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Home My WebLink About2022 Prudhoe Satellite Oil Pools3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503 Phone: 907/777-8300 hilcorp.com Hilcorp North Slope, LLC September 15, 2022 Jeremy Price, Chair Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, AK 99501 RE: Prudhoe Bay Unit Satellite Pools Annual Reservoir Surveillance and Annual Reservoir Properties Reports July 1, 2021 – June 30, 2022 Chairman Price, Hilcorp North Slope, LLC, as operator of the Prudhoe Bay Unit, submits the enclosed Annual Reservoir Surveillance Reports and the Annual Reservoir Property Report for the Satellite Oil Pools (Aurora, Borealis, Midnight Sun, Orion and Polaris). The Annual Reservoir Surveillance Reports were prepared in accordance with the latest conservation orders for each pool. In addition, as required by 20 AAC 25.270(e), Hilcorp North Slope will simultaneously file the Annual Reservoir Properties Reports (ARPs, form 10-428) to aogcc.reporting@alaska.gov. The Operators of the Prudhoe Bay Field reserve the right to alter the content of the analyses contained in this report at any time based upon the most recent surveillance information obtained. If you have any questions regarding the reports, please contact Abbie.Barker@hilcorp.com. Thank you, Jill Fisk Asset Team Leader, Prudhoe Bay West Hilcorp North Slope, LLC Cc:Stephanie Erickson, ConocoPhillips Alaska, Inc. Greg Keith, ConocoPhillips Alaska, Inc. Becky Steen, ConocoPhillips Alaska, Inc. Todd Griffith, ExxonMobil Alaska, Production Inc. Jeff Farr, ExxonMobil Alaska, Production Inc. Gary Selisker, Chevron USA Dave Roby, AOGCC Kevin Pike, DNR, Division of Oil & Gas Aaron O’Quinn, DNR, Division of Oil & Gas Digitally signed by Jill Fisk (940) DN: cn=Jill Fisk (940), ou=Users Reason: I am approving this document Date: 2022.09.15 14:48:38 -08'00' Jill Fisk (940) 1 2022 ANNUAL SURVEILLANCE REPORT AURORA OIL POOL PRUDHOE BAY UNIT JULY 1, 2021 – JUNE 30, 2022 2 CONTENTS 1. INTRODUCTION 3 2. PROGRESS OF ENHANCED RECOVERY PROJECT IMPLEMENTATION AND RESERVOIR MANAGEMENT SUMMARY (RULE 8A) 3 3. VOIDAGE BALANCE BY MONTH OF PRODUCED AND INJECTED FLUIDS (RULE 8B) 4 4. ANALYSIS OF RESERVOIR PRESSURE SURVEYS WITHIN THE POOL (RULE 8C) 4 5. RESULTS AND ANALYSIS OF SPECIAL MONITORING (RULE 8D) 4 6. REVIEW OF POOL PRODUCTION ALLOCATION (RULE 8E) AND REVIEW OF POOL PRODUCTION ALLOCATION FACTORS AND ISSUES (RULE 4E) 5 7. FUTURE DEVELOPMENT PLANS (RULE 8F) 5 LIST OF ATTACHMENTS Figure 1: Aurora production and injection history 8 Figure 2: Aurora voidage history 8 Table 1: Aurora monthly production and injection summary 6 Table 2: Aurora cumulative voidage by fault block 7 Table 3: Aurora pressure survey detail 9 Table 4: Aurora monthly average oil allocation factors 10 Table 5: Aurora pressures by representative area 10 3 Prudhoe Bay Unit 2022 Aurora Oil Pool Annual Surveillance Report 1. INTRODUCTION This Annual Reservoir Report is being submitted to the Alaska Oil and Gas Conservation Commission in accordance with Rule 8 of Conservation Order 457B for the Aurora Oil Pool and covers the period from July 1, 2021 to June 30, 2022. 2. PROGRESS OF ENHANCED RECOVERY PROJECT IMPLEMENTATION AND RESERVOIR MANAGEMENT SUMMARY (RULE 8 A) Enhanced Recovery Projects Water injection in the Aurora Oil Pool (AOP) started in 2001. Tertiary EOR Miscible Water Alternating Gas (MWAG) started in the North of Crest (NOC) and West blocks at Aurora in 2003, Southeast Crest (SEC) in 2004, and Crest (CR) & South of Crest (SOC) in 2006. Evaluation of hydrocarbon recovery mechanisms for the Aurora Oil Pool (AOP) has been a continual process. A phased development program has been deemed appropriate due to the technical characteristics of considerable faulting, low initial oil rates, gas cap presence, and thin oil columns. This development approach employs three reservoir mechanisms throughout the field’s life to maximize commercial production. Initial development involves a period of primary production to determine reservoir performance and connectivity of drainage areas. Primary production under solution gas and aquifer influx drive, from both floodable and non-waterflood pay intervals, provides information, including production pressure data to evaluate compartmentalization and conformance, that is used to improve the depletion plan. This drilling and surveillance data influences subsequent steps in reservoir development, including proper water injection pattern layout. In areas of the AOP where injection is justified, water-flooding is initiated to improve recovery by reducing residual oil saturation and maintaining well productivity via reservoir pressure support. Tertiary EOR MWAG provides additional oil recovery by further reducing residual oil saturation. The miscible gas injection project is operated to maintain miscibility between the reservoir fluid and the injected miscible gas. There will be higher pressure in the area around injection wells and a pressure sink around the producers, which in some cases can be below minimum miscibility pressure (MMP) of approximately 2600 psi. With average reservoir pressures above the MMP, incremental EOR recovery is essentially the same even when producer region pressures below the MMP are maintained. Consequently, reservoir management guidelines for EOR are based on average reservoir pressure rather than producer pressure. Early implementation of the secondary and tertiary injection processes allows adequate time for producers to capture mobilized oil. Proper field management includes monitoring of productivity, GOR, water cut, pressure, and voidage replacement ratios. Reservoir Management Strategy The objective of the Aurora reservoir management strategy is to manage reservoir development and depletion to maximize commercial production consistent with prudent oil field engineering practices. During primary depletion, producers experienced increasing gas -oil-ratios (GORs) due to existence of an initial gas cap, primarily in the West side of the field, but also apparent in the CR and SEC areas. 4 Production was restricted to conserve reservoir energy. Beginning in mid-2001 and continuing into 2003, production from wells S-100, S-106 and S-102 was reduced to approximately half capacity, allowing injection to significantly reduce the GORs by the end of 2003. This pra ctice continued in 2004-5 with curtailment of wells S-108, S-113B and S-118. By 2006, these wells were returned to production with a notable increase in reservoir pressure and productivity in S-108. Pressure data and production performance in S-113B indicates the well is supported by a large gas-cap, so it was returned to full-time production in 2006 to capture benefits of MI injection in the area. Waterflood patterns have been designed and implemented to maintain pressure in individual reservoir compartments and areal sweep is maximized. Initial patterns were based on the understanding at the time of reservoir compartmentalization. Patterns and producer/injector ratios are being modified as development wells and surveillance data provide new information. The surveillance program emphasizes pressure monitoring, injection tracers in select patterns, and waterflood performance monitoring to support this feedback and intervention process. During the reporting period, average injection rate was 17.3 MBWIPD and 14.7 MMSCFD. Cumulative injection through June 2022 was 148.5 MMSTBW and 62.4 BCF. A total of 15 injectors have been on water injection and 4 injectors have been on MI. 3. VOIDAGE BALANCE BY MONTH OF PRODUCED AND INJECTED FLUIDS (RULE 8 B) During the reporting period, field production averaged 5.1 MBOPD, 16.8 MMSCFD (FGOR 3.2 MSCF/STB), and 16.0 MBWPD (WC 76 %). The average voidage replacement ratio was 0.90. Monthly production, injection, and voidage volumes for the reporting period are summarized in Table 1. Cumulative production, injection, and voidage replacement ratios by fault block are summarized in Table 2. Figures 1 and 2 graphically depict this information since field start-up. Plans to achieve injection withdrawal ratios consistent with the reserv oir management strategy include drilling and stimulation of injection wells as necessary and increasing water injection supply pressure to enhance injection rates where needed. A booster pump was installed at S Pad to provide increased injection pressure for low injectivity patterns. 4. ANALYSIS OF RESERVOIR PRESSURE SURVEYS WITHIN THE POOL (RULE 8 C) Reservoir pressure monitoring is performed in accordance with Rule 5 of Conservation Order 457B. A summary of reservoir pressure surveys obtained during the reporting period is shown in Table 3. 11 static pressure measurements were obtained during the reporting period, covering all active areas, as shown in Table 5. Most producers in the AOP have evidence of pressure response to injection support. For the period of July 1st, 2022 to June 30th, 2023, a minimum of one pressure survey will be taken in each of the active representative areas that contain active wells. If all active representative areas contain active wells, a minimum of five pressure surveys will be taken. 5. RESULTS AND ANALYSIS OF SPECIAL MONITORING (RULE 8 D) • S-22B: IPROF run to determine water injection splits. During the reporting period, no production logs were run in the Aurora Field. 