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Home My WebLink About2021 Prudhoe Satellite Oil Pools1 7/20 – 6/21 ORION ANNUAL SURVEILLANCE REPORT 2021 ANNUAL SURVEILLANCE REPORT ORION OIL POOL PRUDHOE BAY UNIT JULY 1,2020 –JUNE 30,2021 2 7/20 – 6/21 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) ....................................................................... 5 6.PROGRESS OF ENHANCED RECOVERY PROJECT IMPLEMENTATION AND RESERVOIR MANAGEMENT SUMMARY (RULE 9E) ....................................................................................................... 6 7.PROGRESS OF PLANS AND TESTS TO EXPAND THE PRODUCTIVE LIMITS OF THE POOL (RULE 9F) ........7 8.RESULTS OF MONITORING TO DETERMINE ENRICHED GAS INJECTANT BREAKTHROUGH TO OFFSET PRODUCERS (RULE 9G) ....................................................................................................7 9.FUTURE DEVELOPMENT PLANS .......................................................................................................... 7 LIST OF ATTACHMENTS Figure 1: Orion production and injection history ......................................................................................... 9 Figure 2: Orion voidage history ................................................................................................................. 10 Figure 3: Orion pressures at datum ........................................................................................................... 12 Table 1: Orion monthly production and injection summary ......................................................................... 8 Table 2: Orion pressure survey detail ........................................................................................................ 11 Table 3: Orion monthly average oil allocation factors ................................................................................ 13 3 7/20 – 6/21 ORION ANNUAL SURVEILLANCE REPORT PRUDHOE BAY UNIT 2020 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, 2020 to June 30, 2021. 2.VOIDAGE BALANCE BY MONTH OF PRODUCED AND INJECTED FLUIDS (RULE 9A) During the reporting period, field production averaged 4,056 BOPD, 8.3 MMSCFD (FGOR 2,047 SCF/STB), and 10,648 BWPD (WC 72 %). Water injection during this period averaged 12,609 BWIPD with 10,238 MMSCFD of miscible gas injection. The average voidage replacement ratio was 1.00. 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 bottomhole 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, 2021 to June 30th, 2022, a minimum of one pressure survey will be taken in each of the active representative areas that contain active wells. Acquiring representative regional average pressures continues to be a challenge in Orion wells due to the physical characteristics of viscous oil, multiple sand targets, and multilateral producer wellbores which present a paradigm shift from typical data acquisition in light-oil reservoirs. Pressure gradients around producers and injectors are very shallow due to the low mobility of viscous oil, which results in very slow build-up and fall-off of pressures. Obtaining representative reservoir pressures is further complicated by significant differences in rock and oil properties between sands in the same wellbore, and as a result, productivity (and average sand pressure) varies dramatically between sands. Multilateral producers experience crossflow between laterals completed in different Schrader Bluff sands while shut-in, which can result in uneven zonal recharge. Injectors also suffer from slow bleed-off rates. Most injectors now incorporate check valves in the waterflood regulators to limit cross flow, but cross flow can occur where check valves are not present or not holding. These phenomena combine to make the quality of pressure transient analysis (PTA) questionable, and therefore, extrapolating a representative average reservoir pressure from pressure build-up (PBU) or pressure fall-off (PFO) data is difficult. In order to mitigate these concerns, single point pressure surveys are obtained