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Home My WebLink About2020 Schrader Bluff Oil Pool Annual Reservoir Surveillance Report Nikaitchuq Schrader Bluff Oil Pool (NSBOP) Nikaitchuq Field April 1, 2021 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 ........................................... 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 ..................................... 6 5.0 Reservoir Management Summary .............................................................................................. 7 ATTACHMENT A: NSBOP Well Location Map ............................................................................................... 9 ATTACHMENT B: 2020 NSBOP Voidage Balance by Month ....................................................................... 10 ATTACHMENT C: NSBOP Pressure Report, Form 10-412 ............................................................................ 11 ATTACHMENT D: NSBOP Reservoir Pressure Map – December, 2020 ....................................................... 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 Drillsite (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-in to 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 2020, there were 52 active NSBOP development wells, including 30 production (11 OPP, 19 SID) and 22 injection (8 OPP, 14 SID) wells. Dual lateral wellbores have been completed in 22 of the production wellbores (8 OPP, 14 SID). 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. Future development plans include drilling seven additional OA wells, adding four laterals to existing wells, and recompleting OP19-T1N to further assess the N sand development potential. Under the current economic environment, this scenario will be completed in 2025, but it is subject to change. The existing and planned NSBOP wells are shown in Attachment A. In 2020, Eni continued rig activities at both OPP and SID. However, due to the logistical interference of the COVID-19 pandemic, the reduced demand for oil, and associated low oil prices both rigs were shut down and cold stacked from April into November. In total, twelve rig activities (6 OPP, 6 SID) including ten workovers (6 OPP, 4 SID) and two SID drilling operations were conducted in eleven wells (5 OPP, 6 SID) including the SD37-DSP01 disposal well and the OP22-WW03 Ivishak source water well as summarized in Table 1 below. Table 1: 2020 Nikaitchuq Field Drilling Rig Activity Well Name Well Type Site Activity Rig Name Description Shut-In Date Rig Completion Date OP05-06 Producer OPP Workover Nordic 4 ESP upgrade 02/25/20 03/17/20 OP22-WW03 Water well OPP Workover Nordic 4 ESP failure -03/31/20 OP17-02 Producer OPP Workover Nordic 4 Replace corroded tubing 03/24/20 04/24/20 OP12-01 Producer OPP Workover Nordic 4 ESP failure 08/09/20 12/03/20 OP17-02 Producer OPP Workover Nordic 4 Tubing connection leak 10/29/20 12/12/20 OP16-03 Producer OPP Workover Nordic 4 ESP failure 08/03/20 12/21/20 SI06-NE1 New Injector SID Drilling Doyon 15 New injection well -02/17/20 SP10-FN5 L1 Producer SID Drilling Doyon 15 Drill 2nd lateral 02/18/20 03/26/20 SP04-SE5 Producer SID Workover Doyon 15 Replace corroded tubing 03/29/20 04/14/20 SD37-DSP01 Disposal well SID Workover Doyon 15 Replace corroded tubing 08/20/20 12/16/20 SP08-N7 Producer SID Workover Doyon 15 ESP failure 12/18/20 12/25/20 SP01-SE7 Producer SID Workover Doyon 15 ESP failure 01/25/20 01/03/21 Eni Petroleum – Alaska Development Page 2 The primary causes for well shut-ins and workovers are electrical submersible pump (ESP) failures and tubing corrosion. To mitigate the corrosion risk all workovers now incorporate coated tubing. At the end of 2020 four active producing wells remained shut-in pending rig interventions, which are planned in 2021. The planned and approved well interventions are: SP03-NE2 (shut-in 6/23/20 due to a plugged ESP), SP05-FN7 (shut-in 7/23/20 due to tubing corrosion), SP23-N3 (shut-in 11/21/20 due to tubing corrosion, 2nd lateral to be added) and SP27-N1 (shut-in 7/30/20 due to tubing corrosion, 2nd lateral to be added). On October 22, 2019, pursuant to AIO 36.002 polymer injection was initiated in the Oliktok Point I-2 (OP-I2) well for a one-year test to determine the effectiveness of polymer injection for improving recovery from the NSBOP. The test was cut short after 154 days due to logistical issues resulting from the COVID-19 pandemic. The shortened test period resulted in inconclusive test results. Eni plans to resume