Pikka Dev WellsPlanned Pikka Dev WellsRoads / InfrastructureGeologic Depth Surface:Top NanushukC.I. 25 ftNANUSHUK AIO 10+Depositional Setting: deltaic shelfal deposits representing the topset equivalent of deeper water shale-dominated Torok Fm (deposition from overall west to east prograding clinoform system with wave reworking along the shelf)+Trend: Elongate reservoir geometry associated with NNE shelf margin orientation +Depth: 3900 – 4250ft SSTVD+Trap: combined structural & stratigraphic trap (updip thinning to west and shelfal termination to shale downdip). Robust topsealfrom overlying Seabee Formation, and significant internal top seals for each major clinothem+Lithology: fine to very fine grained interbedded sandstone, siltstone and claystone+Oil quality: 24- 30° API oil gravity+Net pay: 140 ft average+Porosity: 22% average+Permeability: 60 mD average+Water Saturation: 41% averageGeology Overview – Pikka Nanushuk 3 Geologic Depth Surface:Top NT3 MFSC.I. 100 ftTop NT3 MFS IntersectionExploration / Appraisal WellsExisting Pikka Dev WellsPlanned Pikka Dev WellsRoads / InfrastructureNANUSHUK AIO 11Dip-aligned Well Correlation: Pikka FieldAA’Seabee Fm.Upper NanushukNT3NT2NT1AA’ PikkaDescription of OperationAndy Bond12NANUSHUK AIO 13Location of Proposed Injection Wells and ¼ mile Offset Penetrations41 Nanushuk Development wells+Well Layout:─Alternating injector/producer pairs in line drive patterns to maximize areal sweep efficiency─Well orientation designed to achieve longitudinal fracs (330 deg)─~6,000 foot horizontal lateral sections with ~9-12 fracs per lateral to maximize vertical sweep efficiency+Well Spacing:─1,800’ inter-well spacing is planned+Depth Considerations:─Well trajectories will be placed ~60' below the top of the Nanushuk surface─Landing depth near base of amalgamated sand section to improve fracture initiation and long-term connection to wellbore+Completions:─Cleanup After Stimulation Operations─Fluids Disposal Onsite, Class I Well─Possible storage of oil into completed wells─Minimized Trucking / Transfers─Interwell pulse testing over single and double well spacing distances: Injection into Bi-30 late June/July 2024NDBNPFAA’NANUSHUK AIO 14Fluid Properties– Nanushuk 3 Reservoir+Pikka Phase 1 Fluid Properties from Qugruk 8 well represent average for new development+There is a compositional gradient in the vertical direction and some variability from North to South. (see API vs depth for north and south trends)+Samples to the north have higher C8-10 and samples to the south have a higher C30+ but really look and behave very similarly+Pikka Phase 1 will primarily produce from oil representative of samples from the North including wells Q3, Q301, Q8, Pikka C, Q9A-4800-4700-4600-4500-4400-4300-4200-4100-4000-3900-380020 22 24 26 28 30 32 34API gravity (contamination<5%, DL residual)PIKKA CQUGRUK 7PIKKA BPIKKA B ST1HORSESHOE 1QUGRUK 8QUGRUK 301QUGRUK 3QUGRUK 9AQUGRUK 1PIKKA C ST1South trend BOTNorth trend BOTAPI GravityDepth, ftFluid Property – Well Qugruk 8102Reservoir Temperature (deg F)29.3API Gravity (deg API)1561Saturation Pressure - BP (psia)2.04Fluid Viscosity (cp)0.88Fluid Density (g/cc)430Solution GOR (scf/bbl)1.177Formation Volume Factor (rb/stb)6.60e-6Oil Compressibility (1/psi)Mole %Weight %Component0.1640.210Nitrogen0.0800.160Carbon Dioxide0.0000.000Hydrogen Sulfide78.62257.685Methane11.29715.534Ethane5.54511.182Propane0.6981.856Iso-Butane1.3163.498N-Butane0.3061.009Iso-Pentane0.3000.991N-Pentane0.2721.073Hexanes0.5212.285Heptanes0.6002.930Octanes0.2271.258Nonanes0.0520.329Decanes PlusCompositional Analysis of Separator GasPikka B STSampling Conditions: 115 psia at 93 °FNANUSHUK AIO 15+No issues are expected with injection of either seawater or produced water/gas into the Nanushuk formation. Prior to water breakthrough, ultra filtered and sulfate removed seawater are planned for injection to maximize injectivity and reduce SRB/H2S potential.+Re-injected solution gas is expected to range between 61% and 70% methane over the life of the project and will be partially miscible at reservoir/injection conditions.+Liquid injection rates between 2,000 and 10,000 bbl/d and gas rates between 3 and 15 MMscf/day are expected at each injection well drilled for the project and will be managed to achieve and maintain a voidage replacement ratio of 1.+Santos is also seeking permission to re-inject produced oil from frac flowbacks into existing wells. NOP crude oil has an average API gravity of 29.1 with an estimated viscosity of 11-14cp (dead oil) at 100F reservoir temperature. Minor amounts of fines may still be present in dead oil recovered from tanks. The fines are small enough to travel through the propped fractures and will not affect injectivity over short injection periods due to massive fracture area created with multi-stage fractures.+Proposed allowable injection fluids include: Beaufort seawater sourced from the Pikka seawater treatment plant. Produced water from all present and yet -to -be defined oil pools within the Pikka, Colville, and Kuparuk River Units so long as produced water salinity is within range of that produced in offset Units. Lean and enriched gas from the Pikka Unit as well as gas imported from outside the Unit. 