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Home My WebLink About2023 Oooguruk-Kuparuk Oil Pool 2023 Annual Reservoir Surveillance Report Oooguruk-Kuparuk Oil Pool (OKOP) Oooguruk Field April 1st, 2024 Eni Petroleum, Alaska 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 ....................................................................................... 4 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: 2023 OKOP Voidage Balance by Month ................................................................ 7 ATTACHMENT C: 2023 OKOP Pressure Report, Form 10-412............................................................ 8 ATTACHMENT D: OKOP Reservoir Pressure Map – December 2023 .................................................. 9 ATTACHMENT E: OKOP Annual Reservoir Properties Report, Form 10-428 ...................................... 10 Eni Petroleum, Alaska Page 1 1.0 Progress of the Enhanced Recovery Project The Oooguruk Field (OF) is one of two Eni US Operating Co. Inc. (Eni) offshore-operated fields in 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, and 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). In 2023, engineering and operational efforts focused on optimizing and debottlenecking existing equipment. In addition, Oooguruk Field Engineering performed an internal operations and maintenance assessment to ensure compliance with corporate requirements. Engineering work commenced on an integrated model connecting the reservoir, wells, and surface production equipment to optimize production. An engineering study for revamping the 2-phase separator also started. Operations included general maintenance and replacing critical oil, water, and gas piping and valves. Field-wide maintenance included mechanical integrity inspections of piping, tanks, pressure vessels, and other safety systems. During 2023, Operations and Facilities engineering performed internal operations and maintenance assessments to ensure compliance with corporate requirements. Eni’s corporate operations team also conducted a Oooguruk asset review to identify bottlenecks at the plant, efficiencies, and production improvement opportunities. The 2023 asset review recommended detailed actions and an engineering study to be conducted in cooperation with the specialists at HQ. An internal corporate assessment was also performed to ensure compliance with internal procedures on safety and environmental critical elements. An engineering study was conducted to revamp the 2-phase separator. Operations included general maintenance and replacing critical oil, water, and gas piping and valves. Field-wide maintenance was also performed, including mechanical integrity inspections Eni Petroleum, Alaska Page 2 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. A detailed monitoring plan for injection system microbes was established with systematic biocide treatments conducted during 2023. Capital projects included eight (8) well workovers, 7 producers, and 1 injector. Four (4) ESPs were installed in production wells. The OTP control room design study was completed to relocate the OTP control room in 2025. Capital projects included upgrading the Fire and Gas software, mandatory tank and vessel inspections, lift/injection compressor PLC upgrade and module lifecycle upgrade. The ODS exterior camera system was completed and upgraded in 2023 to allow enhanced warning of nearby polar bears, seawater injection line pig trap upgrades, and the addition of a corrosion coupon to the ODS subsea diesel flowline was also completed. A conversion from the existing Siemens PCS7 Distributed Control System (DCS) to Emerson DeltaV has been developed, with a detailed engineering study supporting implementation during the 2025 planned major maintenance turnaround. Finally, the Rig Support Complex (RSC) has been partially revamped to support the Well Work Over campaign that took place and future drilling campaigns. The revamping will continue in the following years. The Oooguruk development originally envisioned producing wells would ultimately utilize electrical submersible pumps (ESPs) to maximize drawdown and minimize gas lift and the associated KRU and hydraulic back-out effects. Currently, most OF-producing wells require a 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 flow rates and generating significant back-out costs at KRU, primarily constrained by gas processing capacity. These constraints result in backing out KRU fluid production when a high total gas oil ratio (TGOR, includes formation and lift gas) OF fluids enter the system. Because of the hydraulic effects and KRU back-out all OF wells cannot be produced concurrently using gas lift. In 2023, on average, 14 of the 22 