5 6. REVIEW OF POOL PRODUCTION ALLOCATION (RULE 8 E) AND REVIEW OF POOL PRODUCTION ALLOCATION FACTORS AND ISSUES (RULE 4E) Production allocation is based on well tests and conducted in accordance with 20 AAC 25.230. Over the reporting period, the monthly average of daily oil production allocation factors fell within the range of 0.81 and 0.96. Any days with allocation factors of zero were excluded. The monthly averages of daily oil production allocation factors are shown in Table 4. 7. FUTURE DEVELOPMENT PLANS (RULE 8 F) Future development plans are discussed in the 2022 update to the Plan of Development for the Orion Participating Area, which was filed with the Division of Oil and Gas of the Alaska Department of Natural Resources on September 30, 2022, a copy of which was provided to the Commission. The Commission will be copied when the 2023 update of the Orion Plan of Development is filed with the Division. 6 TABLE 1: AURORA MONTHLY PRODUCTION AND INJECTION SUMMARY Report Oil Prod Gas Prod Water Prod Water Inj MI Inj Oil Prod Cum Gas Prod Cum Water Prod Cum Water Inj Cum Cum Total Inj (MI+Water) Net Res Voidage Net Voidage Cum Monthly VRR Date STB MSCF STB STB MSCF STB MSCF STB STB RVB RVB RVB RVB/RVB Jul-21 177,524.428,102.490,776.767,606.308,095.51,010,430.147,112,514.79,779,844.142,184,926.180,413,324.6,291 58,106,467 0.99 Aug-21 168,183.406,323.464,460.736,269.144,742.51,178,613 147,518,837 80,244,304 142,921,195 181,254,058 87,915 58,194,382 0.91 Sep-21 166,862.413,226.473,544.647,202.371,140.51,345,475 147,932,063 80,717,848 143,568,397 182,144,311 50,348 58,244,730 0.95 Oct-21 159,580.419,766.548,586.644,699.427,604.51,505,055 148,351,829 81,266,434 144,213,096 183,067,019 89,702 58,334,432 0.91 Nov-21 152,596.448,642.564,799.651,339.439,741.51,657,651 148,800,471 81,831,233 144,864,435 184,004,024 101,416 58,435,848 0.90 Dec-21 156,774.464,252.539,824.612,284.536,141.51,814,425 149,264,723 82,371,057 145,476,719 184,960,961 70,730 58,506,578 0.93 Jan-22 149,800.482,667.514,010.597,937.709,358.51,964,225 149,747,390 82,885,067 146,074,656 186,010,659 -45,360 58,461,218 1.05 Feb-22 135,910.483,473.469,822.558,285.586,672.52,100,135 150,230,863 83,354,889 146,632,941 186,943,846 9,814 58,471,032 0.99 Mar-22 171,871.651,130.525,061.554,029.634,522.52,272,006 150,881,993 83,879,950 147,186,970 187,902,359 188,181 58,659,212 0.84 Apr-22 167,544.720,413.527,042.430,162.589,548.52,439,550 151,602,406 84,406,992 147,617,132 188,706,644 382,163 59,041,375 0.68 May-22 161,072.731,892.460,970.469,198.579,368.52,600,622 152,334,298 84,867,962 148,086,330 189,544,434 280,570 59,321,945 0.75 Jun-22 127,561.494,185.280,271.433,127.346,719.52,728,183 152,828,483 85,148,233 148,519,457 190,201,190 89,469 59,411,414 0.88 7 TABLE 2: AURORA CUMULATIVE VOIDAGE BY FAULT BLOCK On Jun-22 Aurora Aurora Aurora Aurora Aurora Aurora Crest*N of Crest**E of Crest*W of Crest*S of Crest* Total Cumulative Injection (rsvb)23,756,857 57,454,960 13,197,423 81,771,116 14,020,833 190,201,190 Total Cumulative Production (rsvb)40,825,270 67,150,804 15,822,826 100,498,710 32,368,873 256,666,483 Cumulative Voidage Replacement Ratio 0.58 0.86 0.83 0.81 0.43 0.74 * Initial Gas Cap ** Solution Gas Only Bo 1.32 rsvb/stb Bg 0.84 rsvb/mscf Bw 1.02 rsvb/stb Rs 0.65 mscf/stb Bg (MI)0.62 rsvb/mscf 8 FIGURE 1: AURORA PRODUCTION AND INJECTION HISTORY FIGURE 2: AURORA VOIDAGE HISTORY 9 TABLE 3 - AURORA PRESSURE SURVEY DETAIL 6. Oil Gravity: 0.9SG/25 API 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. B.H. 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) S-103 500292298100 O 640120 6652-6670,6707-6715,6723-6729,6806-6818,6844- 6850,6671-6682,6735-6740,6688-6701,6682-6683,6828- 6839,6670-6671 6/15/2022 364 SBHP 4744 2008 6700 0.44 2868 S-106 500292299900 O 640120 6759-6773,6797-6812,6773-6786,6759-6768,6776- 6786,6751-6759,6768-6773,6773-6776 6/22/2022 528 SBHP 6684 2091 6700 0.26 2095 S-112 500292309900 WAG 640120 6754-6743,6759-6754,6773-6760,6711-6724,6741-6749 2/14/2022 192 Other 6700 4450 S-114A 500292311601 WAG 640120 6743-6755,6743-6745,6745-6755,6728-6743 6/7/2022 168 Other 6700 3757 S-114A 500292311601 WAG 640120 6743-6755,6743-6745,6745-6755,6728-6743 6/18/2022 432 Other 6700 3657 S-121 500292330400 O 640120 6756-6800,6815-6787,6816-6818,6835-6823,6816- 6826,6834-6837,6820-6822,6828-6844,6810-6820,6792- 6810,6812-6808,6813-6815,6785-6788,6829-6818 6/14/2022 112 SBHP 4951 2384 6700 0.44 3154 S-122 500292326500 O 640120 6769-6777,6783-6782,6760-6745,6739-6753,6781- 6780,6770-6763,6782-6780,6780-6781,6782-6781,6780- 6782,6778-6772 6/15/2022 360 SBHP 4644 2304 6700 0.44 3209 S-124 500292332300 WAG 640120 6927-6936,6871-6879,6888-6898,6900-6917,6944-6951 3/5/2022 192 Other 6700 3921 S-126 500292336300 WAG 640120 6729-6735,6700-6716,6741-6748,6773-6778,6719- 6725,6753-6761 4/21/2022 192 Other 6700 4488 S-31A 500292210901 WAG 640120 8763-8785,8784-8813,6775-6790,6660-6729 5/7/2022 144 Other 6700 4183 *Other: Static pressure for water injectors were calculated based tubing fluid level shots and water gradient below known freeze protect volume 7. Gas Gravity: Prudhoe Bay Unit Prudhoe Bay Field: Aurora Oil Pool 6700 TVDss 0.72 August 11th, 2022 3. Unit or Lease Name:4. Field and Pool:5. Datum Reference: ALASKA OIL AND GAS CONSERVATION COMMISSION RESERVOIR PRESSURE REPORT 1. Operator:2. Address: Hilcorp Alaska, LLC 3800 Centerpoint Dr. Anchorage, AK, 99503 STATE OF ALASKA Gavin Dittman 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. Gavin DittmanSignature Printed Name Title Date Senior Reservoir Engineer 10 TABLE 4 - AURORA MONTHLY AVERAGE OIL ALLOCATION FACTORS TABLE 5: AURORA PRESSURES BY REPRESENTATIVE AREA Representative Area Well Date Pressure at Datum (psi) Crest S-31A 5/7/2022 4,183 East of Crest S-112 2/14/2022 4,450 North of Crest S-124 3/5/2022 3,921 North of Crest S-121 6/14/2022 3,154 North of Crest S-103 6/15/2022 2,868 North of Crest S-122 6/15/2022 3,209 Northwest of Crest S-106 6/22/2022 2,095 Northwest of Crest S-101 7/8/2022 2,947 South of Crest S-126 4/21/2022 4,488 South of Crest S-114A 6/7/2022 3,757 South of Crest S-114A 6/18/2022 3,657 1 2022 ANNUAL SURVEILLANCE REPORT BOREALIS OIL POOL PRUDHOE BAY UNIT JULY 1, 2021 – JUNE 30, 2022 2 CONTENTS 1. INTRODUCTION ........................................................................................................................................ 3 2. PROGRESS OF ENHANCED RECOVERY PROJECT IMPLEMENTATION AND RESERVOIR MANAGEMENT SUMMARY (RULE 9A) ............................................................................................................................... 3 3. VOIDAGE BALANCE BY MONTH OF PRODUCED AND INJECTED FLUIDS (RULE 9B).................................. 4 4. ANALYSIS OF RESERVOIR PRESSURE SURVEYS WITHIN THE POOL (RULE 9C) .......................................... 4 5. RESULTS AND ANALYSIS OF SPECIAL MONITORING (RULE 9D) ............................................................... 5 6. REVIEW OF POOL PRODUCTION ALLOCATION AND WELL TEST EVALUATION (RULE 9E) AND REVIEW OF POOL PRODUCTION ALLOCATION FACTORS AND ISSUES (RULE 4G) ................................................. 5 7. OPERATIONS, DEVELOPMENT & RESERVOIR DEPLETION PLANS REVIEW (RULE 9F AND 9G) ................. 5 LIST OF ATTACHMENTS Figure 1: Borealis production and injection history ......................................................................................... 8 Figure 2: Borealis voidage history .................................................................................................................... 8 Table 1: Borealis monthly production and injection summary ........................................................................ 7 Table 2: Borealis pressure survey detail ........................................................................................................... 9 Table 3: Borealis monthly average oil allocation factors ................................................................................ 10 Table 4: Borealis pressures by representative area ....................................................................................... 10 3 Prudhoe Bay Unit 2022 Borealis Oil Pool Annual Reservoir Report 1. INTRODUCTION This Annual Reservoir Report is submitted to the Alaska Oil and Gas Conservation Commission for the Borealis Oil Pool in accordance with Commission regulations and Conservation Order 471. This report covers the period from July 1, 2021 through June 30, 2022. 