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 Nanushuk injection wells and are detailed in the application.Seawater with alternating gas-injection is proposed for enhanced recovery injection into the NOP. After water-breakthrough, individual well patterns may be swapped to produced water over time.Injection Fluid Analysis and Injection Rates NANUSHUK AIO 16Waterflood & Gas EOR PlannedNew Build STP Planned with Ultra Filtration and Sulfate Removal to Optimize Ultimate Recovery+OSA Seawater Treatment Plant (STP)–100 MBWPD capacity–Expandable to 165/200 MBWPD+Ultra-Filtration and Sulfate Removal improve long term Nanushuk recovery–Significant reduction in pipeline and tubular corrosion rates and products–Significant reduction in SRB’s and H2S in the reservoir and facilities–Further reduction of BaSO4 scaling tendencies –Third party studies confirm these benefits+Nanushuk reservoir has generally small pore throats–Susceptible to damage and blocking from particulates (filter cake formation)–Core studies completed which confirm this current understanding–Multi-stage frac completions will help overcome injection issues+Gas EOR WAG Program Planned–40 MMSCFD Gas Injection capacity planned–Provides incremental oil recovery over life of field –Plan to import fuel gas and use indigenous gas and NGL’s for floodOverviewSTPNANUSHUK AIO 17Enhanced Oil Recovery (EOR)NANUSHUK POOL RULESWater-alternating-gas (WAG) injection using enriched produced gasLower GLIR to 1.5 mmscfpdTotal (31.5 w/ 21 producers)Max GPR 90-31.5=58.5Max GIR 40 mmscfpd34.5 mmscfd40.5 mmscfdLatest estimate: 0.5 mmscfdGas Flow Diagram 18+Fracture modelling indicates that fractures are contained within the reservoir. Fracture modelling is done with StimPlan software heavily used in industry and validated with rock mechanical properties obtained from core, well logs, and appraisal well fracture tests.+The project will operate near the fracture gradient of the NOP reservoir sandstone which has demonstrated a fracture gradient of 0.6 to 0.7 psi/ft in the multiple exploration and development well fracture tests.+The flowing bottom hole pressure (FBHP) of the injection wells will be maintained within the strength of the K-3 seal. Analysis of available data in the seal interval yielded a fracture gradient as high as 0.87 psi/ft. The project will target an injection gradient of 0.7 psi/ft with an operating maximum at 0.8 psi/ft. This equates to a maximum FBHP of 3280 psig at the 4100' TVDss datum and 1476 psig at the wellhead for water injection.In the Pikka Unit area, the NOP is overlain by a 240 to 310 foot TVD claystone section with thin siltstone beds from the K-3 marker to the top NOP sandstone; part of the Cretaceous Nanushuk Group, here referred to as the K-3 Seal. The underlying confining zone beneath the NOP consists of 25-100 feet TVD of shaley slope mudstones and shales that thicken to the east/southeast.Fracture information and Maximum Injection Pressures 19Formation Water & Aquifer Exemption+A water sample was obtained from the Pikka B well at 4,784’ approximately 600’ below the top of the Nanushuk. The salinity of this water was found to be about 17,000 ppm with relatively low calcium and barium concentrations, ~80 ppm and 9 ppm respectively. No downhole scaling issues are expected with either seawater or produced water, and only minor scale inhibition is expected to be needed at the surface production heater.+Santos is not aware of any Aquifer Exemption Orders in the proposed area. Examination of well log data from exploratory wells in and near the proposed NOP confirms that there are no freshwater aquifers within the affected area that could serve as underground sources of drinking water. None of the subsequent oil pools and area injection orders in the adjacent units have found any freshwater aquifers to exist within the Colville River, Oooguruk, or Kuparuk unit areas.NANUSHUK AIO 20Incremental Hydrocarbon RecoveryNANUSHUK AIONOP waterflood will employ a horizontal well line drive pattern with the intent to convert to a Water Alternating Gas (“WAG”) orrich gas flood, to enhance oil recovery from the reservoir. Due to the highly laminated nature of the reservoir, all the wells (including the injectors) will be hydraulically fracture stimulated to enhance productivity and improve vertical injection sweep. PikkaWell ConstructionRob Tirpack21NANUSHUK AIO 22+Intermediate sections will be drilled utilizing the latest directional techniques from surface casing, encountering the top of the Nanushuk at 40-85 degree inclination.+Casing shoe will be set just above or just into the Nanushuk 3.+Casing will be cemented to 250’ TVD above top Nanushuk to provide isolation and containment of Nanushuk. Cement will be logged prior to stimulation or injection activities.+Depending on well length and inclination, one or more intermediate strings or two stage cement jobs may be deployed between the surface casing shoe and the top of the Nanushuk Reservoir, as determined by the required engineering design.+Cementing of intermediate/production casing will comply with all other requirements of 20 AAC 25.030, including portions of the Tuluvak when gas is present.+Lower completion will be an uncemented liner and consist of mechanical set isolation packers and frac sleeves.+Upper completion will sting into the lower completion to form a monoborecompletion. Completion jewelry may include a downhole pressure and temperature gauge. +The tubing/casing annulus pressure of each injection well will be tested and monitored in accordance with 20 ACC 25.412.Injection wellsTypical InjectorNANUSHUK AIO 23NANUSHUK AIOQUESTIONS? 