The URL can be used to link to this page

Home My WebLink About2023 Schrader Bluff Oil Pool 2023 Annual Reservoir Surveillance Report Nikaitchuq Schrader Bluff Oil Pool (NSBOP) Nikaitchuq Field April 1, 2024 Eni Petroleum – Alaska Development 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 .......................................... 4 3.0 Results and Analysis of Production and Injection Log Surveys, Tracer Surveys, Observation Well Surveys and Any Other Special Monitoring ....................................................................................... 5 4.0 Review of Pool Production Allocation Factors and Issues Over the Year .................................... 6 5.0 Reservoir Management Summary........................................................................................... 7 ATTACHMENT A NSBOP Well Location Map ......................................................................... 9 ATTACHMENT B 2023 NSBOP Voidage Balance by Month ................................................ 10 ATTACHMENT C NSBOP Pressure Report, Form 10-412..................................................... 11 ATTACHMENT D NSBOP Reservoir Pressure December 2023 ............................................ 12 ATTACHMENT E NSBOP Annual Reservoir Properties Report, Form 10-428 ...................... 13 ATTACHMENT F NSBOP Injection Well Mechanical Integrity Testing (AIO 36, Rule 8) ........ 14 Eni Petroleum – Alaska Development Page 1 1.0 Progress of the Enhanced Recovery Project The Nikaitchuq Field (NF) is one of two Eni US Operating Co. Inc. (Eni) offshore-operated fields in Alaska. It is located offshore in East Harrison Bay, near the Colville River Delta in the Beaufort Sea. The Nikaitchuq Schrader Bluff Oil Pool (NSBOP) development utilizes an onshore gravel pad located at the Oliktok Point Pad (OPP) and the offshore Spy Island Drill site (SID). The onshore development contains standalone multiphase processing facilities. SID is a drilling location from which offshore production is imported via a flowline bundle to OPP. Processed oil sales are exported through a dedicated pipeline tied into the Kuparuk River Unit (KRU) facilities, operated by ConocoPhillips Alaska, Inc. (CPAI), which exports the oil to the Trans-Alaska Pipeline System (TAPS). The Alaska Oil and Gas Conservation Commission (AOGCC) issued pool rules under Conservation Order No. 639 (CO 639) and Area Injection Order 36 (AIO 36) authorizing the injection of fluids for pressure maintenance and enhanced oil recovery in the NSBOP. At the end of 2023, there were 52 active NSBOP development wells, including 29 production (8 OPP, 21 SID) and 23 injection (6 OPP, 17 SID) wells. Two injection (OI15-S4 and OI24-08) and six producing (OP03-P05, OP09-S1, OP18-08 OP19-T1N, SP18-N5, and SP40-E4) wells were shut-in or inactive. Dual lateral wellbores have been completed in 28 of the 35 production wells (8 OPP, 20 SID). Excluding one well, these wells target the OA sand of the NSBOP. One inactive development well, OP19-T1N, was drilled and completed to test the potential of the N sand development. Additionally, two disposal wells (1 OPP, 1 SID) and three Ivishak source water wells (3 OPP) are active in supporting operations. The existing and planned NSBOP wells are shown in Attachment A. In 2023, Eni continued rig (RWO) and rigless (RLWO) well operations at OPP and SID. Eight rig activities (2 OPP, 6 SID), including seven workovers (2 OPP, 5 SID), were performed, and one new dual lateral well, SP42-NE4, was drilled. Twenty-six rigless well operations (RLWO) were performed (16 OPP, 24 SID) on 27 wells (9 OPP, 18 SID). Both types of activities are summarized in Table 1 below. Eni Petroleum – Alaska Development Page 2 Table 1: 2023 Nikaitchuq Field Well Intervention Activities Action #Well Name Well Type Location Reservoi r Action Type Objectives / Description Completion date 1 SD37-DSP1 DSP SID OA Sand Rigless D&D hole finder 1/12/2023 2 SD37-DSP1 DSP SID Torok RWO Tubing - annulus communication. Replace 4-1/2” upper disposal completion string 2/2/2023 3 OP-I2 WI OPP OA Sand Rigless Memory gauge 2/3/2023 4 OP-I2 WI OPP OA Sand Rigless Leak