2. PROGRESS OF ENHANCED RECOVERY PROJECT IMPLEMENTATION AND RESERVOIR MANAGEMENT SUMMARY (RULE 9A) Enhanced Recovery Projects Water injection in the Borealis Oil Pool (BOP) started in June 2001, whereas tertiary EOR Miscible Water Alternating Gas (MWAG) started in June 2004. Evaluation of hydrocarbon recovery mechanisms for the Borealis Oil Pool (BOP) has been a continual process. A phased development program has been deemed appropriate due to the technical characteristics of considerable faulting, low initial oil rates, and thin oil columns. This development approach employs three reservoir mechanisms throughout the field’s life to maximize commercial production. Initial development involves a period of primary production to determine reservoir performance and connectivity of drainage areas. Primary production under solution gas and aquifer influx drive, from both floodable and non-waterflood pay intervals, provides information, including production pressure data to evaluate compartmentalization and conformance, that is used to improve the depletion plan. This drilling and surveillance data influences subsequent steps in reservoir development, including proper water injection pattern layout. In areas of the BOP where injection is justified, waterflooding is initiated to improve recovery by reducing residual oil saturation and maintaining well productivity via reservoir pressure support. Tertiary EOR MWAG provides additional oil recovery by further reducing residual oil saturation. The miscible gas injection project is operated to maintain miscibility betw een the reservoir fluid and the injected miscible gas. There will be higher pressure in the area around injection wells and a pressure sink around the producers, which in some cases can be below minimum miscibility pressure (MMP) of approximately 2100 psi. With average reservoir pressures above the MMP, incremental EOR recovery is essentially the same even when producer region pressures below the MMP are maintained. As a consequence, reservoir management guidelines for EOR are based on average reservoir pressure rather than producer pressure. Early implementation of the secondary and tertiary injection processes allows adequate time for producers to capture mobilized oil. Proper field management includes monitoring of productivity, GOR, water cut, pressure, and voidage replacement ratios. Reservoir Management Summary The objective of the Borealis reservoir management strategy is to manage reservoir development and depletion to maximize commercial production consistent with prudent oil field engineering practices. During primary depletion, a number of producers experienced increasing GORs. Production was restricted in several wells in 2002 to conserve reservoir energy. As more injection patterns were implemented in 2003, the rising GOR trend was reversed and GORs stabilized near solution GOR. When 4 water injection was initiated, a VRR target greater than 1.0 was implemented in order to catch up with voidage. The current VRR target is 1.0. Waterflood patterns have been designed and implemented to maintain pressure in individual reservoir compartments and areal sweep is maximized. Initial patterns were based on the understanding at the time of reservoir compartmentalization. Patterns and producer/injector ratios are being modified as development wells and surveillance data provide new information. The surveillance program emphasizes pressure monitoring, injection tracers in select patterns, and waterflood performance monitoring to support this feedback and intervention process. Injection facility limitations were identified in 2003, which limited the delivery pressure of water to be injected to the field. Booster pumps were installed at Z Pad to provide increased injection pressure and better water distribution. The increased injection pressure has allowed better management of injection at a pattern level. The Borealis waterflood strategy is progressing as planned , however Borealis has experienced earlier than expected water breakthrough in many patterns. Impacts of the early breakthrough include reduced production due to unfavorable wellbore hydraulics and gas -lift supply pressure limitations. Remedies have included gas-lift redesign and optimization and prioritization of gas-lift use. During the reporting period, average injection rate was 22.4 MBWIPD and 45.1 MMSCFD. Cumulative injection through June 2022 was 246 MMSTBW and 135 BCF. A total of 24 injectors have been on water injection and 26 injectors have been on MI over the life of the field. 3. VOIDAGE BALANCE BY MONTH OF PRODUCED AND INJECTED FLUIDS (RULE 9B) During the reporting period, field production averaged 7.9 MBOPD, 31.5 MMSCFD (FGOR 4.0 MSCF/STB), and 31.5 MBWPD (WC 79%). The average voidage replacement ratio was 0.84. Monthly production, injection, and voidage volumes for the reporting period are summarized in Table 1. Figures 1 and 2 graphically depict this information since field start-up. Plans to achieve injection withdrawal ratios consistent with the reservoir management strategy include drilling and stimulation of injection wells as necessary and increasing water injection supply pressure to enhance injection rates where needed. Booster pumps were installed at Z Pad to provide increased injection pressure for low injectivity patterns. 4. ANALYSIS OF RESERVOIR PRESSURE SURVEYS WITHIN THE POOL (RULE 9C) Reservoir pressure monitoring is performed in accordance with Rule 5 of Conservation Order 471. A summary of reservoir pressure surveys obtained during the reporting period is shown in Table 2. Five producers and one injector have been completed with permanent bottomhole gauges, giving valuable information about the flowing conditions, reservoir pressures, and reservoir connectivity on a continuous basis. Nine static pressure measurements were obtained during the reporting period , covering all active areas, as shown in Table 4. Most producers in Borealis have evidence of pressure response to injection support. For the period of July 1st, 2022 to June 30th, 2023, a minimum of one pressure survey will be taken in each of the active representative areas that contain active wells. If all active representative areas contain active wells, a minimum of six pressure surveys will be taken. 5 5. RESULTS AND ANALYSIS OF SPECIAL MONITORING (RULE 9D) During the reporting period, no production or injection logs were run in the Borealis Field. 6. REVIEW OF POOL PRODUCTION ALLOCATION AND WELL TEST EVALUATION (RULE 9E) AND REVIEW OF POOL PRODUCTION ALLOCATION FACTORS AND ISSUES (RULE 4G) Production allocation is based on well tests and conducted in accordance with 20 AAC 25.230. A project was initiated to improve the L & V pad metering reliability issues by phasing out the Gen 2 meters and upgrading/reinstating the test separators with modern flow measurement components that are easily maintained. The upgrades on L Pad included installation of a M icroMotion meter and Phase Dynamics meter, as the L Pad test separator was already in service. The upgrades on V Pad included returning the test separator to service as well as installation of a MicroMotion meter and Phase Dynamics meter. The L & V pad test separator upgrades were completed in January 2019. The meter prove-up and rate verification was completed with the portable testers in 1Q 2019. Overall, improvements in both well test quality and accuracy have been observed. Over the reporting period, the monthly average of daily oil production allocation factors fell within the range of 0.81 and 0.96 . Any days with allocation factors of zero were excluded. The monthly averages of daily oil production allocation factors are shown in Table 3. 7. OPERATIONS, DEVELOPMENT & RESERVOIR DEPLETION PLANS REVIEW (RULE 9F & G) Miscible gas injection and water-alternating with miscible gas injection is used to increase the economic recovery of Borealis reservoir hydrocarbons. Injection wells are completed for Enhanced Oil Recovery services. Waterflood and tertiary EOR have been implemented to provide pressure support and reduce residual oil saturations on all three Borealis Pads, L, V and Z. Injection started on June 8, 2002. Water injection manifolding and booster pumps have been installed and have been operating since January 2004. These booster pumps allow even pattern support througho ut the waterflood providing optimum waterflood spacing, configuration, timing and operations. The Borealis waterflood management strategy targets a voidage replacement ratio of 1.0 through MI WAG injection to maintain reservoir pressure and to maximize commercial oil production. In March 2010, GC2 reached its permit limit for H2S production. Several Borealis wells were shut in during their MI responses due to elevated H2S in the returned MI. The installation of Metal Triazine injection continues to help maintain H2S production within the allowable limit. Borealis wells continue to show benefits from MI. Summarized below are significant events and accomplishments at Borealis over the past year: • Z-15A: Recompleted as a Borealis producer in 2Q 2022 • V-105: CTD sidetrack in 1Q 2022 • L-106A: CTD sidetrack in 1Q 2022 • L-116A: CTD sidetrack in 1Q 2022 • L-122L1: CTD sidetrack in 1Q 2022 The Borealis owners will continue to evaluate optimal well count, well utility , wellwork and well locations to maximize commercial production. 6 Future development plans are discussed in the 2022 update to the Plan of Development for the Western Satellite Participating Areas, which was filed with the Division of Oil and Gas of the Alaska Department of Natural Resources on September 30, 2021. A copy was provided to the Commission. The Commission will be copied when the 2023 update of the Western Satellites Plan of Development is filed with the Division. 