24NANUSHUK AIO 2 Notice of Public Hearing STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION RE: Docket Numbers: AIO-24-013 By application dated April 16, 2024, Oil Search (Alaska), LLC (OSA), as the operator of the Pikka Unit (PU), requests that the Alaska Oil and Gas Conservation Commission (AOGCC) approve an Area Injection Order (AIO) to allow enhanced oil recovery (EOR) injection activities in the Nanushuk Oil Pool (NOP). Conservation Order 807 (CO 807), issued on July 20, 2023, defined the extents of the NOP and prescribed rules for its development. OSA is now seeking authorization to conduct an EOR injection project in the NOP in anticipation of beginning production from the PU in the coming years. The AOGCC approves injection orders for several purposes, including EOR, storage, and disposal either on an individual well or area wide basis in Alaska. EOR injection orders establish rules for conducting operations that are intended to increase the amount of oil or gas that could be recovered from a pool by one or more of the following mechanisms, maintain reservoir energy, sweeping oil through the reservoir to a production well, or modifying the properties of the oil to make it more mobile. This is consistent with the portion of the AOGCC’s mission that seeks to promote greater ultimate recovery. This notice does not contain all the information filed by OSA. To obtain more information, contact the AOGCC’s Special Assistant, Samantha Coldiron, at (907) 793-1223 or Samantha.Coldiron@alaska.gov. A public hearing on the matter has been scheduled for June 4, 2024, at 10:00 a.m. The hearing, which may be changed to full virtual, if necessary, will be held in the AOGCC hearing room located at 333 West 7th Avenue, Anchorage, AK 99501. The audio call-in information is (907) 202-7104 Conference ID: 204 118 862#. Anyone who wishes to participate remotely using MS Teams video conference should contact Ms. Coldiron at least two business days before the scheduled public hearing to request an invitation for the MS Teams. In addition, written comments regarding this application may be submitted to the AOGCC, at 333 west 7th Avenue, Anchorage, AK 99501 or Samantha.Coldiron@alaska.gov. Comments must be received no later than the conclusion of the June 4, 2024, hearing. If, because of a disability, special accommodations may be needed to comment or attend the hearing, contact Samantha Coldiron, at (907) 793-1223, no later than May 28, 2024. Brett W. Huber, Sr. Chair, Commissioner Brett W. Huber, Sr. Digitally signed by Brett W. Huber, Sr. Date: 2024.04.30 12:35:02 -08'00' Lisi Misa being first duly sworn on oath deposes and says that she is a representative of the An- chorage Daily News, a daily newspaper. That said newspaper has been approved by the Third Judicial Court, Anchorage, Alaska, and it now and has been published in the English language continually as a daily newspaper in Anchorage, Alaska, and it is now and during all said time was printed in an office maintained at the afore- said place of publication of said newspaper. That the annexed is a copy of an advertisement as it was published in regular issues (and not in supplemental form) of said newspaper on AFFIDAVIT OF PUBLICATION ______________________________________ Notary Public in and for The State of Alaska. Third Division Anchorage, Alaska MY COMMISSION EXPIRES ______________________________________ 05/01/2024 and that such newspaper was regularly distrib- uted to its subscribers during all of said period. That the full amount of the fee charged for the foregoing publication is not in excess of the rate charged private individuals. Signed________________________________ Subscribed and sworn to before me Account #: 100869 ST OF AK/AK OIL AND GAS CONSERVATION COMMISSION333 W. 7TH AVE STE 100, ANCHORAGE, AK 99501 Order #: W0045418 Cost: $325.18 Notice of Public HearingSTATE OF ALASKAALASKA OIL AND GAS CONSERVATION COMMISSION RE: Docket Numbers: AIO-24-013 By application dated April 16, 2024, Oil Search (Alaska), LLC (OSA), as the operator of the Pikka Unit (PU), requests that the Alaska Oil and Gas Conservation Commission (AOGCC) approve an Area Injection Order (AIO) to allow enhanced oil recovery (EOR) injection activities in the Nanushuk Oil Pool (NOP). Conservation Order 807 (CO 807), issued on July 20, 2023, defined the extents of the NOP and prescribed rules for its development. OSA is now seeking authorization to conduct an EOR injection project in the NOP in anticipation of beginning production from the PU in the coming years. The AOGCC approves injection orders for several purposes, including EOR, storage, and disposal either on an individual well or area wide basis in Alaska. EOR injection orders establish rules for conducting operations that are intended to increase the amount of oil or gas that could be recovered from a pool by one or more of the following mechanisms, maintain reservoir energy, sweeping oil through the reservoir to a production well, or modifying the properties of the oil to make it more mobile. This is consistent with the portion of the AOGCC’s mission that seeks to promote greater ultimate recovery. This notice does not contain all the information filed by OSA. To obtain more information, contact the AOGCC’s Special Assistant, Samantha Coldiron, at (907) 793-1223 or Samantha.Coldiron@alaska.gov. A public hearing on the matter has been scheduled for June 4, 2024, at 10:00 a.m. The hearing, which may be changed to full virtual, if necessary, will be held in the AOGCC hearing room located at 333 West 7th Avenue, Anchorage, AK 99501. The audio call-in information is (907) 202-7104 Conference ID: 204 118 862#. Anyone who wishes to participate remotely using MS Teams video conference should contact Ms. Coldiron at least two business days before the scheduled public hearing to request an invitation for the MS Teams. In addition, written comments regarding this application may be submitted to