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Home My WebLink About2024 Oooguruk-Kuparuk Oil Pool2024 Annual Reservoir Surveillance Report Oooguruk-Kuparuk Oil Pool (OKOP) Oooguruk Field April 17, 2025 Hilcorp – WNS Asset Team Table of Contents SUBJECT PAGE 1.0 Progress of the Enhanced Recovery Project ............................................................................1 2.0 Results and Analysis of Reservoir Pressure Surveys within the Pool .........................................3 3.0 Results and Analysis of Production and Injection Log Surveys, Tracer Surveys, Observation Well Surveys and Any Other Special Monitoring ......................................................................................3 4.0 Review of Pool Production Allocation Factors and Issues Over the Year ...................................4 5.0 Reservoir Management Summary .........................................................................................5 ATTACHMENT A OKOP Well Location Map ...................................................................................6 ATTACHMENT B 2024 OKOP Voidage Balance by Month ...............................................................7 ATTACHMENT C OKOP Pressure Report, Form 10-412 ....................................................................8 ATTACHMENT D OKOP Annual Reservoir Properties Report, Form 10-428 ........................................9 Hilcorp – WNS Asset Team Page 1 1.0 Progress of the Enhanced Recovery Project The Oooguruk Field (OF) is located offshore on the North Slope of Alaska. Three oil pools, the Torok, Kuparuk, and Nuiqsut, are currently under development within the OF. The development consists of an offshore man-made gravel island, the Oooguruk Drill Site (ODS), located just east of the Colville River Delta in Harrison Bay. ODS production is delivered to the Oooguruk Tie-in Pad (OTP) via a buried subsea flowline bundle and onshore flowlines, metered, then transferred to Kuparuk River Unit (KRU) facilities, operated by ConocoPhillips Alaska, Inc. (CPAI), for final processing and transportation to the sales line. The Oooguruk-Kuparuk Oil Pool (OKOP) development includes nine wells: ODSN-06 Kuparuk, ODSK-13i, ODSK-14, ODSN-29 Kuparuk, ODSK-33, ODSK-35Ai, ODSK-38i, ODSN-40i Kuparuk, and ODSK-41. The locations of the OKOP, the OKOP wells, the current OU, and the Oooguruk Kuparuk Participating Area (OKPA) are shown in Attachment A. Currently, two producers, ODSN-06 Kuparuk and ODSK-14, and one injector, ODSK-38i, are active. The ODSK-33 well is inactive due to a high water cut, ODSK-13i remains shut-in for long-term pressure fall-off monitoring, ODSK-35Ai is shut-in and secured due to multiple tubing leaks, ODSN-29 Kuparuk has been isolated to produce from the Nuiqsut, the ODSN-40i Kuparuk is shut-in due to limited injection capacity, and ODSK-41 is shut-in due to a failed ESP and inability to lift using back up gas lift (low reservoir pressure). Operations included general maintenance and replacing critical oil, water, and gas piping and valves. Field-wide maintenance was also performed, including mechanical integrity inspections of piping, tanks, pressure vessels and other safety systems. As per vendor recommendation, routine maintenance was performed on the three power generation turbines, including the generator cleaning. In addition, cathodic protection inspections were completed on the sub-sea production flowline from ODS to OTP to ensure the mechanical integrity of the pipelines. The river overflood inspections are completed annually to verify the depth of cover over the buried subsea pipelines, including modeling of water flows over the ice, strudel and scour identification and bathymetric surveys. Conversion from the existing Siemens PCS7 Distributed Control System (DCS) to Emerson DeltaV is ongoing and will be completed in 2025. The Oooguruk development originally envisioned producing wells with electrical submersible pumps (ESPs) in order to maximize drawdown and minimize gas lift and the associated KRU and hydraulic back-out effects. Currently, the majority of the OF producing wells require gas lift to produce; only two wells, ODSN-04 and ODSN-25, produce using ESPs. The gas lift gas coupled with the OF formation gas significantly impacts the flowline pressure, reducing overall flowrates, and generates significant back-out cost at KRU, which is also primarily constrained by gas processing capacity. Hilcorp – WNS Asset Team Page 2 Table 1: 2024 OKOP Well Interventions Average annual daily water injection for 2024 was 1,238 bpd. Total water injection in 2024 was 461 Mbbl. The annual voidage replacement ratio averaged 106% for the year. The cumulative voidage replacement ratio is at 59%. Attachment B details the 2024 voidage balance for the ONOP. Hilcorp – WNS Asset Team Page 3 2.0 Results and Analysis of Reservoir Pressure Surveys within the Pool No pressure surveys were conducted in the Kuparuk pool in 2024. 