7 TABLE 1: BOREALIS MONTHLY PRODUCTION AND INJECTION SUMMARY Report Oil Prod Gas Prod Water Prod Water Inj MI Inj Oil Prod Cum Gas Prod Cum Water Prod Cum Water Inj Cum Cum Total Inj (MI+Water) Net Res Voidage Net Voidage Cum Monthly VRR Date STB MSCF STB STB MSCF STB MSCF STB STB RB RVB RVB RVB/RVB Jul-21 253,882.999,783.1,160,130.899,836.658,557.92,693,569.147,984,396.148,573,057.238,463,183.319,334,364.816,275 39,217,982 0.62 Aug-21 189,133.803,778.981,249.948,401.197,480.92,882,702 148,788,174 149,554,306 239,411,584 320,433,654 660,502 39,878,484 0.62 Sep-21 169,104.814,655.1,061,522.803,095.1,137,752.93,051,806 149,602,829 150,615,828 240,214,679 321,966,248 290,068 40,168,553 0.84 Oct-21 182,437.773,606.1,015,829.954,002.1,382,577.93,234,243 150,376,435 151,631,657 241,168,681 323,806,068 -71,994 40,096,559 1.04 Nov-21 230,162.742,239.949,415.712,570.1,638,245.93,464,405 151,118,674 152,581,072 241,881,251 325,555,727 -6,410 40,090,148 1.00 Dec-21 254,267.959,146.1,068,277.654,879.1,971,878.93,718,672 152,077,820 153,649,349 242,536,130 327,452,817 135,029 40,225,177 0.93 Jan-22 276,115.1,027,025.922,067.678,949.1,805,864.93,994,787 153,104,845 154,571,416 243,215,079 329,271,770 133,622 40,358,799 0.93 Feb-22 228,168.810,516.670,631.495,262.1,290,992.94,222,955 153,915,361 155,242,047 243,710,341 330,582,305 185,254 40,544,053 0.88 Mar-22 252,657.950,483.804,746.586,119.1,733,330.94,475,612 154,865,844 156,046,793 244,296,460 332,260,672 74,809 40,618,862 0.96 Apr-22 299,082.1,156,969.888,760.466,673.1,806,847.94,774,694 156,022,813 156,935,553 244,763,133 333,861,590 428,367 41,047,229 0.79 May-22 285,887.1,342,638.913,450.513,988.1,577,650.95,060,581 157,365,451 157,849,003 245,277,121 335,369,141 644,785 41,692,014 0.70 Jun-22 259,763.1,104,123.589,923.457,320.1,270,995.95,320,344 158,469,574 158,438,926 245,734,441 336,628,198 377,530 42,069,544 0.77 8 FIGURE 1: BOREALIS PRODUCTION & INJECTION HISTORY FIGURE 2: BOREALIS VOIDAGE HISTORY 9 TABLE 2: BOREALIS PRESSURE SURVEY DETAIL 1. Operator: Hilcorp Alaska. LLC 3. Unit or Lease Name:6. Oil Gravity:7. Gas Gravity: Prudhoe Bay Unit 0.9 SG / 25° API 0.72 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. B.H. 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) L-108 500292309000 WAG 640130 6605-6610,4414-4442,4509-4523,6519-6575,4455-4470,6595- 6601,4562-4594,4350-4386,6583-6588 6/7/2022 168 other 6600 3214 L-116 500292302500 O 640130 6468-6513,6527-6533,6608-6628 8/4/2021 4159 SBHP 6500.45 3479 6600 0.09 3487.97 L-121A 500292313801 O 640130 6623-6663 8/21/2021 484 SBHP 6549.58 2291 6600 0.37 2309.83 V-111 500292316100 O 640130 6650-6658,6670-6677,6677-6684,6689-6699,6628-6639,6680- 6680,6626-6628,6650-6664,6666-6639,6641-6649,6684- 6688,6626-6639,6639-6639 9/5/2021 2995 SBHP 6549.8 2891 6600 0.34 2908.09 V-117 500292315600 O 640130 6710-6712,6709-6710,6682-6685,6718-6717,6715-6714,6700- 6688,6681-6693,6711-6696,6681-6681,6717-6715,6725- 6706,6708-6708,6712-6717,6700-6705,6696-6682,6714-6724 12/22/2021 2659 SBHP 6586.32 3075 6600 0.34 3079.68 V-120 500292322500 WAG 640130 6809-6835,6660-6739 5/20/2022 192 other 6600 3073 Z-103 500292323500 WAG 640130 6687-6728 6/19/2022 456 other 6600 0.42 2494 Z-113 500292345000 O 640130 6640-6634,6552-6553,6553-6568,6656-6641,6646-6637,6633- 6644,6631-6644,6553-6642,6568-6642,6654-6659,6633-6631 11/11/2021 792 SBHP 4441.49 2874 6600 2925 Z-116 500292345500 WAG 640130 6836-6871,6831-6834,6801-6797,6793-6807,6811-6804,6833- 6799 6/20/2022 480 other 6600 0.43 2973 *Other: Static pressure for water injectors were calculated based tubing fluid level shots and water gradient below known freeze protect volume Gavin Dittman 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. Gavin DittmanSignature Printed Name Title Date Senior Reservoir Engineer August 11th, 2022 4. Field and Pool:5. Datum Reference: Prudhoe Bay Field, Borealis Oil Pool 6600 TVDss STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION RESERVOIR PRESSURE REPORT 2. Address: 3800 Centerpoint Dr. Anchorage, AK, 99503 10 TABLE 3: BOREALIS MONTHLY AVERAGE OIL ALLOCATION FACTORS Month Allocation Factor 7/1/2021 0.85 8/1/2021 0.81 9/1/2021 0.81 10/1/2021 0.90 11/1/2021 0.86 12/1/2021 0.86 1/1/2022 0.83 2/1/2022 0.81 3/1/2022 0.86 4/1/2022 0.87 5/1/2022 0.88 6/1/2022 0.96 TABLE 4: BOREALIS PRESSURES BY REPRESENTATIVE AREA Representative Area Well Date Pressure at Datum (psi) North of L-Pad L-116 8/4/2021 3,488 North of V-Pad V-111 9/5/2021 2,908 North of V-Pad L-108 6/7/2022 3,214 Northeast of V-Pad V-120 5/20/2022 3,073 South of V-Pad V-117 12/22/2021 3,080 Southwest of L-Pad L-121A 8/21/2021 2,310 Z-Pad Z-113 11/11/2021 2,925 Z-Pad Z-103 6/19/2022 2,494 Z-Pad Z-116 6/20/2022 2,973 7/21 – 6/22 Midnight Sun Annual Surveillance Report 1 2022 ANNUAL RESERVOIR SURVEILLANCE REPORT MIDNIGHT SUN OIL POOL PRUDHOE BAY UNIT JULY 1, 2021 – JUNE 30, 2022 7/21 – 6/22 Midnight Sun Annual Surveillance Report 2 CONTENTS 1. Introduction 3 2. Progress of Enhanced Recovery Project Implementation and Reservoir Management (Rule 11 a) 3 3. Voidage Balance by Month of Produced and Injected Fluids (Rule 11 b) 3 4. Analysis of Reservoir Pressure Surveys within the Pool (Rule 11 c) 4 5. Results and Analysis of Production and Injection Logging Surveys (Rule 11 d) 4 6. Results of Well Allocation and Test Evaluation (Rule 11 e) and Review of Pool Production Factors and Issues (Rule 7d) 4 7. Future Development Plans and Review of Plan of Operations and Development (Rule 11 f & g) 4 LIST OF ATTACHMENTS Figure 1: Midnight Sun Monthly Production and Injection History ................................................................. 5 Figure 2: Midnight Sun Voidage History .......................................................................................................... 5 Figure 3: Midnight Sun Pressure History ......................................................................................................... 6 Table 1: Midnight Sun Monthly Production, Injection, Voidage Balance Summary ........................................ 7 Table 2: Midnight Sun Pressure Survey Details ............................................................................................... 8 Table 3: Allocation Factors .............................................................................................................................. 9 7/21 – 6/22 Midnight Sun Annual Surveillance Report 3 Prudhoe Bay Unit 2022 Midnight Sun Annual Reservoir Report This Annual Reservoir Report is submitted to the Alaska Oil and Gas Conservation Commission for the Midnight Sun Oil Pool in accordance with Commission regulations and Conservation Order 452. This report covers the period from July 1, 2021 through June 30, 2022. Progress of Enhanced Recovery Project Implementation and Reservoir Management Summary (Rule 11 a) Production and injection volumes for the 12-month period ending June 30, 2022 are summarized in Table 1. The objective of the Midnight Sun reservoir management strategy is to manage reservoir development and depletion to maximize commercial production consistent with prudent oil field engineering practices. During primary depletion, both the E-101 and the E-102 producers experienced increasing gas-oil-ratios (GORs). Consequently, production was restricted to conserve reservoir energy. Produced water injection into the Midnight Sun reservoir commenced in October 2000 and continues to provide pressure support to Midnight Sun. The objective of water injection is to increase reservoir pressure, reduce GOR’s to enable wells to be produced at their full capacity, and maximize areal sweep efficiency. There is a risk of oil in-flux into the gas cap from mid-field water injection. Placement of the wells drilled in 2001 and voidage management are minimizing this risk. A historical VRR target of 1.0 to 1.3 is designed to increase reservoir pressure while minimizing re- saturation of oil into the gas cap. During the period covered by the report, the VRR averaged 1.62. E-103 and E-104 injectors came back online near the end of the 2021 reporting period – reservoir pressure had declined while E Pad water injectors were offline. VRR >1 was targeted to increase reservoir pressure above minimum miscibility pressure for miscible injectant. Since 2005, gas lift has been utilized to produce the Midnight Sun wells more efficiently. In 2015, P1-122, a Water-Alternating-Gas (WAG) injector, was drilled from P1 Pad (the only pad with Miscible Injectant nearby) to supply MI and implement enhanced oil recovery in the pool. Voidage Balance by Month of Produced and Injected Fluids (Rule 11 b) A total of six Midnight Sun wells have been drilled, with the most recent well , P1-122, drilled in 2015 from Pt. McIntyre. Midnight Sun produced at an average rate of 624 bopd, 8842 bwpd, 6.9 mmscfpd and injected 19.9 mbwpd and 0 mmscfpd of MI for the report period resulting in a total VRR of 1.62 for the period. Monthly production and injection 7/21 – 6/22 Midnight Sun Annual Surveillance Report 4 surface volumes for the reporting period are summarized in Table 1 along with a voidage balance of produced and injected fluids for the report period. Analysis of Reservoir Pressure Surveys within the Pool (Rule 11 c) Reservoir pressure monitoring is performed in accordance with Rule 8 of Conservation Order 452. A summary of reservoir pressure surveys obtained during the reporting period is shown in Table 2. For the report period two reservoir pressures was acquired: E-102 (12/26/21 & 5/7/22). Results and Analysis of Production & Injection Logging Surveys (Rule 11 d) No significant production logging or tracer studies were completed , and future tracer studies are not being planned at this time . Results of Well Allocation and Test Evaluation (Rule 11 e) and Review of Pool Production Factors and Issues (Rule 7(d) Midnight Sun wells are tested using the E-Pad test separator, and Midnight Sun production is processed through the GC-1 facility. Midnight Sun production allocation is based on well tests and conducted in accordance with 20 AAC 25.230. Over the reporting period, the monthly average of the daily oil production allocation factors fell within the range of 0.89-0.98. Any days with allocation factors of zero were excluded. The monthly averages of daily oil production allocation factors are shown in Table 3. Electronic files containing daily allocation data and daily test data for a minimum of five years are being retained. Future Development Plans and Review of Plan of Operations and Development (Rule 11f and g) Future development plans are discussed in the 202 2 update to the Plan of Development for the Western Satellite Participating Areas, which was filed with the Division of Oil and Gas of the Alaska Department of Natural Resources on September 30, 2021. A copy was provided to the Commission. The Commission will be copied when the 2023 update of the Western Satellites Plan of Development is filed with the Division. 