the AOGCC, at 333 west 7th Avenue, Anchorage, AK 99501 or Samantha.Coldiron@alaska.gov. Comments must be received no later than the conclusion of the June 4, 2024, hearing. If, because of a disability, special accommodations may be needed to comment or attend the hearing, contact Samantha Coldiron, at (907) 793-1223, no later than May 28, 2024. Brett W. Huber, Sr.Chair, Commissioner Pub: May 1, 2024 STATE OF ALASKA THIRD JUDICIAL DISTRICT ______________________________________2024-05-02 2024-07-14 Document Ref: ETTPK-7UYHJ-3OXR6-ZMMNY Page 6 of 30 From:Coldiron, Samantha J (OGC) To:AOGCC_Public_Notices Subject:[AOGCC_Public_Notices] Public Hearing Notice (Oil Search) Date:Tuesday, April 30, 2024 1:38:21 PM Attachments:AIO-24-013 public hearing notice establishing an AIO for the NOP in PU.pdf Docket Numbers: AIO-24-013 By application dated April 16, 2024, Oil Search (Alaska), LLC (OSA), as the operator of the Pikka Unit (PU), requests that the Alaska Oil and Gas Conservation Commission (AOGCC) approve an Area Injection Order (AIO) to allow enhanced oil recovery (EOR) injection activities in the Nanushuk Oil Pool (NOP). 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 1 Page 1 of 1 Oil Search (Alaska), LLC a subsidiary of Santos Limited 900 E. Benson Blvd. Anchorage, Alaska 99508 PO Box 240927 Anchorage AK 99524-0927 o: +1 907 375-4642 | m: +1 907 830-3956 Telephone: +1 907-375-4600 www.santos.com April 16, 2024 VIA EMAIL TO: SAMANTHA.COLDIRON@ALASKA.GOV Brett Huber, Chair Jesse Chmielowski, Commissioner Greg Wilson, Commissioner Alaska Oil and Gas Conservation Commission 333 W 7th Ave. Anchorage, AK 99501 Re: Application to Establish an Area Injection Order for the Nanushuk Oil Pool Dear Commissioners: Oil Search (Alaska), LLC, a subsidiary of Santos Limited (Santos), as Operator of the Pikka Unit, hereby submits the enclosed application requesting approval of an Area Injection Order for the Nanushuk Oil Pool. This document requests authorization and proposes rules for enhanced recovery and storage injection operations in accordance with 20 AAC 25.252, 20 AAC 25.402, and 20 AAC 25 460. Santos requests that the hearing date for this application be scheduled as soon as possible after the 30-day public notice period has concluded. If you have additional questions or concerns, please contact me at 907-375-4624 or via email at Tim.Jones3@santos.com. Thank you for your consideration. Sincerely, Tim Jones Land Manager Ecc: Dave Roby, Senior Petroleum Engineer (Dave.Roby@alaska.gov) Derek Nottingham, Director, ADNR Division of Oil and Gas (Derek.Nottingham@alaska.gov) Erik Kenning, Senior Director of Lands and Natural Resources, ASRC (EKenning@asrc.com) Enclosure: Application for an Area Injection Order for the Nanushuk Oil Pool Nanushuk Area Injection Order Application April 16, 2024 Page | 1 List of Figures Figure 1: Pikka Unit map ............................................................................................................................... 2 Figure 2: Plat of Planned injection well locations for NOP development . .................................................. 4 Figure 3: The Qugruk 3 Type log with depths of Nanushuk Oil Pool. ........................................................... 5 Figure 4: Cross section of upper (Seabee) and lower confining intervals (Torok) for the NOP .................... 7 Figure 5: Nanushuk typical producer Completion with liner tieback ........................................................... 9 Figure 6: Typical well with 2-stage cement job........................................................................................... 10 Figure 7: Nanushuk proposed NDB-43 injector Completion ...................................................................... 11 Figure 8: Frac modelling of the Q-8 well with perforations 20' below top of Nanushuk ........................... 13 Introduction Oil Search (Alaska), LLC, a subsidiary of Santos Ltd (“Santos”), in its capacity as operator of the Pikka Unit (shown in Figure 1) submits this document to the Alaska Oil and Gas Conservation Commission (“AOGCC” or “Commission”) on behalf of itself and other working interest owner (“WIO”) Repsol E&P USA LLC (Repsol).This application to the AOGCC seeks endorsement and authorization for enhanced recovery (water & gas) and storage injection operations in the Nanushuk Oil Pool (“NOP”) for which Pool Rules were finalized on July 20, 2023 under CO 807. A water injection pulse test is planned for June 2024 to confirm connectivity between wells and expected waterflood response. Well tests are being conducted to optimize development plans and storage avoids risks associated with hauling fluids to a non-Santos operated facility prior to field startup. Storage of produced oil from initial development well tests will prevent waste prior to full field startup. 20 AAC 25.402 & 25.252(c)(1) Location of proposed injection wells and ¼ mile offset penetrations A plat showing the location of each proposed injection well, abandoned or other unused well, production well, dry hole, or other well within a ¼ mile radius of each proposed injection well are shown in Figure 2. Nanushuk Area Injection Order Application April 16, 2024 Page | 2 Figure 1: Pikka Unit/Nanushuk Oil Pool map Nanushuk Area Injection Order Application April 16, 2024 Page | 3 20 AAC 25.402 & 25.252(c)(2,3) List and notification of operators and surface owners within ¼ mile Operators within a ¼ mile radius of the proposed injection wells are ConocoPhillips Alaska; Inc (CPAI) and Oil Search (Alaska), LLC. The surface owners within a ¼ mile radius of the proposed injection wells are Kuukpik Corporation and the State of Alaska. An affidavit showing that a copy of this application has been provided to the operators and surface owners within a ¼ mile radius of each proposed injection well is attached as Attachment 1. 