detection 2/11/2023 5 SP04-SE5 OP SID OA Sand RWO Run new tubing 2/12/2023 6 OI06-05 WI OPP OA Sand RWO Replace completion 2/22/2023 7 OI07-04 WI OPP OA Sand RWO Run new injection completion 3/17/2023 8 OP-I2 WI OPP OA Sand Rigless Caliper run 3/18/2023 9 SP42-NE4 OP SID OA Sand Drilling Drilling 3/22/2023 10 OP03-P05 OP OPP OA Sand RWO ESP failure 3/30/2023 11 OI20-07 WI OPP OA Sand RWO Replace tubing and run a new packer 4/15/2023 12 OP-I2 WI OPP OA Sand Rigless Patch Install 4/17/2023 13 SI34-W6 WI SID OA Sand Rigless Combo MIT 4/17/2023 14 SP42-NE4 L1 OP SID OA Sand Drilling Drilling 4/20/2023 15 SI06-NE1 WI SID OA Sand Rigless ACX log 4/26/2023 16 OI13-03 WI OPP OA Sand RWO Replace tubing and run a new packer 5/7/2023 17 SP42-NE4 OP SID OA Sand Rigless Flow back test 5/7/2023 18 SP21-NW1 OP SID OA Sand RWO Sand plug around ESP 5/12/2023 19 SP36-W5 OP SID OA Sand RWO ESP electrical failure 5/27/2023 20 SP10-FN5 OP SID OA Sand RWO ESP electrical failure 6/3/2023 21 SI34-W6 WI SID OA Sand Rigless Combo MIT 6/25/2023 22 SP30-W1 OP SID OA Sand RWO ESP electrical failure 7/27/2023 23 OI11-01 WI OPP OA Sand Rigless Leak detection, patch instalation 8/19/2023 24 SD37-DSP1 DSP SID Torok Rigless ACX log 10/24/2023 25 OI24-08 WI OPP OA Sand Rigless Leak detection 12/9/2023 26 SD37-DSP1 DSP SID Torok Rigless Tubing punch 12/14/2023 Eni Petroleum – Alaska Development Page 3 The primary causes for well shut-ins and workovers are electrical submersible pump (ESP) failures, solids plugging, and tubing corrosion. At the end of 2023, four producing wells (OP03-P05, OP09-S1, OP18-08, SP18-N5 and SP40-E4) and two injection wells (OI15-S4 and OI24-08) were shut in pending interventions. At the end of 2023, the planned well interventions for 2024 include OP03-P05 (ESP replacement, clear solids), OP09-S1 (ESP replacement), OP18-08 (ESP replacement, clear solids), SP18-N5 (ESP replacement, clear solids), and OI24-08 (restore or demonstrate well integrity). Other well interventions will be conducted, as needed, if materials and funding are available. Plans to repair or replace the OI15-S4 injection well are under review. The SP40-E4 peripheral producer, drilled and completed in 2022, produced primarily water, was shut-in on October 23, 2022, and is being evaluated for recompletion as an injector. 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 Nikaitchuq 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. Engineering work commenced on an integrated model to connect the reservoir, wells, and surface production equipment to facilitate production optimization. Modeling analyses were also started with the Multiphase pumps at SID (MPP) to optimize their operation. Routine maintenance was performed on the four power generation turbines and two gas compressors at the Oliktok Production Pad (OPP). Maintenance was performed on Train 2 Inlet and Low Pressure Separators during 2023. The separators were cleaned, inspected and partially recoated to be API inspected and certified. External visual inspection has been performed on the tanks and vessels per the Integrity Inspection plan. In addition, cathodic protection inspections were completed on the sub-sea production flowline from the offshore Spy Island Drill Site (SID) to OPP, as well as Atmospheric Corrosion Inspection (3 years) on the Sales oil pipeline to ensure the mechanical integrity of the flowline bundle. The river overflow inspections are completed annually to verify the depth of cover over the buried subsea pipelines, including modeling water flows over the ice, strudel and scour identification, and bathymetric surveys. The NSBOP observed that field oil production and water cuts align with Eni's reservoir model expectations through additional drilling, well interventions, and consistent injection. The annual average daily NSBOP production during 2023 was 15,999 BOPD. Total oil production from the NSBOP during 2023 was 5,839,694 barrels and is 80,713,423 barrels since field startup through 2023. The annual average producing GOR and watercut were 144 SCF/STBO and 75%, respectively. The annual average daily NSBOP water injection during 2023 was 83,092 