7/21 – 6/22 Midnight Sun Annual Surveillance Report 5 Figure 1: Midnight Sun Production and Injection History Figure 2: Midnight Sun Voidage History 7/21 – 6/22 Midnight Sun Annual Surveillance Report 6 Figure 3: Midnight Sun Pressure History 2,700 2,900 3,100 3,300 3,500 3,700 3,900 4,100 Jan-96 Jan-98 Jan-00 Jan-02 Jan-04 Jan-06 Jan-08 Jan-10 Jan-12 Jan-14 Jan-16 Jan-18 Jan-20 Jan-22 Jan-24psiaMidnight Sun Pressure History (measured at 8050 ft. TVDss datum) 7/21 – 6/22 Midnight Sun Annual Surveillance Report 7 Table 1: Midnight Sun Monthly Production, Injection, Voidage Balance Summary Assumptions for Production Table: Oil Formation Volume Factor = 1.29 rb/stb Water Formation Volume Factor = 1.03 rb/stb Gas Formation Volume Factor = 0.798 rb/Mscf MI Formation Volume Factor = 0.59 rb/Mscf Report Date Oil Prod Gas Prod Water Prod Water Inj MI Inj Oil Prod Cum Gas Prod Cum Water Prod Cum Water Inj Cum MI Inj Cum Cum Total Inj (MI+Water) Net Res Voidage Net Voidage Cum Monthly VRR Date STB MSCF STB STB MSCF STB MSCF STB STB STB RB RVB RVB RVB/RVB Jul-21 21,765 344,066 250,753 391,081 0 22,897,003 77,579,681 61,870,460 108,652,505 9,516,281 117,526,686 147,565 24,436,292 0.84 Aug-21 18,050 274,241 385,807 538,310 0 22,915,053 77,853,922 62,256,267 109,190,815 9,516,281 118,081,145 76,311 24,457,825 0.96 Sep-21 26,013 255,520 355,462 598,818 0 22,941,066 78,109,442 62,611,729 109,789,633 9,516,281 118,697,928 -25,790 24,382,149 1.14 Oct-21 22,169 247,213 356,238 734,809 0 22,963,235 78,356,655 62,967,967 110,524,442 9,516,281 119,454,781 -174,788 24,158,721 1.42 Nov-21 14,387 333,688 360,789 761,031 0 22,977,622 78,690,343 63,328,756 111,285,473 9,516,281 120,238,643 -134,373 23,956,746 1.35 Dec-21 18,840 203,144 295,174 390,062 0 22,996,462 78,893,487 63,623,930 111,675,535 9,516,281 120,640,407 79,556 23,996,410 0.91 Jan-22 19,515 175,141 193,379 568,584 0 23,015,977 79,068,628 63,817,309 112,244,119 9,516,281 121,226,048 -230,973 23,731,455 1.83 Feb-22 16,714 133,958 171,025 678,849 0 23,032,691 79,202,586 63,988,334 112,922,968 9,516,281 121,925,263 -402,692 23,302,996 2.58 Mar-22 17,474 157,562 210,822 708,143 0 23,050,165 79,360,148 64,199,156 113,631,111 9,516,281 122,654,650 -372,425 22,899,990 2.23 Apr-22 16,822 177,966 216,417 690,573 0 23,066,987 79,538,114 64,415,573 114,321,684 9,516,281 123,365,940 -332,809 22,532,274 2.07 May-22 19,200 125,222 226,763 650,748 0 23,086,187 79,663,336 64,642,336 114,972,432 9,516,281 124,036,211 -321,306 22,187,330 2.06 Jun-22 16,679 83,907 204,623 560,104 0 23,102,866 79,747,243 64,846,959 115,532,536 9,516,281 124,613,118 -285,748 21,886,222 2.09 7/21 – 6/22 Midnight Sun Annual Surveillance Report 8 Table 2: MIDNIGHT SUN PRESSURE SURVEY DETAILS 6. Oil Gravity: 25-29 API 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. B.H. 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) E-102 500292304200 O 640158 7989.22-8091.30 12/26/2021 223 SBHP 161 8050 3002 8050 0.4322 3002 E-102 500292304200 O 640158 7989.22-8091.30 5/7/2022 3,108 SBHP 159 7986 3263 8050 0.0300 3265 3. Unit or Lease Name:4. Field and Pool:5. Datum Reference: Tim Davis 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. Tim DavisSignature 7. Gas Gravity: Prudhoe Bay Unit Prudhoe Bay Field, Midnight Sun Oil Pool Printed Name Title Date Reservoir Engineer September 12, 2022 8050 TVDss 0.72 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION RESERVOIR PRESSURE REPORT 1. Operator:2. Address: Hilcorp Alaska, LLC.3800 Centerpoint Dr. Anchorage, AK, 99516 7/21 – 6/22 Midnight Sun Annual Surveillance Report 9 Table 3: Allocation Factors Month Oil Allocation Factor Jul-21 0.89 Aug-21 0.91 Sep-21 0.90 Oct-21 0.91 Nov-21 0.94 Dec-21 0.94 Jan-22 0.98 Feb-22 0.95 Mar-22 0.90 Apr-22 0.94 May-22 0.94 Jun-22 0.95 1 7/21 – 6/22 ORION ANNUAL SURVEILLANCE REPORT 2022 ANNUAL SURVEILLANCE REPORT ORION OIL POOL PRUDHOE BAY UNIT JULY 1, 2021 – JUNE 30, 2022 2 7/21 – 6/22 ORION ANNUAL SURVEILLANCE REPORT CONTENTS 1. INTRODUCTION .................................................................................................................................. 3 2. VOIDAGE BALANCE BY MONTH OF PRODUCED AND INJECTED FLUIDS (RULE 9A) ................................ 3 3. ANALYSIS OF RESERVOIR PRESSURE SURVEYS WITHIN THE POOL (RULE 9B) ........................................ 3 4. RESULTS AND ANALYSIS OF PRODUCTION & INJECTION LOGGING SURVEYS, AND SPECIAL MONITORING (RULE 9C) ..................................................................................................................... 4 5. REVIEW OF POOL PRODUCTION ALLOCATION (RULE 9D) AND REVIEW OF POOL PRODUCTION ALLOCATION FACTORS AND ISSUES (RULE 4F) .................................................................................... 4 6. PROGRESS OF ENHANCED RECOVERY PROJECT IMPLEMENTATION AND RESERVOIR MANAGEMENT SUMMARY (RULE 9E).......................................................................................................................... 5 7. PROGRESS OF PLANS AND TESTS TO EXPAND THE PRODUCTIVE LIMITS OF THE POOL (RULE 9F) ......... 6 8. RESULTS OF MONITORING TO DETERMINE ENRICHED GAS INJECTANT BREAKTHROUGH TO OFFSET PRODUCERS (RULE 9G) ....................................................................................................................... 6 9. FUTURE DEVELOPMENT PLANS .......................................................................................................... 6 LIST OF ATTACHMENTS Figure 1: Orion production and injection history ......................................................................................... 8 Figure 2: Orion voidage history ................................................................................................................... 9 Figure 3: Orion pressures at datum ........................................................................................................... 11 Table 1: Orion monthly production and injection summary ......................................................................... 7 Table 2: Orion pressure survey detail ........................................................................................................ 10 Table 3: Orion monthly average oil allocation factors ................................................................................ 12 3 7/21 – 6/22 ORION ANNUAL SURVEILLANCE REPORT PRUDHOE BAY UNIT 2022 ORION OIL POOL ANNUAL SURVEILLANCE REPORT 1. I NTRODUCTION This Annual Surveillance Report is being submitted to the Alaska Oil and Gas Conservation Commission in accordance with Rule 9 of Conservation Order 505B, and covers the period from July 1, 2021 to June 30, 2022. 2. VOIDAGE BALANCE BY MONTH OF PRODUCED AND INJECTED FLUIDS (RULE 9A) During the reporting period, field production averaged 7,767 BOPD, 18.1 MMSCFD (FGOR 2,331 SCF/STB), and 12,827 BWPD (WC 62 %). Water injection during this period averaged 13,927 BWIPD with 26,050 MMSCFD of miscible gas injection. The average voidage replacement ratio was 0.98. Monthly production, injection, and voidage volumes for the reporting period are summarized in Table 1. Figures 1 and 2 graphically depict this information since field start-up. 3. ANALYSIS OF RESERVOIR PRESSURE SURVEYS WITHIN THE POOL (RULE 9B) Reservoir pressure monitoring is performed in accordance with Rule 5 of Conservation Order 505B. A summary of valid pressure surveys obtained during the reporting period is shown in Table 2. This data was acquired using static bottom hole pressure surveys (SBHP) and permanent downhole gauges installed in injectors. Figure 3 illustrates valid Orion pressure data acquired since field inception interpolated to the Pool datum of 4400 ft TVDss (true vertical depth subsea). For the period of July 1, 2022 to June 30th, 2023, a minimum of one pressure survey will be taken in each of the active representative areas that contain active wells. An analysis of the recent pressure data by polygon follows: Polygon 1 This polygon contains producer L-200A, L-207, L-206 and is supported by injectors L-211i, L-212i, L-218i, L- 240. Measured pressure in the polygon was 1858 psi. Polygon 1A This polygon contains producers L-202, L-203, and L-250 and is supported by injectors L-215i, L-216i, L-217i, L-219i, and L-223i. Measured pressures in the polygon range averaged 1869 psi. Polygon 2 This polygon contains producers V-202, V-203, V-204, V-205, V-234 and is supported by injectors L-213i, V- 210i, V-211i, V-212i, V-213Ai, V-214i, V-215i, V-216i, V-217i, V-218i, V-222i, V-223i, V-225i, V-229i. Measured pressures in the polygon averaged 1962 psi. Polygon 2A 4 7/21 – 6/22 ORION ANNUAL SURVEILLANCE REPORT This polygon contains producers L-201, L-204, and V-207 and is supported by injectors L-210i, L-214Ai, L- 222, V-219i, V-220i, V-221i, and V-224i. Measured pressures in the polygon averaged 1929 psi. Polygon 5S This polygon contains producer L-205A and is supported by injectors L-220i and L-221i. Measured pressures in the polygon averaged 2393 psi. Polygon 3 This polygon contains producer Z-220 and is supported by injector Z-221. This is a greenfield polygon with a normal pressure gradient. 