20 AAC 25.402 & 25.252(c)(4) Description of the Proposed Operation Enhanced recovery operations within the NOP will employ a horizontal well line drive pattern with a Water Alternating Gas (“WAG”) or rich gas flood, to enhance oil recovery from the reservoir. Due to the highly laminated nature of the reservoir, all the wells (including the injectors) will be hydraulically fracture stimulated to enhance productivity and improve vertical injection sweep. Additionally, to remove potentially damaging fracturing gel and confirm rate capacity, frac flowbacks will be conducted; and accompanying oil production from the wells will be re-injected into the reservoir prior to startup to prevent waste. Only pre-production test fluids recovered beyond the initial load recovery will be re-injected, with volumes and injection pressures being tracked to ensure fracture gradients are not exceeded. For flexibility in dispersing pressure, test fluids may be injected in both producers and injectors which have been previously hydraulically fractured. Nanushuk Area Injection Order Application April 16, 2024 Page | 4 Figure 2: Plat of Planned injection well locations for NOP development. 20 AAC 25.402(c)(5) Description and Depth of Pool to be Affected The Nanushuk reservoir is a thick accumulation of deltaic shoreface deposits and is the up dip topset equivalent of the deeper water Torok Formation. The NOP is defined as the accumulation of hydrocarbons common to and correlating with the interval defined by the Nanushuk formation, between Nanushuk and Torok formation tops, from measured depths of 3,892 and 5,166 ft or 3,785 ft true vertical depth subsea (TVDSS) to 4,985 ft TVDSS shown on the Qugruk-3 well type log (Figure 3). Nanushuk Area Injection Order Application April 16, 2024 Page | 5 Figure 3: The Qugruk 3 Type log with depths of Nanushuk Oil Pool. Lower Confining Interval Torok Formation Lithologic Description: The Torok Formation underlies the target reservoir Nanushuk Formation and is dominantly comprised of claystones and silty shales and thick shale sequences. The formation grades Nanushuk Area Injection Order Application April 16, 2024 Page | 6 from silty shales in the shallower section to shale at the base of the Torok Formation. The shales are described in offset wells as very fine grained medium dark grey to dark brownish and greyish black. Soft to easily friable, occasionally firm. The succession is dominated by tabular to platy cuttings with very well- developed laminations, and high organic content overall with layers of organic/carbonaceous material. The fracture gradient for this sealing shale is 16.0-17.0 ppg. Depth & Thickness: 5,200 MD/5,135 TVDSS, ~250ft TVT Upper Confining Interval Seabee Formation Lithologic Description: The Seabee Formation immediately overlies the Nanushuk Formation. The base of the Seabee is the shale wall facies which is a marine flooding surface composed of condensed mudstone facies deposited during a maximum transgression and creates a good regional seal. Distant volcanism occurred during its deposition resulting in numerous bentonite interbeds. The overall Seabee Formation is a thick shale/claystone dominated unit which represents the distal deep-water slope and basinal deposits. The claystones within the Seabee Formation are described as medium grey to dark grey, soft and mushy to slightly firm, locally partings along laminations, commonly micas and scattered very fine lithic grains. Grading to weakly fissile shale. The fracture gradient for this sealing shale is 14.9- 16.8 ppg confirmed by a leak off test in well CD4-594 at 14,767 ft MD/4,059 ft TVD (16.8 ppg EMW or .87 psi/ft) and a formation integrity test in NDB-43 at 6,260 ft MD/4,323 ft TVD (14.9 ppg EMW or .77 psi/ft) Depth & Thickness: 3,175 ft MD/2,830 ft TVDSS, ~1,000 ft TVT Nanushuk Area Injection Order Application April 16, 2024 Page | 7 Figure 4: Cross section of upper (Seabee) and lower confining intervals (Torok) for the NOP. 20 AAC 25.402 (c)(6) Description of the Formation The Torok and Nanushuk Formations are the lower portion of the Brookian sequence and are Lower Cretaceous in age. The Lower Cretaceous section is a large-scale constructional siliciclastic clinoform system, where the topset unit is the Nanushuk Formation and the foreset unit is the Torok Formation. The internal architecture of the system is comprised of multiple clinoforms, of different order, accretionary deposited from west to east. The development of the NOP in the Pikka Unit contemplates the drilling of long horizontal wells across a number of different order clinoforms or prograding parasequence sets. The Nanushuk hydrocarbon bearing sandstones are often present at the topset of the clinoforms and comprised of amalgamated sands gradationally changing to clay-siltstone with abundant thinly laminated mudstones. 20 AAC 25.402 (c)(7) & 25.252(c)(5) Logs of Injection wells Well logs derived from each injection well to be provided with each wells completion report. 