available producing OF wells were online, with TGOR ranking typically used to determine which wells to produce. In 2023 the activity on Kuparuk wells on ODS was limited to three rigless workovers (RLWO) on two wells, as per Table 1 below. Table 1: 2023 OKOP Well Interventions Action #Well Name Well Type Location Reservoi r Action Type Objectives / Description Completion date 1 ODSK-41 OP ODS Kuparuk Rigless PVV diagnostics 1/23/2023 2 ODSK-41 OP ODS Kuparuk Rigless Troubleshoot TRSCSSSV 2/19/2023 Eni Petroleum, Alaska Page 3 As a result of the May 2022 through March 2023 rig program and sustained water injection, OF oil production peaked in April 2023 at 7,488 bpd from 5,000 bpd in April 2022, an increase of 2,488 bpd (+50%). December 2023 OF oil production averaged 6,217 bpd; the 1,271 bpd decline ( 17%) from April was primarily a result of two early ESP failures (ODSN-02 in May and ODSK-41 in August), ODSN 06 Kuparuk oil rate decline, which was as expected, and overall OF decline. The 2023 annual average daily oil rate was 6,650 bpd, up 10% from 6,030 bpd in 2022. Produced water averaged 3,428 bpd, a 34% watercut, in 2023, up slightly from 3,280 bpd, a 35% watercut, in 2022. Total OF gas rates, formation plus lift gas, remained relatively stable, averaging 20.5 MMSCFPD in 2023 compared to 21.4 MMSCFPD in 2022. The OF production network remains hydraulically constrained, so only 13 of the 22 available wells were online on December 31, 2023. The annual average daily OKOP oil production for 2023 was 948 bpd. Total oil production in 2023 was 346,127 barrels for a cumulative 10,776,819 since field start-up in 2008. The 2023 annual average producing gas oil ratio (GOR) and watercut were 660 SCF/STBO and 59%, respectively. The December 2023 average GOR was 615 SCF/STBO and the watercut was 72%. The average annual daily water injection for 2023 was 1,536 bpd, with average daily rates ranging from 0 bpd to 7,000 bpd. Total water injection in 2023 was 560,798 barrels, and since the start of injection in 2009, it has been 16,891,311 barrels. Attachment B details the 2023 monthly and cumulative voidage for the OKOP. 2.0 Results and Analysis of Reservoir Pressure Surveys within the Pool Two pressure surveys were reported from two OKOP wells; the pressure survey results are presented in the OKOP Pressure Report, Form 10-412 (See Attachment C). The OKOP Reservoir Pressure Map, Attachment D, depicts the estimated OKOP average pressures for December 2023, including all wells, active and inactive. Overall, the pressures in the main development continue to show pressure equalization due to historical voidage replacement, excluding the ODSK-41 area, which continues to show limited communication to offset wells. Pressures from the ODSK-13 December 2013 injection and fall-off test continue to demonstrate that the western Ivik block has relatively low transmissibility and is not in hydraulic communication with the main development area, including the ODSN-29 and ODSN-06 Kuparuk completions to the east—the December 2023 OKOP pressure at 6,050 ft. TVDss is estimated at 2,500 psi (refer to Attachment E, Kuparuk Annual Reservoir Properties Report Form 10-428). Eni Petroleum, Alaska Page 4 3.0 Results and Analysis of Production and Injection Log Surveys, Tracer Surveys, Observation Well Surveys and Any Other Special Monitoring A chemical tracer program was initiated in May 2012 and completed in 2014. Tracers were injected into ODSK-35Ai and ODSK-38i. Within 20 months of initial injection tracer concentrations were observed in ODSK-33 and ODSK-14 from ODSK-35Ai. The ODSK-38i tracer has only been seen in minor amounts in ODSK-33. Produced water samples from ODSN-29 Kuparuk did not show signs of either tracer. No additional surveillance logging or surveys were conducted in 2023. 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 2023 are: ONOP: 85.5% OKOP: 14.3% OTOP: 0.2% Theoretical production for individual wells for all pools is calculated daily. During 2023 wells were produced with chokes at 100% most of the time due to the capacity of the production line. 