the polymer injection test in 2021 and has received Administrative Approval under AIO 36.003 to extend the test through December 31, 2022. Heat exchanger repairs at OPP were completed in September 2020, improving oil and water separation, and reducing carryover of oil into the water injection system. This work resulted in 300 to 500 BOPD in additional sales oil. Additional heat exchanger work is planned for 2021, which will further improve efficiency and capacity of the OPP facility. The SID multiphase booster pump project was successfully implemented in late 2019 and was fully operational throughout 2020. The project allows incremental production from wells currently at the maximum ESP speed by reducing the SID flowline backpressure and reducing the pump intake pressure. Through additional drilling, well interventions, and consistent injection the NSBOP observed field oil production and water cut are in line with Eni’s reservoir model expectations. However, due to impacts of COVID-19, as detailed above, workovers of shut-in wells were delayed and Alyeska Pipeline prorated production due to high inventories from April 24, 2020 thru May 22, 2020 resulting in decreased production. Annual average daily NSBOP production during 2020 was 17,919 BOPD. Total oil production from the NSBOP during 2020 was 6,558,183 barrels and is 62,584,727 barrels since field start-up thru 2020. The annual average producing GOR and watercut were 104 SCF/STBO and 69%, respectively. Annual average daily NSBOP injection during 2020 was 69,324 BWPD. Cumulative water injection in the NSBOP during 2020 was 25,372,688 barrels and 125,276,080 barrels since the start of the project. The 2020 annual and cumulative voidage replacement ratio were 1.18 and 0.99, respectively. Attachment B details the 2020 voidage balance for the NSBOP. Pursuant to AIO 36 Rule 8, Attachment F provides a summary of the mechanical integrity testing results and plans for the NSBOP injection wells. The mechanical integrity testing will be conducted on all Nikaitchuq Schrader Bluff injection wells in early 2021. Eni Petroleum – Alaska Development Page 3 2.0 Results and Analysis of Reservoir Pressure Surveys within the Pool Fourteen pressure surveys recorded in 2020 were reported from thirteen wells. 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 2020 including shut-in and producing wells. The estimated average NSBOP reservoir pressure is currently 1,680 psi at -3,760 ft. TVDss (datum). The 2020 average annual producing GOR was 104 SCF/STBO and in December 2020 the GOR averaged 92 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 also monitoring for signs of sand production, rising water cuts (WC), increasing gas-oil ratios (GOR) and balancing voidage. During extended shut-ins the BHP data also provides valuable surveillance and model input. Additionally, downhole gauges have been installed in seven injection wells to assist in monitoring and calibration; five of these systems are currently functional: OP-I2 (temporary installation for polymer test, since September 2019), OI06-05, OI07- 04, SI14-N6 and SI25-N2; two systems no longer transmit accurate data: OI11-01 and SI20-N4. Water injection targets maximizing voidage replacement and throughput in order to maximize production and reserves. Consequently, injection pressures target the maximum pressure to not 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 sandface 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 2020 the datum referenced average NSBOP producing well pressure was 806 psi (range: 410 psi to 1,736 psi), the average injection well pressure was 2,024 psi (range: 1,778 psi to 2,157 psi), and areas outside the influence of the development are at the initial pressure of 1,700 psi. Eni Petroleum – Alaska Development Page 4 3.0 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 and to recommend changes in operating conditions, perform rate allocations, propose optimization actions and address and solve general issues. Production allocations have been performed continuously using well models that are calibrated with the most recent well tests. Reservoir surveillance and monitoring activities in 2020 for the NSBOP included:  Downhole and wellhead pressure and temperature real time 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-I2 polymer pilot area,  Well production tests,  Continuation of the polymer flood testing pilot phase at the OP-I2 well, and  Planning and designing a test of the N-Sand in OP19 using a jet pump for lift. Resman oil and water tracers were installed in SP03-NE2 a dual lateral well completed in November 2019. A restart profile was planned to be conducted in 2020 but the ESP plugged off with solids in June 2020 and the well remains shut-in. 