20 AAC 25.402(c)(6) & 25.252(c)(12) Mechanical Integrity of Injection Wells Surface holes will be drilled and set above the Tuluvak formation for proper anchorage, prevention of uncontrolled flow, and protection from permafrost thaw and freeze back. In the Pikka area there are Nanushuk Area Injection Order Application April 16, 2024 Page | 8 some known areas of shallow gas within the Tuluvak formation, so top-setting the Tuluvak will allow blowout prevention equipment (BOPE) to be installed prior to drilling the gas-bearing formation. This casing setting depth provides adequate depth for required kick tolerance to drill the intermediate section. Within the planned development area, the base of permafrost is interpreted to be between 750 ft and 1,400 ft TVDSS. Surface casing strings will be cemented in accordance with 20 AAC 25.030(d)(4). The blowout prevention equipment (BOPE) will be installed and tested in accordance with 20 AAC.25.035 requirements. A Formation Integrity Test (FIT) will be performed in accordance with 20 AAC 25.030(f). Intermediate sections will be drilled utilizing the latest directional techniques from surface casing, encountering the top of the Nanushuk at 40-85 degree inclination. Casing will be set and cemented with the shoe just above, or just into, the Nanushuk Reservoir and containment will be verified with a bond log. The Tuluvak will be cemented where gas is present. A gas-tight liner top packer will provide secondary containment above with the surface casing cement as additional protection against gas movement. The section between the Tuluvak and the top of the Nanushuk Reservoir consists primarily of mudstones and siltstones with no significant hydrocarbon zones. See figures below for a sketch of a typical producer well design for the first injector completed in the NOP, NDB-43. Nanushuk Area Injection Order Application April 16, 2024 Page | 9 Figure 5: Nanushuk typical producer Completion with liner tieback. Nanushuk Area Injection Order Application April 16, 2024 Page | 10 Figure 6: Typical well with 2-stage cement job. Nanushuk Area Injection Order Application April 16, 2024 Page | 11 Figure 7: 7Nanushuk proposed NDB-43 injector Completion. Depending on well length and inclination, one or more intermediate strings or two stage cement jobs may be deployed between the surface casing shoe and the top of the Nanushuk Reservoir, as determined by the required engineering design. Cementation of intermediate/production casing will comply with all other requirements of 20 AAC 25.030(d)(5) including coverage of Tuluvak sand when gas is present as stipulated in CO 807. The tubing/casing annulus pressure of each injection well will be tested and monitored in accordance with 20 ACC 25.412(c). Drilling and completion operations will be performed in accordance with applicable Nanushuk Area Injection Order Application April 16, 2024 Page | 12 AOGCC regulations. In accordance with 20 AAC 25.412(d), cement bond 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. 20 AAC 25.402(c)(9) & 20 AAC 25.252 (c)(7) Injection Fluid Analysis and Injection Rates The storage operation will involve re-injection of NOP crude oil, solution gas & minor amounts of water recovered from well tests prior to facility startup. Seawater with alternating gas-injection is proposed for enhanced recovery injection into the NOP. After water-breakthrough, individual well patterns may be swapped to produced water. Injection history at the Colville River Unit has demonstrated the compatibility of both produced water and sea water in Brookian age reservoirs, specifically the Nanushuk formation at the Qannik pool, over the past 10+ years. No issues are expected with injection of either seawater or produced water/gas into the Nanushuk formation. Liquid injection rates between 2,000 and 10,000 bbl/d and gas rates between 3 and 15 MMscf/day are expected at each injection well drilled for the project and will be managed to achieve and maintain a voidage replacement ratio of 1. Proposed allowable injection fluids include: Beaufort seawater sourced from the Pikka or Kuparuk seawater treatment plant. Produced water from all present and yet -to -be defined oil pools within the Pikka, Colville, and Kuparuk River Units so long as produced water salinity is within range of that produced in offset Units. Lean and enriched gas from the Pikka Unit as well as gas imported from outside the Unit. 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 Nanushuk injection wells. These fluids are not planned for continuous injection, or as a means for enhanced recovery. The volumes of these other fluids are not expected to hinder the recovery efficiency of performance. These other fluids include: a. Fluids used during hydraulic stimulation, including reservoir oil and solution gas from flowback testing prior to production facility startup. b. Tracer survey fluids to monitor reservoir performance. c. Fluids used to improve flowbacks or near wellbore injectivity (nitrogen, acid, solvents, etc.) d. Fluids associated with freeze protection (diesel, crude, glycol, methanol, etc.) e. Standard oilfield chemicals (corrosion inhibitor, scale inhibitor, etc.) f. Sump fluid, hydrotest fluid, rinsate generated from washing mud hauling trucks, excess well work fluids, and treated camp effluent and mixtures involving such fluids. 20 AAC 25.402 (c)(10) & 25.252(c)(8) Estimated Average and Maximum Injection Pressures The flowing bottom hole pressure of the injection wells will be maintained within the strength of the K-3 seal. Analysis of available data in the seal interval yielded a fracture gradient as high as 0.87 psi/ft. The project will target an injection gradient of 0.7 psi/ft with an operating maximum at 0.8 psi/ft, but this is subject to change as more information is gathered. The project will operate near the fracture gradient of the NOP reservoir sandstone which has demonstrated a fracture gradient of 0.6 to 0.7 psi/ft in the multiple exploration fracture tests. Nanushuk Area Injection Order Application April 16, 2024 Page | 13 At 4,100' TVDSS the typical bottomhole injection pressure will be less than 2,875 psi (0.75 psi/ft), with temporary operational deviations up to a maximum of 3,280 psi (0.8 psi/ft). The maximum surface operating pressure of each injector will be set based on the realized depth of the reservoir and hydrostatic gradient of fluid injected. 