4. RESULT S AND ANALYSIS OF PRODUCTION & INJECTION LOGGING SURVEYS, AND SPECIAL M ONITORING (RULE 9C) Production Logs: No new production logs have been gathered over the reporting period. Well Fluids Sampling: A well fluids sampling program is ongoing to gather hig h quality and high frequency surveillance data: (1) Uncontaminated wellhead samples are obtained monthly to quarterly on each producer, and tested for API, viscosity, WC, and sand quantity. This data helps track changes in production from different sands, waterflood or MI response, and sanding tendencies. (2) Wellhead samples are analysed quarterly for water properties to identify changes between formation water production and waterflood breakthrough. This data is also useful for identifying matrix bypass events (MBE) because produced water will have similar properties as injected water. (3) A produced water supply sample is analysed quarterly to serve as a baseline for analysis of well production samples. (4) Gas sampling is done monthly or quarterly depending on WAG activity in the polygon to establish gas chromatography signatures and track returned miscible injectant (MI). Injection Logs: One injection log was run on V-137 on 3/18/2022 to determine miscible injectant distribution. Injection logs are used to quality check waterflood regulating valve performance while in water service or to determine the distribution of miscible injectant between zones. Real-time Downhole Pressure Gauges in Injectors: Monitoring of individual zonal pressures is continuing on all injectors with downhole gauges installed. Real-time data has confirmed offtake from offset producers, formation and healing of MBE’s, pressure transmission across the OWC, and helped tremendously in identifying underperforming injection regulators. 5. REVIEW OF POOL PRODUCTION ALLOCATION (RULE 9D) AND REVIEW OF POOL PRODUCTION ALLOCATION FACTORS AND ISSUES (RULE 4F) 5 7/21 – 6/22 ORION ANNUAL SURVEILLANCE REPORT Production allocation is based on well tests and conducted in accordance with 20 AAC 25.230. Monthly averages of daily oil production allocation factors are shown in Table 3. Electronic files containing daily allocation data and daily test data for a minimum of five years are being retained. 6. PROGRESS OF ENHANCED RECOVERY PROJECT IMPLEMENTATION AND RESERVOIR MANAGEMENT SUMMARY (RULE 9E ) Enhanced Recovery Project - Waterflood: Primary production from the Orion oil pool commenced in 2002 and continued until waterflood was initiated in 2003. The waterflood patterns are designed to ensure reservoir pressure is maintained above the bubble point pressure and as close to the original reservoir pressure as possible. Because of differences in rock and oil quality, the various sands behave like different reservoirs connected in the same wellbore, thereby requiring a much higher degree of control in the injectors to manage voidage. The basis of design for water injectors has evolved to include isolation packers between sands to accurately control injection rate into the vastly different sands. Injection rate into each zone is controlled by downhole waterflood regulating valves installed in mandrels adjacent to the target sand. To prevent freezing, a minimum injection rate of 500 BWIPD is being used for all new waterflood regulating valve designs. In patterns where the minimum injection rate results in a high voidage replacement ratio, injectors in the pattern are cycled. During the reporting period, average injection rate was 13,927 BWIPD. Cumulative injection through June 2022 was 69.5 MMSTBW Enhanced Recovery Project - Miscible Injectant: In 2006, approval to implement an enhanced oil recovery project in the Orion oil pool using Prudhoe Bay miscible injectant was granted via C.O. 505A. Injection of miscible injectant began later that year in the updip portion of Polygon 2. The current MI strategy is to inject smaller slugs of miscible injectant to improve the efficiency of the flood. To date, miscible injectant has been injected in Polygon 1, Polygon 1A, Polygon 2, Polygon 2A, Polygon 5S, and Polygon 3. During the reporting period, average injection rate was 26.1 MMSCFD. Cumulative injection through June 2022 was 48.3 BCF. Reservoir Management Strategy: The objective of the Orion oil pool reservoir management strategy is to manage reservoir development and depletion to maximize commercial production consistent with prudent oil field engineering practices. Key to this is achieving a balanced voidage replacement ratio requir ed to keep reservoir pressure above the bubble point. Individual floods are managed with downhole waterflood regulating valves in the injectors, as well as limited capabilities of reducing offtake in the producers by shutting in or choking laterals. Learnings over the last few years have revealed significant differences in productivity and oil mobility between Schrader Bluff sands. These learnings have led to changes in completion designs and operational strategies. In addition, the emergence of matrix bypass events has further highlighted the complexity of 6 7/21 – 6/22 ORION ANNUAL SURVEILLANCE REPORT the Schrader Bluff sands. It is expected that the reservoir management strategy will continually be evaluated and revised as appropriate throughout the life of the field. Matrix Bypass Events: As described in prior reports, the phenomenon of premature water breakthrough between a producer and a water source (water injector or aquifer) challenges the North Slope viscous oil developments. These events appear to have a multitude of probable causes: faults, fractures, matrix short-circuit through high perm streaks, and what is believed to be the creation of tunnels or “worm holes”. During the reporting period, a new matrix bypass event was identified in W-216 Oba to W-204. Hilcorp treated the MBE with RPPG but the treatment failed to plug the MBE. 7. PROGRESS OF PLANS AND TESTS TO EXPAND THE PRODUCTIVE LIMITS OF THE POOL (RULE 9F) New Sands: As mentioned in previous reports, Orion includes three wells with slotted liner completions in the N-sand; L-203, L-205, and V-207. 8. RESULTS OF M ONITORING TO DETERMINE ENRICHED GAS INJECTANT BREAKTHROUGH TO OFFSET PRODUCERS (RULE 9G) A response to miscible injectant is indicated by an increase in produced gas rate, an increase in formation gas-oil-ratio, and a reduction in the producing ratio of C1 (methane) to C3 (propane). To date, in the life of the field, responses to miscible injectant have been observed in the following producers: L-201, L-202, V-202, V-203, V-204, V-205, V-207, L-206, Z-220. 9. FUTURE DEVELO PMENT PLANS Future development plans are discussed in the 2022 update to the Plan of Development for the Orion Participating Area, which was filed with the Division of Oil and Gas of the Alaska Department of Natural Resources on September 30, 2022, a copy of which was provided to the Commission. The Commission will be copied when the 2023 update of the Orion Plan of Development is filed with the Division. 7 7/21 – 6/22 ORION ANNUAL SURVEILLANCE REPORT TABLE 1: ORION MONTHLY PRODUCTION AND INJECTION SUMMARY Report Oil Prod Gas Prod Water Prod Water Inj MI Inj Oil Prod Cum Gas Prod Cum Water Prod Cum Water Inj Cum Cum Total Inj (MI+Water) Net Res Voidage Net Voidage Cum Monthly VRR Date STB MSCF STB STB MSCF STB MSCF STB STB RB RVB RVB RVB/RVB Jul-21 143,177 237,031 326,800 457,134 397,461 41,313,975 43,367,570 26,951,767 64,861,844 88,633,836 -110,225 -2,219,305 1.19 Aug-21 140,597 328,568 309,897 450,141 127,341 41,454,572 43,696,138 27,261,664 65,311,985 89,163,610 91,052 -2,128,253 0.85 Sep-21 156,508 377,686 373,844 386,722 576,033 41,611,080 44,073,824 27,635,508 65,698,707 89,894,059 -3,159 -2,131,412 1.00 Oct-21 218,744 434,722 373,305 490,146 930,271 41,829,824 44,508,546 28,008,813 66,188,853 90,937,966 -233,060 -2,364,471 1.29 Nov-21 269,150 447,854 354,680 489,241 981,122 42,098,974 44,956,400 28,363,493 66,678,094 92,010,962 -232,350 -2,596,821 1.28 Dec-21 235,039 529,360 400,960 517,731 1,058,586 42,334,013 45,485,760 28,764,453 67,195,825 93,158,436 -239,649 -2,836,470 1.26 Jan-22 230,037 555,294 447,985 472,115 948,366 42,564,050 46,041,054 29,212,438 67,667,940 94,194,808 -69,805 -2,906,275 1.07 Feb-22 208,308 475,462 439,713 334,454 748,119 42,772,358 46,516,516 29,652,151 68,002,394 94,973,996 114,308 -2,791,968 0.87 Mar-22 277,059 745,278 473,259 395,199 702,579 43,049,417 47,261,794 30,125,410 68,397,593 95,787,669 328,630 -2,463,338 0.71 Apr-22 314,527 842,950 453,111 388,476 992,343 43,363,944 48,104,744 30,578,521 68,786,069 96,765,512 232,109 -2,231,229 0.81 May-22 339,927 876,361 464,782 392,625 1,159,239 43,703,871 48,981,105 31,043,303 69,178,694 97,846,014 181,541 -2,049,688 0.86 Jun-22 301,907 758,893 263,597 309,511 886,809 44,005,778 49,739,998 31,306,900 69,488,205 98,681,838 122,896 -1,926,792 0.87 8 7/21 – 6/22 ORION ANNUAL SURVEILLANCE REPORT FIGURE 1: ORION PRODUCTION AND INJECTION HIST ORY 9 7/21 – 6/22 ORION ANNUAL SURVEILLANCE REPORT FIGURE 2: ORION VOIDAGE HISTORY 10 7/21 – 6/22 ORION ANNUAL SURVEILLANCE REPORT TABLE 2: ORION PRESSURE SURVEY DETAIL 6. Oil Gravity: 15-23 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. B.H. 