BWPD. Cumulative water injection in the NSBOP during 2023 was 30,328,756 barrels and 209,235,459 barrels since the start of the project. The 2023 annual and cumulative voidage replacement ratios were 1.27 and 1.05, respectively. Attachment B details the 2023 voidage balance for the NSBOP. Under AIO 36 Rule 8, Attachment F summarizes the mechanical integrity testing results and plans for the NSBOP injection wells. Eni Petroleum – Alaska Development Page 4 Results and Analysis of Reservoir Pressure Surveys within the Pool Twelve pressure surveys recorded in 2023 were reported from eleven wells. There were nine pressure surveys following worked-over wells, one injector pressure fall off while shut-in due to integrity issues, and one new well initial pressure. The pressure survey results are summarized in the NSBOP Pressure Report, Form 10-412 (refer to Attachment C). The NSBOP Reservoir Pressure Map, Attachment D, depicts the estimated NSBOP average pressures for December 2023, including shut-in and producing wells. The estimated average NSBOP reservoir pressure is currently 1,700 psi at -3,760 ft. TVDss (datum). The 2023 average annual producing GOR was 144 SCF/STBO; the December 2023 GOR averaged 134 SCF/STBO (refer to Attachment E, NSBOP Annual Reservoir Properties Report Form 10-428). Reservoir management utilizes continuous pressure monitoring in both producers and injectors. In addition to surface gauges measuring tubing pressures, Nikaitchuq oil producers are equipped with downhole ESP gauges, providing both pump intake pressures (PIP) and discharge pressures, which allow real-time bottom-hole pressure (BHP) monitoring. The data are used to optimize production while monitoring signs of sand production, rising water cuts (WC), increasing gas-oil ratios (GOR) and balancing voidage. During extended shut-ins, the BHP data provides valuable surveillance and model input. Additionally, downhole gauges have been installed in ten injection wells to assist in monitoring and calibration; seven systems are currently functional (OI06-05, OI07-04, SI02-SE6, SI06-NE1, SI15-E1, SI25-N2, SI43-NE3). Three systems no longer transmit accurate data (OI11-01, SI14-N6, and SI20-N4). OP-I2 had a temporary memory gauge installation for the polymer test. The gauge was removed in early 2023 and was found to have stopped recording data on November 14, 2022. Following the installation of the tubing patch in the well, a downhole memory gauge was installed on April 11, 2023, and will be retrieved in 2024 (388- day design run-life). Water injection targets maximizing voidage replacement and throughput to optimize production and reserves. Consequently, injection pressures target the maximum pressure not to exceed the fracture gradient, which can lead to early breakthrough events and poor flood conformance; injection wellhead pressures, and if available, BHPs are continuously monitored and injection rates adjusted accordingly. The operational target injection pressure limits are significantly lower than the sand face limit of 2,400 psi prescribed by AIO 36, Rule 4 so that injected fluids do not fracture the arresting or confining intervals or migrate out of the approved injection strata. Maps of the field pressures, including shut-in and active wells, refer to Attachment D, are used for monitoring performance, reservoir management, and modeling. In December 2023, the datum referenced average NSBOP producing well pressure was 700 psi (range: 394 psi to 1,500 psi), the average injection well pressure was 2,011 psi (range: 800 psi, OI15-S4 estimated long- term shut-in, to 2,240 psi, OP-I02), and areas outside the influence of the development are at the initial pressure of 1,700 psi. Eni Petroleum – Alaska Development Page 5 2.0 Results and Analysis of Production and Injection Log Surveys, Tracer Surveys, Observation Well Surveys and Any Other Special Monitoring Reservoir surveillance is routinely conducted to monitor well and reservoir performance, recommend operating condition changes, perform rate allocations, propose optimization actions, and address and solve general issues. Production allocations have been performed continuously