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 total production for the day by the sum of the theoretical daily output for each well. Daily allocated production is assigned to each well by multiplying its theoretical daily production by the daily allocation factor. The average daily allocation factor for 2023 was 0.9246. Eni Petroleum, Alaska 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. Subsequently, voidage replacement has been gradually increased, and the GOR is consistently less than 700 SCF/STBO (615 SCF/STBO December 2023), and the watercut is in line with expectations for a mature flood (72% December 2023). At the end of 2023 OKOP cumulative voidage replacement was at 58%, refer to Attachment B. OKOP 2023 production was primarily associated with the ODSN-06 Kuparuk in the eastern Ivik fault block, yielding 70.5% of the annual oil production or 244,136 bbls at an average oil rate of 673 bpd; ODSK-41 produced 80,654 bbls, 23.3% of OKOP oil production at an average oil rate of 368 bpd, through August 10, 2023 when the ESP failed, and ODSK-14 produced 21,337 bbls or 6.2% at an average oil rate of 240 bpd. ODSK-14 production was limited to 89 days (24% uptime) due to its non-competitive TGOR on backup gas lift. ODSK-41 remains shut-in since the ESP failure as the well cannot produce on back up gas lift (low reservoir pressure). Eni Petroleum, Alaska Page 6 ATTACHMENT A: OKOP Well Location Map Eni Petroleum, Alaska Page 7 ATTACHMENT B: 2023 OKOP Voidage Balance by Month Month Oil, MRB Free Gas, MRB Water, MRB Total Voidage, MRB Year Cum, MRB Cum since start-up, MRB Gas, MRB Water. MRB Total Injection, MRB Year Cum, MRB Cum. since start-up, MRB Net Injection, MRB Year Cum, MRB Cum since start-up, MRB Cum Since Start-Up thru 2022 >>28,140 Cum Since Start-Up thru 2022>>16,331 -11,810 Jan-23 47 3 44 94 94 28,234 0 36 36 36 16,367 -58 -58 -11,868 Feb-23 48 1 38 88 182 28,322 0 44 44 80 16,411 -44 -102 -11,912 Mar-23 49 7 36 92 274 28,414 0 47 47 127 16,458 -45 -147 -11,956 Apr-23 45 14 36 95 369 28,509 0 55 55 182 16,513 -40 -187 -11,996 May-23 35 13 39 87 456 28,596 0 52 52 234 16,565 -35 -222 -12,032 Jun-23 36 6 41 83 539 28,679 0 53 53 287 16,618 -30 -252 -12,062 Jul-23 48 20 54 121 660 28,800 0 46 46 333 16,664 -75 -327 -12,136 Aug-23 29 7 44 80 740 28,880 0 39 39 372 16,703 -41 -368 -12,177 Sep-23 27 3 41 71 811 28,951 0 53 53 425 16,756 -18 -386 -12,195 Oct-23 22 0 39 61 872 29,012 0 45 45 470 16,801 -16 -402 -12,211 Nov-23 26 3 47 76 947 29,088 0 49 49 519 16,850 -27 -428 -12,238 Dec-23 21 3 44 69 1,016 29,156 0 42 42 561 16,891 -27 -455 -12,265 2023 Totals 433 79 504 1,016 0 561 561 -455 Produced Fluids Injected Fluids Net Injection (Injection - Production) Eni Petroleum, Alaska Page 8 ATTACHMENT C: 2023 OKOP Pressure Report, Form 10-412 6. Oil Gravity: 21 - 26 8. Well Name and Number: 9. API Number 50XXXXXXXXXXXX NO DASHES 10. Type See Instructions 11. AOGCC Pool Code 12. Zone 13. Perforated Intervals Top - Bottom TVDSS 14. Final Test Date 15. Shut-In Time, Hours 16. Press. Surv. Type (see instructions for codes) 17. Temp.18. Depth Tool TVDSS 19. Final Observed Pressure at Tool Depth 20. Datum TVDSS (input) 21. Pressure Gradient, psi/ft. 22. Pressure at Datum (cal) ODSK-13 50703206070000 O 576100 Kuparuk 6117 - 6195 12/15/23 87,160 PFO 163 6,102 3,641 6,050 0.45 3,618 ODSK-38 50703205840000 WI 576100 Kuparuk 6013 - 6041 8/5/2023 93 PFO 120 5,839 2,439 6,050 0.45 2,533 23. All tests reported herein were made in accordance with the applicable rules, regulations and instructions of the Alaska Oil and Gas Conservation Commission. I hereby certify that the foregoing is true and correct to the best of my knowledge. Production Engineer April 1, 2024 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION RESERVOIR PRESSURE REPORT 1. Operator:2. Address: Eni US Operating Company Inc. (Eni US)3700 Centerpoint Drive, Suite 500, Anchorage, AK 99503 7. Gas Gravity: Keith Lopez Signature Printed Name Title Date Oooguruk Oooguruk-Kuparuk 6050 0.7 3. Unit or Lease Name:4. Field and Pool:5. Datum Reference: Eni Petroleum, Alaska Page 9 ATTACHMENT D: OKOP Reservoir Pressure Map – December 2023 Eni Petroleum, Alaska Page 10 ATTACHMENT E: OKOP Annual Reservoir Properties Report, Form 10-428 3. Field and Pool Code: 4. Pool Name 5. Reference Datum (ft TVDSS) 6. Temperature (°F) 7. Porosity (%) 8. Permeability (md) 9. Swi (%)10. Oil Viscosity @ Original Pressure (cp) 11. Oil Viscosity @ Saturation Pressure (cp) 12. Original Pressure (psi) 13. Bubble Point or Dew Point Pressure (psi) 14. Current Reservoir Pressure (psi) 15. Oil Gravity (°API) 16. Gas Specific Gravity (Air = 1.0) 17. Gross Pay (ft) 18. Net Pay (ft) 19. Original Formation Volume Factor (RB/STB) 20. Bubble Point Formation Volume Factor (RB/STB) 21. Gas Compressibility Factor (Z) 22. Original GOR (SCF/STB) 23. Current GOR (SCF/STB) 576100 Kuparuk 6050 160 13 - 32 50 - 100 30 2 - 4 2 - 4 3150 2600 2500 21 - 26 0.7 3 - 50 1 - 40 1.26 1.24 0.7 450 615 4/1/2024 Production Engineer I hereby certify that the foregoing is true and correct to the best of my knowledge. Signature Title Printed Name Keith Lopez Date STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION ANNUAL RESERVOIR PROPERTIES REPORT 1. Operator:2. Address: Eni US Operating Company Inc. (Eni US)3700 Centerpoint Drive, Suite 500, Anchorage AK 99503