whenever possible after a well has been offline for several weeks or months 4 7/20 – 6/21 ORION ANNUAL SURVEILLANCE REPORT to allow maximum build-up or fall-off. Even after a long shut-in time, wells show build-up or fall-off rates of several psi per day. In light of these challenges, significant effort is being made to obtain high-quality initial pre-injection or pre-production pressure surveys relatively unaffected by pressure gradients applied to the wellbore. Whenever possible, initial pressures by zone are being obtained with an MDT in new producers, or via downhole gauges in injectors. Injector data is becoming increasingly important as the flood matures. Once development is completed, this becomes the only practical way to collect pressure data on a zonal basis. An analysis of the recent pressure data by polygon follows: Polygon 1 This polygon contains producer L-200 and is supported by injectors L-211i, L-212i, and L-218i. During the reporting period, no new pressures were acquired as there was no production or injection from the polygon. 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 1772 psi. Polygon 2 This polygon contains producers V-202, V-203, V-204, V-205 and is supported by injectors L-213i, V-210i, V- 211i, V-212i, V-213i, V-214i, V-215i, V-216i, V-217i, V-218i, V-222i, V-223i, V-225i, V-229i. Measured pressures in the polygon averaged 1899 psi. Polygon 2A 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, V-224i, and V-227i. Measured pressures in the polygon averaged 1769 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 2197 psi. Producer L-205A was offline for most of the reporting period due flow assurance issues caused by low flow rates. 4.RESULTS AND ANALYSIS OF PRODUCTION &INJECTION LOGGING SURVEYS, AND SPECIAL MONITORING (RULE 9C) Production Logs: No new production logs have been gathered over the reporting period. 5 7/20 – 6/21 ORION ANNUAL SURVEILLANCE REPORT Well Fluids Sampling: A well fluids sampling program is ongoing to gather high 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. A portion of these samples is later used for geochemical production allocation analysis. (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). Geochemical Fingerprinting: This technique has been in use since 1999 in the North Slope viscous oil developments and has shown promise in obtaining snapshot relative oil flow splits from individual sands. This data is useful in gauging zonal well performance, identifying problem laterals, and providing a basis by which to optimize offset injection. Wellhead oil samples are taken on roughly a quarterly basis, or as well performance changes. Results to date are mixed with reasonable allocations in some wells, but questionable data in others. Work is ongoing to gather additional baseline oil samples and improve analysis techniques to improve data value. Injection Logs: No injection logs were run during the reporting period. 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 4, PART (F)) 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 7/20 – 6/21 ORION ANNUAL SURVEILLANCE REPORT 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 12,609 BWIPD. Cumulative injection through June 2021 was 64.4 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 1A, Polygon 2, Polygon 2A, and Polygon 5. During the reporting period, average injection rate was 10.2 MMSCFD. Cumulative injection through June 2020 was 38.8 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 required 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 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. 7 7/20 – 6/21 ORION 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.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 MONITORING 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, and V-207. 9.FUTURE DEVELOPMENT PLANS Future development plans are discussed in the 2021 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 January 27, 2021, followed by an amendment on July 15th, 2021. A copy of each was provided to the Commission. The Commission will be copied when the 2022 update of the Western Satellites Plan of Development is filed with the Division. 