using well models calibrated with the most recent well tests. Reservoir surveillance and monitoring activities in 2023 for the NSBOP included: • Downhole and wellhead pressure and real-time temperature measurements, • ESP main performance parameter monitoring (e.g., current, voltage, motor temperature), • Distributed Temperature Systems (DTS, fiber optics) monitoring lateral conformance (fiber optics) in three wells: OI07-04, SI14-N6, and SI20-N4, • Corrosion monitoring, • Well performance indicative of tubing leaks or failing ESPs, • Hydrocarbon and produced water surface sampling, • Tracer sampling and interpretation in the OP-I02 polymer pilot area, • Well production tests. Initially, three OPP injectors (OI06-05, OI07-04, OI11-01) and two SID injectors (SI14-N6, SI20-N4) were equipped with DTS fiber optics to quantify and monitor conformance along the horizontal injection intervals over time. The DTS on OI11-01 and OI06-05 have been taken out of commission. During 2023, no DTS fall-off testing or analyses were performed. Eni has concluded an EOR pilot project focused on using polymer injection to enhance the field's overall recovery. The pilot was planned in three phases: • Phase 1: Short-term Injectivity test (completed in May 2019), • Phase 2: One-year pilot injection test (completed in December 2022), and • Phase 3: Full-Field Application (under evaluation). Tracer interpretation, dynamic modeling and cost-benefit analysis are ongoing. Eni Petroleum – Alaska Development Page 6 3.0 Review of Pool Production Allocation Factors and Issues Over the Year Production from all wells producing from the NSBOP is commingled at the surface into a common production line. Theoretical production for individual wells from the pool is calculated daily using well test allocations consistent with CO 639, Rule 8. Wells are tested at least twice per month using Schlumberger Vx multiphase meters. Daily theoretical production per well is calculated based on the last valid well test and the amount of time that the well was on production for a given day: oductionlDailyTheoreticaBOPDxDailyRate dayMinutes Minutes Welltest produced Pr)( 1440 = The daily oil allocation factor for the field is calculated by dividing the total LACT meter production for the day by the sum of the theoretical daily production for each well. Subsequently, daily allocated production is assigned to each well by multiplying its theoretical daily production by the daily allocation factor. The average 2023 NSBOP oil allocation factor was 0.9583 as detailed in Table 2 below. Month Average Daily Allocation Factor January 0.9668 February 0.9260 March 0.9533 April 0.9545 May 0.9561 June 0.9634 July 0.9539 August 0.9711 September 0.9700 October 0.9555 November 0.9634 December 0.9653 2023 Average 0.9583 Table 2: Average Daily Field Allocation Factors for 2023 Eni Petroleum – Alaska Development Page 7 4.0 Reservoir Management Summary The Alaska Oil and Gas Conservation Commission (AOGCC) issued pool rules under Conservation Order No. 639 (CO 639) and Area Injection Order 36 (AIO 36) authorizing the injection of fluids for pressure maintenance and enhanced oil recovery in the NSBOP. Consistent with the orders, the overall reservoir management objective is to maximize economic recovery and minimize project risks while maintaining the highest environmental and safety standards. The primary recovery mechanism for the field is waterflooding. Producers and injectors have been drilled in pairs, located side by side and completed with horizontal drains in the OA sands. Oil producer and water injector targets are defined based on historical producer-injector waterflood responses, pressure trends, ESP constraints and well integrity limits. Water injection targets maximizing voidage replacement and throughput to maximize production and reserves. Injection pressures target the maximum pressure not to exceed the fracture gradient, which can lead to early breakthrough events and poor flood conformance. The hydrocarbon present in the Schrader Bluff is viscous and has low expansion energy and little potential for gas expansion. Production and recovery are a