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 the conformance along the horizontal injection intervals and monitor it over time. The DTS on the OI11-01 and OI06-05 were taken out of commission. During 2020, due to investment restrictions planned DTS fall-off testing and analyses were postponed to 2021. Eni is currently performing an EOR pilot project focused on the use of polymer injection to enhance overall recovery of the field. The pilot is planned in three phases:  Phase 1: Short-term Injectivity test (completed in May 2019),  Phase 2: One year pilot injection test (initiated in late 2019, shutdown in March 2020 due to COVID19), and  Phase 3: Full-Field Application (dependent on Phase 2 results and further review) The first phase focused on assessing the feasibility of the activity by monitoring injection well performance during polymer injection. For this stage, a 60 day injectivity test was performed in Eni Petroleum – Alaska Development Page 5 the OPP area with four wells each tested for two weeks with continuous polymer injection. Testing was conducted from March 26, 2019 thru Friday, May 24, 2019. The wells tested were OI06-05, OI07-04, OP-I2 and OI24. For each well a range of viscosities were tested, resulting in no detrimental impact seen on any of the wells. All downhole pressures limits were honored. The primary conclusion of the Phase 1 test is that the polymer selected for this study can be safely and effectively injected into the Nikaitchuq reservoir. This conclusion cleared the way for a long- term polymer injection pilot to evaluate the benefit of polymer injection on reservoir production. For Phase 2, the OP-I2 injection well, already tested in Phase 1, was selected as the long term pilot test candidate well. The planned duration of the test is 12 months. Targets for polymer injection rates, and concentrations were determined from a simulation study conducted by the Eni Milan EOR team. The pilot was initiated on October 22, 2019 with injection of tracers early in the test phase with continuous sampling of offset production wells planned at least through 2020. A downhole gauge was run in OP-I2 and periodic falloffs are conducted to assist in modeling the performance. Unfortunately, due to the COVID-19 pandemic operational disruption the polymer injection pilot was shut down on March 23, 2020. Water injection continues along with bi-monthly offset producing well sampling for tracer studies. Current plans are to restart Phase 2 in 2021. Then, depending on the outcome of Phase 2, a full field polymer injection multidisciplinary feasibility study will be carried out, in order to evaluate the full field application and the required surface modifications to the existing facility network. Eni Petroleum – Alaska Development Page 6 4.0 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 on a daily basis by using well test allocations consistent with CO 639, Rule 8. Wells are tested at least twice per month using Schlumberger Vx mult-phase 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 actual total LACT meter production for the day by the sum of the theoretical daily production for each individual well. Subsequently, daily allocated production is assigned to each well by multiplying its theoretical daily production by the daily allocation factor. The average 2020 NSBOP oil allocation factor was 1.0166 as detailed in Table 2 below. Table 2: 2020 Nikaitchuq Field Drilling Rig Activity Month Average Daily Allocation Factor January 1.0232 February 1.0345 March 1.0138 April 1.0021 May 1.0187 June 1.0153 July 1.0041 August 1.0151 September 1.0235 October 1.0211 November 1.0145 December 1.0133 2020 Average 1.0166 Eni Petroleum – Alaska Development Page 7 5.0 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 in order to maximize production and reserves. Injection pressures target the maximum pressure to not 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 the well productivity, thus ESP failures represent one of most impacting risks to NSBOP production. The other significant risk is 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 tubing and ESP replacements. Well constraints, for both 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 