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) L-211 500292319700 WAG 640135 Oa, Oba, Obb, Obd 4042-4068, 4095-4123, 4141- 4154, 4240-4248, 4249-4257, 4262-4270, 4274-4282 6/23/2022 121 EXTR1 -0 1300 4400 0.127 1858.80 L-219 500292337600 WAG 640135 Obd 4660-4665, 4668-4672, 4676- 4679, 4682-4684, 4687-4689, 4691-46692 9/1/2021 600 SBHP -4651 1864 4400 0.44 1753.56 L-219 500292337600 WAG 640135 Obd 4660-4665, 4668-4672, 4676- 4679, 4682-4684, 4687-4689, 4691-46692 6/30/2022 408 SBHP -4651 1940 4400 0.44 1829.56 L-219 500292337600 WAG 640135 Oa 4412-4445 9/1/2021 600 SBHP -4362 1834 4400 0.44 1850.72 L-219 500292337600 WAG 640135 Oa 4412-4445 6/30/2022 408 SBHP -4362 1910 4400 0.44 1926.72 V-229 500292346400 WAG 640135 Oa 4337-4375 3/18/2022 1512 SBHP -4325 1739 4400 0.44 1772.00 V-229 500292346400 WAG 640135 Oba 4402-4431 3/18/2022 1512 SBHP -4395 1325 4400 0.44 1327.20 V-229 500292346400 WAG 640135 Obb 4445-4463 3/18/2022 1512 SBHP -4446 2345 4400 0.44 2324.76 V-229 500292346400 WAG 640135 Obc 4504-4514 3/18/2022 1512 SBHP -4499 2349 4400 0.44 2305.44 V-229 500292346400 WAG 640135 Obd 4553-4592 3/18/2022 1512 SBHP -4553 2152 4400 0.44 2084.68 V-219 500292339700 WAG 640135 Oba 4626-4654 4/15/2022 1104 SBHP -4613 1800 4400 0.44 1706.28 V-219 500292339700 WAG 640135 Obb 4667-4680 4/15/2022 1104 SBHP -4665 1890 4400 0.44 1773.40 V-219 500292339700 WAG 640135 Obe 4861-4866 4/15/2022 1104 SBHP -4752 2075 4400 0.44 1920.12 V-219 500292339700 WAG 640135 Oba 4626-4654 11/1/2021 432 SBHP -4613 2274 4400 0.44 2180.28 V-219 500292339700 WAG 640135 Obb 4667-4680 11/1/2021 432 SBHP -4665 2020 4400 0.44 1903.40 V-219 500292339700 WAG 640135 Obe 4861-4866 11/1/2021 432 SBHP -4752 2235 4400 0.44 2080.12 V-224 500292340000 WAG 640135 Obe 4903-4928 4/15/2022 1056 SBHP -4901 2260 4400 0.44 2039.56 V-224 500292340000 WAG 640135 Obd 4832-4881 4/15/2022 1056 SBHP -4801 2010 4400 0.44 1833.56 L-220 500292338700 WAG 640135 Oba 4318-4347 6/29/2022 3504 SBHP -4308 2440 4400 0.44 2480.48 L-220 500292338700 WAG 640135 Obd 4466-4511 6/29/2022 3504 SBHP -4457 2430 4400 0.44 2404.92 L-220 500292338700 WAG 640135 Obb/Obc 4360-4377, 4414-4431 6/29/2022 3504 SBHP -4362 2308 4400 0.44 2324.72 L-220 500292338700 WAG 640135 Oa 4250-4291 6/29/2022 3504 SBHP -4203 2269 4400 0.44 2355.68 L-220 500292338700 WAG 640135 Nb 4117-4136 6/29/2022 3504 SBHP -4052 2260 4400 0.44 2413.12 L-221 500292338500 WAG 640135 Obd 4433-4481 6/29/2022 648 SBHP -4426 2400 4400 0.44 2388.56 L-221 500292338500 WAG 640135 Oba 4286-4316 6/29/2022 648 SBHP -4276 2459 4400 0.44 2513.56 L-221 500292338500 WAG 640135 Obb/Obc 4329-4343, 4382-4396 6/29/2022 648 SBHP -4330 2251 4400 0.44 2281.80 L-221 500292338500 WAG 640135 Oa 4222-4258 6/29/2022 648 SBHP -4176 2293 4400 0.44 2391.56 L-221 500292338500 WAG 640135 Nb 4090-4105 6/29/2022 648 SBHP -4038 2226 4400 0.44 2385.28 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION RESERVOIR PRESSURE REPORT 1. Operator:2. Address: Hilcorp Alaska P.O. Box 196612, 900 E. Benson Blvd., Anchorage, AK 99519-6612 Prudhoe Bay Field, Orion Oil Pool Printed Name Title Date Reservoir Engineer September 12, 2022 4400 TVDss 0.7 3. Unit or Lease Name:4. Field and Pool:5. Datum Reference: Michael Mayfield 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 7. Gas Gravity: Prudhoe Bay Unit 11 7/21 – 6/22 ORION ANNUAL SURVEILLANCE REPORT FIGURE 3: ORION AVERAGE PRESSURE AT DATUM 12 7/21 – 6/22 ORION ANNUAL SURVEILLANCE REPORT TABLE 3: ORION MONTHLY AVERAGE OIL ALLOCATION FACTORS Date Allocation Factor Jul-21 0.84 Aug-21 0.81 Sep-21 0.81 Oct-21 0.90 Nov-21 0.86 Dec-21 0.86 Jan-22 0.83 Feb-22 0.81 Mar-22 0.89 Apr-22 0.87 May-22 0.88 Jun-22 0.99 1 7/21 – 6/22 POLARIS ANNUAL SURVEILLANCE REPORT 2022 ANNUAL SURVEILLANCE REPORT POLARIS OIL POOL PRUDHOE BAY UNIT JULY 1, 2021 – JUNE 30, 2022 2 7/21 – 6/22 POLARIS ANNUAL SURVEILLANCE REPORT CONTENTS 1. I NTRODUCTION ........................................................................................................................... 3 2. VOIDAGE BALANCE BY MONTH OF PRODUCED AND INJECTED FLUIDS (RULE 9 A)............................................ 3 3. ANALYSIS OF RESERVOIR PRESSURE SURVEYS WITHIN THE POOL (RULE 9B) .................................................. 3 4. RESULTS AND A NALYSIS OF PRODUCTION & INJECTION LOGGING S URVEYS, AND S PECIAL MONITORING (RULE 9C) . 4 5. REVIEW OF P OOL PRODUCTION ALLOCATION (RULE 9 D) AND REVIEW OF POOL PRODUCTION ALLOCATION FAC TORS AND ISSUES (RULE 4 D) ................................................................................................................. 4 6. P ROGRESS OF E NHANCED RECOVERY PROJECT IMPLEMENTATION AND RESERVOIR MANAGEMENT SUMMARY (RULE 9E) .....................................................................................................................................................55 7. RESULTS OF MONITORING TO DETERMINE E NRICHED GAS INJECTANT BREAKTHROUGH TO OFFSET PRODUCERS (RULE 9F) ..............................................................................................................................................6 8. FUTURE DEVELOPMENT PLANS……………………………………………………………………………………………………………..……. 6 LIST OF ATTACHMENTS Figure 1: Polaris production and injection history .........................................................................................8 Figure 2: Polaris voidage history ...................................................................................................................8 Figure 3: Polaris pressure at datum ............................................................................................................ 10 Table 1: Polaris monthly production and injection summary .........................................................................7 Table 2: Polaris pressure survey detail ..........................................................................................................9 Table 3: Polaris monthly average oil allocation factors ................................................................................ 11 3 7/21 – 6/22 POLARIS ANNUAL SURVEILLANCE REPORT PRUDHOE BAY UNIT 2022 POLARIS OIL POOL ANNUAL SURVEILLANCE REPORT 1. I NTRODUCTION This Annual Surveillance Report is submitted to the Alaska Oil and Gas Conservation Commission for the Polaris Oil Pool in accordance with Commission regulations and Conservation Order 484A. This report covers the period from July 1, 2021 through June 30, 2022. 2. VOIDAGE BALANCE BY MONTH OF PRODUCED AND INJECTED FLUIDS (RULE 9A) During the reporting period, field production averaged 7,556 BOPD, 13,641 MMSCFD (FGOR 1,805 SCF/STB), and 5,517 BWPD (WC 42 %). Water injection during this period averaged 8,897 BWIPD with 16,710 MMSCFD of miscible gas injection. The average voidage replacement ratio was 1.06. Monthly production, injection, and voidage volumes for the reporting period are summarized in Table 1. Figures 1 and 2 graphically depict this information since field start-up. 3. ANALY SIS OF RESERVOIR PRESSURE SURVEYS WITHIN THE POOL (RULE 9B) Reservoir pressure monitoring is performed in accordance with Rule 5 of Conservation Order 484A. The pressures reported in Table 2 are representative of the four pressure areas. This data was acquired using static bottom hole pressure surveys (SBHP) and permanent downhole gauges installed in injectors. Figure 3 illustrates Polaris pressure data since field inception at the Pool datum of 5000 ft TVDss (true vertical depth subsea). For the period of July 1, 2022 to June 30, 2023, a minimum of one pressure survey will be taken in each of the active representative areas that contain active wells. An analysis of the recent pressure data by polygon follows: S-Pad North This polygon contains producers S-202 and M-200 and is supported by injectors S-104, S201, S210, and M- 201. Measured pressure in this polygon is 2184 psi. S-Pad South This polygon contains producer S-213A and is supported by injectors S-215i, S-217i and S-218i. Measured pressure in this polygon is 1859 psi. W-Pad North This polygon contains producers W-200, W-201, W-202, W-204, W-205, and W-211 and is supported by injectors W-209i, W-212i, W-213i, W-214i, W-215i, W-216i, W-217i, W-218i, W-219i, W-220i, W-221i, and W-223i. Measured pressures in this polygon average is 2029 psi. 4 7/21 – 6/22 POLARIS ANNUAL SURVEILLANCE REPORT W-Pad East This polygon contains producer W-203 and is supported by injectors W-207i, W-210i, and W-01. Measured pressure in the polygon was 2161 psi. 4. RESULTS AND ANALYSIS OF PRODUCTION & INJECTION LOGGING SURVEYS, AND SPECIAL M ONITORING (RULE 9C) Production Logs: No production logs were run during the reporting period. Prior production logs have frequently been adversely affected by well slugging. Future production logging candidates will be evaluated on a case-by-case basis. Well fluids sampling A well fluids sampling program is ongoing to gather high quality and frequency surveillance data: (1) Uncontaminated wellhead samples are obtained monthly to quarterly on each producer, and tested for API, viscosity, WC, and sand quantity. This data helps track changes in production from different sands, waterflood or MI response, and sanding tendencies. (2) Wellhead samples are analysed quarterly for water properties to identify changes between formation water production and waterflood breakthrough. This data is also useful for identifying matrix bypass events (MBE) because produced water will have similar properties as injected water. (3) A produced water supply sample is analysed quarterly to serve as a baseline for analysis of well production samples. (4) Gas sampling is done monthly or quarterly depending on WAG activity in the polygon to establish gas chromatography signatures and track returned miscible injectant (MI). Injection Logs: No new injection logs were run in this area. Injection logs are typically run to quality check waterflood regulating valve performance while in water service or to determine the distribution of miscible injectant between zones. Real-time Downhole Pressure Gauges in Injectors Monitoring of individual zonal pressures is continuing for all injectors with downhole gauges installed. Real- time data has confirmed offtake from offset producers, formation and healing of MBE’s, pressure transmission across the OWC, and helped tremendously in identifying underperforming injection zones. 