3.0 Results and Analysis of Production and Injection Log Surveys, Tracer Surveys, Observation Well Surveys and Any Other Special Monitoring Reservoir surveillance is conducted as needed to monitor wells and reservoir performance and to recommend changes in operating conditions, perform rate allocations, propose optimization actions, address, and solve general issues. Hilcorp – WNS Asset Team Page 4 4.0 Review of Pool Production Allocation Factors and Issues Over the Year Production from the Oooguruk-Torok Oil Pool (OTOP), Oooguruk-Kuparuk Oil Pool (OKOP) and Oooguruk-Nuiqsut Oil Pool (ONOP) is commingled at the surface into a common production line. Allocation between the pools is based on the ratio of total production for a pool to the total production for the Oooguruk Unit. The pool oil allocation factors for 2024 are: ONOP:96.1% OKOP: 3.9% OTOP: 0% Theoretical production for individual wells for all pools is calculated on a daily basis. Daily theoretical production for a well was calculated using the data from the most current well test and the amount of time a well was on production for a given day: oductionlDailyTheoreticaBOPDxDailyRate dayMinutes Minutes Welltest produced Pr)( 1440  The daily allocation factor for the unit is calculated by dividing the actual total production for the day by the sum of the theoretical daily production for each individual well. Daily allocated production is assigned to each well by multiplying its theoretical daily production by the daily allocation factor. The average daily oil allocation factor for 2024 during Hilcorp operation was 0.914. Hilcorp – WNS Asset Team Page 5 5.0 Reservoir Management Summary The AOGCC issued pool rules under Conservation Orders Nos. 645A, 596, and 597 for the OTOP, OKOP, and ONOP, respectively. While there is no subsurface commingling, unitized substances produced from the three oil pools are commingled on the surface. Area injection orders (AIOs) authorizing the injection of fluids for enhanced oil recovery in the OTOP, OKOP, and ONOP reservoirs were issued by the AOGCC as AIO No. 37A, 33 and 34, respectively. Injection commenced into the OKOP in 2009. The OKOP reservoir management targets maximizing oil production, managing producing gas-oil ratios (GOR), and maximizing long-term reservoir performance and value through enhanced recovery while minimizing the project risks and maintaining the highest environmental and safety standards. Flood throughput and reliable water supply are critical to long-term OKOP recovery. Consequently, Eni implemented SWIS in 2020 and 2021 to avoid injecting KRU-produced water, improve water supply reliability, and increase available injection pressures. SWIS uptime has been very high, successfully meeting OF reservoir injection targets and increasing supply pressure.Additionally, once the ODS booster pump is placed in service, water injection supply pressures can be boosted from 3,400 psi to 3,700 psi, increasing injectivity and flood throughput in certain low injectivity wells. The AOGCC has approved increasing the pressure limit to 3,700 psi from 2,800 psi for both the ONOP and OKOP; however, the OTOP limit remains at 2,800 psi, consistent with Rule 4 of AIO 37A. Higher injection pressures are typically unnecessary for Kuparuk reservoir injection; however, one well ODSN-40 with limited injectivity may benefit. Because the OKOP development area is a mature flood in a dual porosity system with highly variable matrix permeability and open fracture networks, voidage replacement has been purposely reduced to minimize waterflood by-pass while stabilizing the reservoir pressure and the GOR. As a result, the producing Kuparuk water oil ratio and oil production have remained fairly stable and ultimate recovery is projected to exceed expectations. However, during the extended 2019-2020 water injection shutdown, the OKOP-producing GOR increased from 3,200 SCF/STBO to 4,800 SCF/STBO. At the end of 2024 OKOP cumulative voidage replacement was at 59%, refer to Attachment B. Hilcorp – WNS Asset Team Page 6 ATTACHMENT A OKOP Well Location Map Hilcorp – WNS Asset Team Page 7 ATTACHMENT B 2024 OKOP Voidage Balance by Month Hilcorp – WNS Asset Team Page 8 ATTACHMENT C OKOP Pressure Report, Form 10-412 Inentionally Left Blank Hilcorp – WNS Asset Team Page 9 ATTACHMENT D OKOP Annual Reservoir Properties Report, Form 10-428