result of waterflood displacement. Artificial lifting is crucial for well productivity; thus, ESP failures represent one of the most significant risks to NSBOP production. Other considerable risks are tubing, manifold and pipeline leaks due to corrosion. Studies to understand and mitigate these risks are ongoing. This integrity issue continues to negatively affect production, is costly to diagnose and is remediated through the tubing and ESP replacements. Well constraints for injectors and producers are based on historical analog field and well performance, ESP capacity, pressure trends, waterflood pattern behavior, well integrity conditions and ongoing operations. Individual well, pattern and field performance are routinely reviewed and discussed with the Anchorage, Houston and Milan teams; pump intake targets and injection well rate targets and pressure limits are defined and communicated to the lead field operators along with guidelines to implement changes. The typical minimum pump intake pressure targets 400 to 500 psi at the sand face but is occasionally higher due to pump capacity limits, gas locking at low pressures, sand production, or other performance concerns. The maximum injection pressure limit target for all the wells is below the formation fracture pressure and is continuously monitored by surface wellhead pressures; occasionally, lower injection limits are implemented for diagnostic or operational purposes. Reservoir management activities will continue in the NSBOP with the objective to: • Maximize daily volumes and value by optimizing hydrocarbon production; • Minimize risk exposure to key producing wells and maintain well integrity; • Proactively define and develop mitigation plans related to water production; • Proactively acquire reservoir performance data critical to reservoir management and overall recoverable volumes determination; • Ensure timely execution of reservoir surveillance plans, workovers, re-completions, and infill drilling; • Update current reservoir simulations and studies to reproduce the field behavior; Eni Petroleum – Alaska Development Page 8 • Find cost-effective solutions to optimize production. Individual well and pattern surveillance data will continue to be collected to monitor performance and improve recovery. A simulation model has been maintained and updated to assist reservoir development and flood management decisions in the NSBOP. Eni Petroleum – Alaska Development Page 9 ATTACHMENT A NSBOP Well Location Map Eni Petroleum – Alaska Development Page 10 ATTACHMENT B 2023 NSBOP Voidage Balance by Month Month Oil, MSTBO Produced Gas, MMSCF Water, MBBL Total Voidage, MRB Year Cum Voidage, MRB Cum since start-up, MRB Water Injection, MSTB Water 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>>175,062 Cum Since Start-Up thru 2022 >>178,907 3,844 Jan-23 524 78 1,525 2,134 2,134 177,196 2,685 2,685 2,685 181,591 551 551 4,395 Feb-23 455 67 1,396 1,925 4,058 179,120 2,343 2,343 5,027 183,934 418 969 4,813 Mar-23 507 78 1,492 2,086 6,144 181,207 2,535 2,535 7,562 186,468 448 1,417 5,262 Apr-23 478 74 1,392 1,953 8,098 183,160 2,362 2,362 9,924 188,830 409 1,826 5,670 May-23 481 73 1,352 1,913 10,011 185,073 2,553 2,553 12,477 191,384 640 2,466 6,311 Jun-23 479 71 1,355 1,911 11,922 186,984 2,576 2,576 15,053 193,960 665 3,131 6,976 Jul-23 511 73 1,422 2,009 13,931 188,993 2,547 2,547 17,600 196,507 538 3,669 7,514 Aug-23 510 72 1,470 2,056 15,987 191,049 2,510 2,510 20,110 199,017 454 4,124 7,968 Sep-23 486 68 1,438 1,994 17,981 193,043 2,506 2,506 22,616 201,523 512 4,636 8,480 Oct-23 496 67 1,490 2,053 20,033 195,096 2,685 2,685 25,301 204,208 632 5,268 9,113 Nov-23 459 60 1,380 1,898 21,931 196,994 2,548 2,548 27,849 206,756 650 5,918 9,762 Dec-23 454 61 1,379 1,893 23,825 198,887 2,479 2,479 30,329 209,235 586 6,504 10,348 2023 Totals 5,840 843 17,091 23,825 30,329 30,329 6,504 Produced Fluids Injected Fluids Net Injection Eni Petroleum – Alaska Development Page 11 ATTACHMENT C NSBOP Pressure Report, Form 10-412 6. Oil Gravity: 13 - 19 8. Well Name and Number: 9. API Number 50XXXXXXXXXXXX NO DASHES 10. Type See Instructions 11. AOGCC Pool Code 