5. REVIEW OF POOL PRODUCTION ALLOCATION (RULE 9D) AND REVIEW OF POOL PRODUCTION ALLOCATION FACTORS AND ISSUES (RULE 4D) Production allocation is based on well tests and conducted in accordance with 20 AAC 25.230. The monthly averages of daily oil production allocation factors are shown in Table 3. Electronic files containing daily allocation data and daily test data for a minimum of five years are being retained. 5 7/21 – 6/22 POLARIS ANNUAL SURVEILLANCE REPORT 6. PROGRESS OF ENHANCED RECOVERY PROJECT IMPLEMENTATION AND RESERVOIR MANAGEMENT SUMMARY (RULE 9E ) Enhanced Recovery Project - Waterflood: Primary production from the Polaris oil pool commenced in 1999 and continued until waterflood was initiated in 2003. The waterflood patterns are designed to maintain reservoir pressure above the bubble point pressure and as close to the original reservoir pressure as possible. Because of differences in rock and oil quality, the various sands behave like different reservoirs connected in the same wellbore, thereby requiring a much higher degree of control in the injectors to manage voidage. The basis of design for water injectors has evolved to include isolation packers between sands to accurately control injection rate into the vastly different sands. Injection rate into each zone is controlled by downhole waterflood regulating valves installed in mandrels adjacent to the target sand. To prevent freezing, a minimum injection rate of 500 BWIPD is being used for all new waterflood regulating valve designs. In patterns where the minimum injection rate results in a high voidage replacement ratio, injectors in the pattern are cycled. During the reporting period, average injection rate was 8,897 BWIPD. Cumulative injection through June 2021 was 42.7 MMSTBW. Enhanced Recovery Project - Miscible Injectant: In 2005, approval to implement an enhanced oil recovery project in Polaris oil pool using Prudhoe Bay miscible injectant was granted via C.O. 484A. Injection of miscible injectant began in early 2006 in the downdip portion of W Pad North. The current MI strategy is to inject smaller slugs of miscible injectant to improve the efficiency of the flood. To date, miscible injectant has been injected in S Pad South, S pad North, W Pad North, and W Pad East. During the reporting period, average injection rate was 16.7 MMSCFD. Cumulative injection through June 2021 was 19.1 BCF. Reservoir Management Strategy: The objective of the Polaris oil pool reservoir management strategy is to manage rese rvoir development and depletion to maximize commercial production consistent with prudent oil field engineering practices. Key to this is achieving a balanced voidage replacement ratio required to keep reservoir pressure above the bubble point. Individual floods will be managed with downhole waterflood regulating valves in the injectors, as well as limited capabilities of reducing offtake in the producers by shutting in or choking laterals. Learnings over the last few years have revealed significant differences in productivity and oil mobility between Schrader Bluff sands. These learnings have led to changes in completion designs and operational strategies. In addition, the emergence of matrix bypass events has further highlighted the complexity of the Schrader Bluff sands. It is expected that the reservoir management strategy will continually be evaluated and revised as appropriate throughout the life of the field. 6 7/21 – 6/22 POLARIS ANNUAL SURVEILLANCE REPORT Matrix Bypass Events: As described in prior reports, the phenomenon of premature water breakthrough between a producer and a water source (water injector or aquifer) challenges the North Slope viscous oil developments. These events appear to have a multitude of probable causes: faults, fractures, matrix short-circuit through high perm streaks, and what is believed to be the creation of tunnels or “worm holes”. During the reporting period, no new matrix bypass events were identified. 7. RESULTS OF MONITORING TO DETERMINE ENRICHED GAS INJECTANT BREAKTHROUGH TO OFFSET PRODUCERS (RULE 9F) A response to miscible injectant is indicated by an increase in produced gas rate, an increase in formation gas-oil-ratio, and a reduction in the producing ratio of C1 (methane) to C3 (propane). During the reporting period, W-204, W-202, W-201, W-205, W-203, S-213A, S-202 responded positively to miscible injectant. 8. Future Development Plans Future development plans are discussed in the 2022 update to the Plan of Development for the Orion Participating Area, which was filed with the Division of Oil and Gas of the Alaska Department of Natural Resources on September 30, 2022, a copy of which was provided to the Commission. The Commission will be copied when the 2023 update of the Orion Plan of Development is filed with the Division. 7 7/21 – 6/22 POLARIS ANNUAL SURVEILLANCE REPORT TABLE 1: POLARIS MONTHLY PRODUCTION AND INJECTION SUMMARY Report Oil Prod Gas Prod Water Prod Water Inj MI Inj Oil Prod Cum Gas Prod Cum Water Prod Cum Water Inj Cum Cum Total Inj (MI+Water) Net Res Voidage Net Voidage Cum Monthly VRR Date STB MSCF STB STB MSCF STB MSCF STB STB RB RVB RVB RVB/RVB Jul-21 176,404 217,478 78,241 234,782 261,581 29,153,388 27,633,399 21,083,061 39,709,005 48,065,139.-44,787 9,600,937 1.13 Aug-21 275,748 333,540 148,034 154,059 196,680 29,429,136 27,966,939 21,231,095 39,863,064 48,338,747 268,964 9,869,901 0.50 Sep-21 267,129 383,777 152,318 147,506 814,696 29,696,265 28,350,716 21,383,413 40,010,570 48,976,546 -81,414 9,788,486 1.15 Oct-21 217,411 456,770 261,183 325,199 711,417 29,913,676 28,807,486 21,644,596 40,335,769 49,731,847 -112,052 9,676,435 1.17 Nov-21 209,796 444,070 216,901 363,637 508,444 30,123,472 29,251,556 21,861,497 40,699,406 50,404,187 -85,922 9,590,513 1.15 Dec-21 236,885 487,258 225,916 348,517 442,400 30,360,357 29,738,814 22,087,413 41,047,923 51,021,629 20,435 9,610,948 0.97 Jan-22 231,221 498,561 207,776 390,570 375,310 30,591,578 30,237,375 22,295,189 41,438,493 51,641,291 -1,664 9,609,283 1.00 Feb-22 225,970 436,342 161,962 311,928 456,409 30,817,548 30,673,717 22,457,151 41,750,421 52,230,183 -44,703 9,564,580 1.08 Mar-22 228,136 420,253 142,211 281,836 561,370 31,045,684 31,093,970 22,599,362 42,032,257 52,851,660 -100,863 9,463,717 1.19 Apr-22 219,748 350,912 144,393 260,491 609,009 31,265,432 31,444,882 22,743,755 42,292,748 53,480,161 -138,885 9,324,832 1.28 May-22 256,200 515,002 152,191 233,647 646,351 31,521,632 31,959,884 22,895,946 42,526,395 54,103,955 -31,275 9,293,557 1.05 Jun-22 213,387 435,156 122,613 195,099 515,402 31,735,019 32,395,040 23,018,559 42,721,494 54,610,246 -14,744 9,278,813 1.03 8 7/21 – 6/22 POLARIS ANNUAL SURVEILLANCE REPORT FIGURE 1: POLARIS PRODUCTION AND INJECTION HISTORY FIGURE 2: POLARIS VOIDAGE HISTORY 9 7/21 – 6/22 POLARIS ANNUAL SURVEILLANCE REPORT TABLE 2: POLARIS PRESSURE SURVEY DETAIL 6. Oil Gravity: 15-23 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. B.H. 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) W-218 500292340300 WAG 64160 Oba 4948-4970 09/09/21 672 SBHP -5011 2040 5000 0.440 2035 W-218 500292340300 WAG 64160 Obc 5032-5055 09/09/21 672 SBHP -5006 2060 5000 0.440 2057 W-218 500292340300 WAG 64160 Obd 5087-5127 09/09/21 672 SBHP -5092 2035 5000 0.440 1995 W-210 500292333900 WAG 64160 Oba 4893 - 4922 08/25/21 888 SBHP -4671 2016 5000 0.440 2161 S-210 500292363000 WAG 64160 Obd 5187-5189 + 5288-5300 05/21/22 1632 PFO -5202 2273 5000 0.440 2184 S-215 500292310700 WAG 64160 Obd 5169-5196 11/19/21 1584 SBHP -5151 1925 5000 0.440 1859 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION RESERVOIR PRESSURE REPORT 1. Operator:2. Address: BP Exploration (Alaska) Inc.P.O. Box 196612, 900 E. Benson Blvd., Anchorage, AK 99519-6612 Prudhoe Bay Field, Polaris Oil Pool Printed Name Title Date Reservoir Engineer September 13th, 2021 5000 TVDss 0.7 3. Unit or Lease Name:4. Field and Pool:5. Datum Reference: Michael Mayfield 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 7. Gas Gravity: Prudhoe Bay Unit 10 7/21 – 6/22 POLARIS ANNUAL SURVEILLANCE REPORT FIGURE 3: POLARIS AVERAGE PRESSURE AT DATUM 11 7/21 – 6/22 POLARIS ANNUAL SURVEILLANCE REPORT TABLE 3: POLARIS MONTHLY AVERAGE OIL ALLOCATION FACTORS Date Allocation Factor Jul-21 0.84 Aug-21 0.81 Sep-21 0.81 Oct-21 0.90 Nov-21 0.86 Dec-21 0.86 Jan-22 0.83 Feb-22 0.81 Mar-22 0.89 Apr-22 0.87 May-22 0.88 Jun-22 0.99 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) 640158 Midnight Sun 8050 160 21 540 18 1.68 1.68 4045 4045 3265 27 0.725 94 59 1.3 1.3 0.86 717 11058 640135 Orion 4400 87 27.6 220 46.5 11.2 11 1950 1836 2086 18.7 .7 415 98 1.12 1.12 .830 272 2331 640160 Polaris 5000 98 26.4 78 54 8 7.4 2250 2013 2048 18.2 .65 391 91 1.15 1.15 .868 310 1805 640120 Aurora 6700 150 18 44 45 .72 0.72 3423 3464 3556 29.1 .72 112 53 1.35 1.35 .858 717 3294 640130 Borealis 6600 158 18 22 44 2.97 2.81 3442 2761 3009 24.1 .72 141 36 1.23 1.24 .861 457 3987 Reservoir Engineer 9/12/2022 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION ANNUAL RESERVOIR PROPERTIES REPORT 1. Operator:2. Address: Tim Davis I hereby certify that the foregoing is true and correct to the best of my knowledge. Tim DavisSignature Hilcorp Alaska, LLC.3800 Centerpoint Dr. Anchorage, AK 99516 Printed Name Title Date Form 10-428 Rev. 05/2017 INSTRUCTIONS ON REVERSE SIDE