20 AAC 25.402(c)(11) & 25.252(c)(9) Fracture Information In the Pikka Unit area, the NOP is overlain by a 240 to 310 foot TVD claystone section with thin siltstone beds from the K-3 marker to the top NOP sandstone; part of the Cretaceous Nanushuk Group, here referred to as the K-3 Seal. The underlying confining zone beneath the NOP consists of 25-100 feet TVD of shaley slope mudstones and shales that thicken to the east/southeast. The calculated hydraulic fracture gradient for the K-3 Seal is based on the available leak-off tests (LOT) and formation integrity tests (FIT) in the immediate area that include one LOT within the seal interval that exceeded 3,500 psig. Fracture modelling indicates that fractures are contained within the reservoir. Fracture modelling is done with StimPlan software heavily used in industry and validated with rock mechanical properties obtained from core, well logs, and appraisal well fracture tests. Figure 8: Frac modelling of the Q-8 well with perforations 20' below top of Nanushuk. 20 AAC 25.402 (c)(12) & 25.252(c)(10) Quality of Formation Water A water sample was obtained from the Pikka B well at 4,784’ approximately 600’ below the top of the Nanushuk. The salinity of this water was found to be about 17,000 ppm with relatively low calcium and barium concentrations as shown below. No downhole scaling issues are expected with either seawater or produced water, and only minor scale inhibition is expected to be needed at the surface production heater. Nanushuk Area Injection Order Application April 16, 2024 Page | 14 Table 1: Water analysis from NOP well Pikka B. 4834' MD sample Cations Test Method (mg/l) Meq/l Pikka B Barium Ba+2 ICP 8.9 0.16 Cadmium Cd+2 ICP <0.006 0.00 Calcium Ca+2 ICP 79 4.94 Chromium Cr+3 ICP <0.007 0.00 Cobalt Co+2 ICP <0.01 0.00 Copper Cu+2 ICP <0.009 0.00 Iron (total) Fe+2 ICP 8.1 0.00 Lead Pb+2 ICP <2.2 0.00 Lithium Li+ ICP 1.7 0.29 Magnesium Mg+2 ICP 24 1.55 Manganese Mn+2 ICP 0.0 0.00 Molybdenum Mo+6 ICP <0.044 0.00 Nickel Ni+2 ICP <0.02 0.01 Phosphorus P+3 ICP <0.17 0.00 Potassium K+ ICP 37 1.24 Silicon Si+4 ICP 10 2.16 Sodium Na+ ICP 6,420 302.09 Strontium Sr+2 ICP 4.2 0.10 Vanadium V+2 ICP <0.01 0.00 Zinc Zn+2 ICP 0.0 0.00 Anions Test Method (mg/l) Meq/l Bicarbonate HCO3- Titration 575 63.97 Borate B(OH)4- ICP 7.9 0.18 Bromide Br- Titration / IC 87 1.02 Carbonate CO3-2 Titration 18 0.00 Chloride Cl- Titration / IC 9,430 259.13 Fluoride F- IC <2 0.00 Iodide I- Titration / IC 30 0.30 Nitrate NO3-2 IC <2 0.00 Nitrite NO2- IC <2 0.00 Phosphate PO4-3 IC <2 0.00 Nanushuk Area Injection Order Application April 16, 2024 Page | 15 Sulfate SO4-2 IC 27 0.43 Sulfide S-2 IC 0.0 0.00 Bicarbonate HCO3- Rice Titration 401 Organic Acids Test Method (mg/l) Meq/l Acetate CH3COO- IC 3,170 53.71 Butyrate CH3(CH2)2CO2- IC 30 0.35 Formate HCOO- IC <10 0.00 Glycolate CH2OHCOO- IC <10 0.00 Propionate CH3CH2CO2- IC 315 4.33 Valerate CH3(CH2)3CO2- IC <10 0.04 Total Cation Meq's 313 Stability Index at 100 °F -0.42 Total Anion Meq's 325 Stability Index at 200 °F 1.47 TDS (mg/l) 17,169 TDS (ppm) 16,953 % Deviation in Meq. Bal. 10.19 Ion Balance 0.102 % Deviation in TDS 3.62 20 AAC 25.402(c)(13) & 25.252(c)(11) Aquifer Exemption Reference Santos is not aware of any Aquifer Exemption Orders in the proposed area. Examination of well log data from exploratory wells in and near the proposed NOP confirms that there are no freshwater aquifers within the affected area that could serve as underground sources of drinking water. None of the subsequent oil pools and area injection orders in the adjacent units have found any freshwater aquifers to exist within the Colville River, Oooguruk, or Kuparuk unit areas. 20 AAC 25.4O2(c)(14) Incremental Hydrocarbon Recovery The NOP will be developed in a phased approach initiated from existing infrastructure. Development will be completed in discrete phases to apply knowledge gained from previous phases and improve recovery. The initial targets will be accessed from the NDB drill site and future targets may be accessed via additional drill sites. The table below summarizes the potential resources associated with full NOP development. Table 2: Estimated Nanushuk oil in place with recoverable volumes associated with different recovery mechanisms. Nanushuk Reservoir low high Original Oil in Place (OOIP) 2,297 - 2,814 MMSTB Primary Recovery 161 - 253 MMSTB Primary + Waterflood 532 - 718 MMSTB Primary + Waterflood + WAG 592 - 868 MMSTB Nanushuk Area Injection Order Application April 16, 2024 Page | 16 The NOP will employ a horizontal well line drive pattern with the intent to convert to a Water Alternating Gas (“WAG”) or rich gas flood, to enhance oil recovery from the reservoir. Due to the highly laminated nature of the reservoir, all the wells (including the injectors) will be hydraulically fracture stimulated to enhance productivity and improve vertical injection sweep. 