12. Zone 13. Perforated Interval Top TVDSS 14. Final Test Date 15. Shut-In Time, Hours 16. Press. Surv. Type (see instructions for codes) 17. Temp., F 18. Depth Tool TVDSS 19. Final Observed Pressure at Tool Depth, psi 20. Datum TVDSS (input) 21. Pressure Gradient, psi/ft. 22. Pressure at Datum (cal), psi OP03-P05 50029233960000 O 561100 Schrader Bluff 3,631 3/29/2023 311 SBHP 72 3,436 1,195 3,760 0.45 1,340 OP03-P05 50029233960000 O 561100 Schrader Bluff 3,631 12/31/2023 2,549 PBU 73 3,436 1,333 3,760 0.41 1,467 OP09-S01 50029234480000 O 561100 Schrader Bluff 3,851 12/31/2023 815 PBU 75 3,498 905 3,760 0.41 1,013 OP10-09 50029234390000 O 561100 Schrader Bluff 3,637 1/31/2023 6,185 SBHP 70 3,531 993 3,760 0.45 1,096 OP18-08 50029234490000 O 561100 Schrader Bluff 3,432 12/31/2023 167 PBU 85 3,384 488 3,760 0.41 644 SI06-NE1 50629236580000 WI 561100 Schrader Bluff 3,986 12/21/2023 550 PFO 84 3,925 1,526 3,760 0.44 1,453 SP04-SE5 50629235370000 O 561100 Schrader Bluff 4,052 2/11/2023 335 SBHP 82 3,911 1,167 3,760 0.45 1,099 SP10-FN5 50629234730000 O 561100 Schrader Bluff 3,845 6/2/2023 671 SBHP 80 3,702 1,201 3,760 0.45 1,227 SP21-NW1 50629235200000 O 561101 Schrader Bluff 3,580 5/11/2023 1,946 SBHP 70 3,323 1,085 3,760 0.45 1,280 SP30-W1 50629234760000 O 561102 Schrader Bluff 3,625 7/26/2023 888 SBHP 75 3,598 1,003 3,760 0.45 1,075 SP36-W5 50629234920000 O 561103 Schrader Bluff 3,463 5/27/2023 1,691 SBHP 67 3,153 1,233 3,760 0.45 1,505 SP42-NE4 50629237250000 O 561104 Schrader Bluff 4,095 5/3/2023 Initial SBHP 91 4,079 2,071 3,760 0.49 1,915 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. Signature Title Production Engineer Printed Name Keith Lopez Date April 1, 2024 3. Unit or Lease Name:4. Field and Pool:5. Datum Reference:7. Gas Gravity: NIKAITCHUQ NIKAITCHUQ-SCHRADER BLUFF OIL 3760 0.6 Eni US Operating Company Inc. (Eni US)3700 Centerpoint Drive, Suite 500, Anchorage, AK 99503 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION RESERVOIR PRESSURE REPORT 1. Operator:2. Address: Eni Petroleum – Alaska Development Page 12 ATTACHMENT D NSBOP Reservoir Pressure December 2023 Eni Petroleum – Alaska Development Page 13 ATTACHMENT E NSBOP 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) 561100 Schrader Bluff 3760 70 -90 15 -35 50 - 1000 13 - 45 90 - 200 70 - 180 1700 600-1200 1700 13 -19 0.6 30 - 40 25 - 40 1.045 1.05 0.7 - 0.8 80 - 140 134 I hereby certify that the foregoing is true and correct to the best of my knowledge. STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION ANNUAL RESERVOIR PROPERTIES REPORT 1. Operator:2. Address: Eni Petroleum 3700 Centerpoint Drive , Suite 500, Anchorage, Alaska 99503 Printed Name Title Date 1-Apr-24Keith Lopez Production EngineerSignature Eni Petroleum – Alaska Development Page 14 ATTACHMENT F NSBOP Injection Well Mechanical Integrity Testing (AIO 36, Rule 8) Well PTD #Status Date of Last Test Result Frequency (Years) Due Date Injecting since MIT due date? OP-I2 (inj)206-144 WINJ 04/19/23 P 4 04/19/27 Yes OI06-05 210-165 WINJ 03/10/23 P 4 03/09/27 Yes OI07-04 210-153 WINJ 04/05/23 P 4 05/05/27 Yes OI11-01 210-106 WINJ 07/07/23 P 2 (AA)07/06/25 Yes OI13-03 211-100 WINJ 05/23/23 P 4 05/23/27 Yes OI15-S4 211-141 WINJ 03/30/22 F 4 03/29/26 Yes OI20-07 211-140 WINJ 04/25/23 P 4 04/25/27 Yes OI24-08 211-130 WINJ 12/05/23 P 2 (AA)12/04/25 Yes SI02-SE6 220-019 WINJ 12/15/21 P 4 12/15/25 Yes SI06-NE1 219-165 WINJ 05/04/23 P 2 (AA)05/03/25 Yes SI07-SE4 214-100 WINJ 02/26/22 P 4 02/26/26 Yes SI11-FN6 213-128 WINJ 08/03/22 P 4 08/03/26 Yes SI13-FN4 212-156 WINJ 04/30/21 P 4 04/30/25 Yes SI14-N6 213-194 WINJ 04/30/21 P 4 04/30/25 Yes SI15-E1 221-111 WINJ 03/13/22 P 4 03/13/26 Yes SI17-SE2 214-041 WINJ 04/30/21 P 4 04/30/25 Yes SI19-FN2 213-043 WINJ 04/30/21 P 4 04/30/25 Yes SI20-N4 212-029 WINJ 04/30/21 P 4 04/30/25 Yes SI25-N2 212-090 WINJ 04/30/21 P 4 04/30/25 Yes SI26-NW2 214-157 WINJ 08/14/21 P 4 08/14/25 Yes SI29-S2 212-006 WINJ 06/26/21 P 4 06/26/25 Yes SI32-W2 213-013 WINJ 04/30/21 P 4 04/30/25 Yes SI34-W6 215-016 WINJ 06/25/23 P 2 (AA)06/24/25 Yes SI35-W4 213-101 WINJ 04/30/21 P 4 04/30/25 Yes SI43-NE3 222-115 WINJ 01/01/23 P 4 01/01/27 Yes