team; 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 sandface, 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 for all wells targets staying below the formation fracture pressure and is continuously monitored by surface wellhead pressures; occasionally, lower injection limits are implemented for diagnostic or operational purposes. Eni Petroleum – Alaska Development Page 8 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;  Resume the Polymer Injection test at OPP in 2021;  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;  Find cost-effective solutions to optimize the 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 in 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 2020 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 2019>>104,722 Cum Since Start-Up thru 2019 >>99,903 (4,818) Jan-20 628 67 1,234 1,906 1,906 106,628 2,028 2,028 2,028 101,932 122 122 (4,697) Feb-20 581 62 1,159 1,781 3,687 108,409 1,874 1,874 3,902 103,806 93 215 (4,604) Mar-20 588 64 1,207 1,838 5,526 110,248 1,968 1,968 5,870 105,774 130 345 (4,474) Apr-20 532 58 1,141 1,714 7,239 111,961 1,998 1,998 7,868 107,771 284 629 (4,190) May-20 562 59 1,259 1,858 9,098 113,820 2,125 2,125 9,993 109,896 266 895 (3,924) Jun-20 598 62 1,333 1,970 11,068 115,790 2,204 2,204 12,196 112,100 234 1,129 (3,690) Jul-20 598 66 1,366 2,010 13,078 117,800 2,317 2,317 14,513 114,416 306 1,435 (3,383) Aug-20 527 58 1,195 1,761 14,839 119,561 2,290 2,290 16,803 116,707 529 1,964 (2,855) Sep-20 489 52 1,135 1,658 16,498 121,220 2,169 2,169 18,972 118,875 510 2,474 (2,344) Oct-20 505 48 1,183 1,713 18,210 122,932 2,222 2,222 21,194 121,097 509 2,983 (1,835) Nov-20 458 43 1,091 1,571 19,782 124,504 2,102 2,102 23,296 123,199 531 3,514 (1,305) Dec-20 491 45 1,247 1,760 21,542 126,264 2,077 2,077 25,373 125,276 317 3,831 (988) 2020 Totals 6,558 684 14,549 21,542 25,373 25,373 3,831 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.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) SI06-NE1 50629236580000 WI 561100 Schrader Bluff 3,934 3/13/2020 Initial SBHP 83 3,925 1,500 3,760 0.48 1,420 OP05-06 50029234270000 O 561100 Schrader Bluff 3,778 3/18/2020 537 PBU 78 3,694 1,035 3,760 0.48 1,067 SP10-FN5 50629234730000 O 561100 Schrader Bluff 3,878 3/28/2020 935 PBU 83 3,685 1,657 3,760 0.48 1,693 SP04-SE5 50629235370000 O 561100 Schrader Bluff 4,026 4/16/2020 427 PBU 84 3,905 1,123 3,760 0.48 1,053 OP17-02 50029234310000 O 561100 Schrader Bluff 3,504 4/26/2020 795 PBU 71 3,460 1,085 3,760 0.48 1,230 OP12-01 50029234260000 O 561100 Schrader Bluff 3,565 12/5/2020 2,833 PBU 63 3,054 1,058 3,760 0.48 1,399 SP03-NE2 50629236390000 O 561100 Schrader Bluff 4,040 12/15/2020 4,712 PBU 87 4,026 1,619 3,760 0.41 1,509 SP05-FN7 50629234810000 O 561100 Schrader Bluff 3,943 12/15/2020 3,480 PBU 75 3,614 1,676 3,760 0.41 1,736 SP23-N3 50629234560000 O 561100 Schrader Bluff 3,841 12/15/2020 3,480 PBU 87 3,816 1,050 3,760 0.41 1,027 SP27-N1 50629234580000 O 561100 Schrader Bluff 3,685 12/15/2020 3,320 PBU 81 3,627 1,581 3,760 0.41 1,636 OP17-02 50029234310000 O 561100 Schrader Bluff 3,504 12/16/2020 1,152 PBU 71 3,460 1,123 3,760 0.48 1,268 OP16-03 50029234420000 O 561100 Schrader Bluff 3,403 12/22/2020 3,375 PBU 66 3,202 1,467 3,760 0.48 1,737 SP08-N7 50629235010000 O 561100 Schrader Bluff 4,014 12/27/2020 230 PBU 81 3,900 1,692 3,760 0.48 1,624 SP01-SE7 50629235420000 O 561100 Schrader Bluff 4,104 1/3/2021 8,266 PBU 87 4,049 1,096 3,760 0.48 956 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, 2021 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 NIKAITCHUQ NIKAITCHUQ-SCHRADER BLUFF OIL 3760 0.6 3. Unit or Lease Name:4. Field and Pool:5. Datum Reference: Eni Petroleum – Alaska Development Page 12 ATTACHMENT D NSBOP Reservoir Pressure December 2020 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 1680 13 -19 0.6 30 - 40 25 - 40 1.045 1.05 0.7 - 0.8 80 - 140 92 3800 Centerpoint Drive , Suite 300. Anchorage, Alaska 99503 Printed Name Title Date 1-Apr-21Keith Lopez Production Engineer I hereby certify that the foregoing is true and correct to the best of my knowledge. Signature STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION ANNUAL RESERVOIR PROPERTIES REPORT 1. Operator:2. Address: Eni Petroleum Eni Petroleum – Alaska Development Page 14 ATTACHMENT F NSBOP Injection Well Mechanical Integrity Testing (AIO 36, Rule 8) Mechanical integrity testing will be conducted on all Nikaitchuq Schrader Bluff injection wells in early 2021..