20 AAC 25.402 & 25.252(c)(15) Mechanical Condition of Wells Within 1/4 Mile of Proposed Area The only wells which penetrate the NOP interval within 1/4 mile of proposed injection operations are exploration wells which have been cemented across and plugged above the NOP and will be documented with the drilling permit for proposed injectors. Proposed wells will be drilled in accordance with applicable AOGCC drilling regulations. Proposed Rules Underground injection of fluids for oil storage, pressure maintenance and enhanced recovery to be 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 Township 10 North, Range 5 East Sections 2-4 – All Section 5 – E1/2, SE1/4NW1/4, E1/2SW1/4, and SW1/4SW1/4 Township 11 North, Range 5 East Section 1 – E1/2 and E1/2W1/4 Sections 12-13 – All Section 14 – E1/2, E1/2NW1/4, SW1/4NW1/4 and SW1/4 Section 15 – SE1/4SE1/4 Section 22 – E1/2, E1/2SW1/4, and SW1/4SW1/4 Sections 23-27 – All Sections 34-36 – All Township 11 North, Range 6 East Sections 1-12 – All Sections 17-20 – All Township 12 North, Range 5 East Sections 24-25 – All Section 26 – NE1/4, NE1/4NW1/4, and Nanushuk Area Injection Order Application April 16, 2024 Page | 17 E1/2SE1/4 Section 36 – N1/2, N1/2SW1/4, SE1/4SW1/4, and SE1/4 Township 12 North, Range 6 East All Township 13 North, Range 5 East Sections 1-3 - All Sections 11-14 – All Sections 23-25 - All Township 13 North, Range 6 East Sections 1-2 – All Sections 6-36 – All Township 14 North, Range 5 East Sections 24-27 - All tide and submerged lands lying shoreward of the line fixed by coordinates found in Exhibit A of the Final Decree in U.S. v. Alaska, No. 84 Original Sections 34-36 - All Township 14 North, Range 6 East Section 19 – All tide and submerged lands lying shoreward of the line fixed by coordinates found in Exhibit A of the Final Decree in U.S. v. Alaska, No. 84 Original Sections 30 & 31 - All Rule 1: Authorized Injection Strata The Nanushuk Oil Pool as defined as the accumulation of oil and gas common to and correlating to the stratigraphic interval between 3,892 and 5,166 feet measured depth in the Qugruk-3 well and its lateral equivalents. Rule 2: Well Construction Packers in injection wells may be located more than 200 feet measured depth above the top of the injection zone; however, packers must not be located above the confining zone. In cases where the distance is more than 200 feet, the production casing cement volume should be sufficient to place cement a minimum 300 feet measured depth above the planned packer depth as well as coverage of the Tuluvak as stipulated in the pool rules. Rule 3: Authorized fluids for injection 1. For storage operations: re-injection of crude oil, solution gas & minor amounts of fracturing fluid water recovered from NOP well tests prior to facility startup. 2. For Enhanced Recovery operations: a. Beaufort seawater sourced from the Pikka or Kuparuk seawater treatment plant. b. Produced water from all present and yet -to -be defined oil pools within the Pikka, Colville, and Kuparuk River Units so long as produced water salinity is within range of that produced in offset Units. c. Lean and enriched gas from the Pikka Unit as well as gas imported from outside the Unit. 3. Minor amounts of the following fluids: a. Tracer survey fluids to monitor reservoir performance. Nanushuk Area Injection Order Application April 16, 2024 Page | 18 b. Fluids used to improve flowbacks or injectivity (nitrogen, acid, solvents, etc.) c. Fluids associated with freeze protection (diesel, crude, glycol, methanol, etc.) d. Standard oilfield chemicals (corrosion inhibitor, scale inhibitor, etc.) e. Sump fluid, hydrotest fluid, rinsate generated from washing mud hauling trucks, excess well work fluids, and treated camp effluent and mixtures involving such fluids. Rule 4: Authorized Injection pressures At 4,100' TVDSS the target bottomhole injection pressure will be less than 3,280 psi (0.8 psi/ft). The maximum surface operating pressure of each injector will be set based on the realized depth of the reservoir and hydrostatic gradient of fluid injected. Rule 5: Tubing-Casing Annulus Pressure monitoring The operator shall monitor each injection well daily to check for sustained pressure, except if prevented by extreme weather conditions, emergency situations, or unavoidable circumstances. Monitoring results shall be made available for AOGCC inspections. Rule 6: Demonstration of Mechanical Integrity At the time of installation or replacement, the operator shall conduct and document a pressure test of tubulars and completion equipment in each production well that is sufficient to demonstrate that planned well operations will not result in failure of well integrity, uncontrolled release of fluid or pressure, or threat to human safety. 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. Mechanical integrity must be demonstrated by a tubing/casing annulus pressure using a surface pressure of 1,500 psi that shows stabilizing pressure that does not change more than 10 percent during a 30-minute test period. 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. Rule 7: Well Integrity and Confinement The operator shall notify the AOGCC within one business day and submit a plan for corrective action via Form 10-403 after identifying a well as having lost injection zone isolation as indicated by injection rate, pressure, log or other evidence. Rule 8: Notification of Improper Class II Injection AOGCC shall be notified of injection of fluids other than those listed in Rule 3 and provide details of the operation and propose actions to prevent reoccurrence. Rule 9: Other Conditions If fluids are found to be fracturing the confining zone or migrating out of the approved injection strata, the Operator must immediately shut in the injection well and notify AOGCC. Injection may not be restarted unless approved by the AOGCC.