8 7/20 – 6/21 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-20 127,354 283,176 309,472 371,169 278,356 39,817,818 40,383,846 23,047,946 60,173,717 81,623,821 43,769 -2,125,398 0.92 Aug-20 122,300 245,708 269,015 391,296 194,078 39,940,118 40,629,554 23,316,961 60,565,013 82,133,536 6,100 -2,119,298 0.99 Sep-20 96,605 194,188 280,571 371,273 252,058 40,036,723 40,823,742 23,597,532 60,936,286 82,657,236 -47,440 -2,166,738 1.10 Oct-20 107,006 187,314 350,843 402,280 318,632 40,143,729 41,011,056 23,948,375 61,338,566 83,251,532 -42,685 -2,209,423 1.08 Nov-20 118,691 210,125 315,833 314,705 316,786 40,262,420 41,221,181 24,264,208 61,653,271 83,756,288 34,426 -2,174,997 0.94 Dec-20 122,012 267,744 323,203 349,771 391,517 40,384,432 41,488,925 24,587,411 62,003,042 84,340,552 -952 -2,175,949 1.00 Jan-21 123,746 300,329 297,983 384,797 370,959 40,508,178 41,789,254 24,885,394 62,387,839 84,948,062 -29,040 -2,204,989 1.05 Feb-21 108,778 267,927 261,793 396,911 276,949 40,616,956 42,057,181 25,147,187 62,784,750 85,512,342 -53,612 -2,258,601 1.10 Mar-21 117,150 256,916 294,591 442,556 284,108 40,734,106 42,314,097 25,441,778 63,227,306 86,126,948 -70,521 -2,329,122 1.13 Apr-21 127,379 219,236 330,896 372,403 294,216 40,861,485 42,533,333 25,772,674 63,599,709 86,676,662 17,099 -2,312,022 0.97 May-21 142,233 273,477 437,310 382,726 417,339 41,003,718 42,806,810 26,209,984 63,982,435 87,309,445 85,552 -2,226,471 0.88 Jun-21 167,080 323,729 414,983 422,275 341,841 41,170,798 43,130,539 26,624,967 64,404,710 87,937,629 117,392 -2,109,079 0.84 9 7/20 – 6/21 ORION ANNUAL SURVEILLANCE REPORT FIGURE 1: ORION PRODUCTION AND INJECTION HISTORY 10 7/20 – 6/21 ORION ANNUAL SURVEILLANCE REPORT FIGURE 2: ORION VOIDAGE HISTORY 11 7/20 – 6/21 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-219 500292337600 WAG 640135 Oa 4412-4445 3/16/2021 44328 SBHP -4362 1821 4400 0.44 1837.72 L-219 500292337600 WAG 640135 Obd 4660-4665, 4668-4672,3/16/2021 44328 SBHP -4651 1818 4400 0.44 1707.56 L-213 500292330800 WAG 640135 Oa 4218-4250 8/19/2020 15 PFO -4230 1730 4400 0.44 1804.8 L-213 500292330800 WAG 640135 Oba/Obb 4318-4333, 4277-4307 8/28/2020 15 PFO -4300 2114 4400 0.44 2158 L-213 500292330800 WAG 640135 Obc 4374-4385 9/3/2020 15 PFO -4380 2034 4400 0.44 2042.8 L-213 500292330800 WAG 640135 Obd 4423-4469 9/8/2020 15 PFO -4440 1514 4400 0.44 1496.4 V-219 500292339700 WAG 640135 Oba 4626-4654 7/20/2020 48 SBHP -4613 1706 4400 0.44 1612.28 V-219 500292339700 WAG 640135 Obb 4667-4680 7/20/2020 48 SBHP -4665 2020 4400 0.44 1903.4 V-219 500292339700 WAG 640135 Obe 4861-4866 7/20/2020 48 SBHP -4752 2015 4400 0.44 1860.12 V-224 500292340000 WAG 640135 Obe 4903-4928 3/16/2021 3456 SBHP -4901 2050 4400 0.44 1829.56 V-224 500292340000 WAG 640135 Obd 4832-4881 3/16/2021 3456 SBHP -4801 1814 4400 0.44 1637.56 L-220 500292338700 WAG 640135 Oba 4318-4347 10/16/2020 548 SBHP -4308 2272 4400 0.44 2312.48 L-220 500292338700 WAG 640135 Obd 4466-4511 10/16/2020 548 SBHP -4457 2251 4400 0.44 2225.92 L-220 500292338700 WAG 640135 Obb/Obc4360-4377, 4414-443110/16/2020 548 SBHP -4362 2210 4400 0.44 2226.72 L-220 500292338700 WAG 640135 Oa 4250-4291 10/16/2020 548 SBHP -4203 2105 4400 0.44 2191.68 L-220 500292338700 WAG 640135 Nb 4117-4136 10/16/2020 548 SBHP -4052 1907 4400 0.44 2060.12 L-221 500292338500 WAG 640135 Obd 4433-4481 11/19/2020 12720 SBHP -4426 2267 4400 0.44 2255.56 L-221 500292338500 WAG 640135 Oba 4286-4316 11/19/2020 12720 SBHP -4276 2185 4400 0.44 2239.56 L-221 500292338500 WAG 640135 Obb/Obc4329-4343, 4382-439611/19/2020 12720 SBHP -4330 2174 4400 0.44 2204.8 L-221 500292338500 WAG 640135 Oa 4222-4258 11/19/2020 12720 SBHP -4176 2094 4400 0.44 2192.56 L-221 500292338500 WAG 640135 Nb 4090-4105 11/19/2020 12720 SBHP -4038 1903 4400 0.44 2062.28 3. Unit or Lease Name:4. Field and Pool:5. Datum Reference: Micheal 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 Prudhoe Bay Field, Orion Oil Pool Printed Name Title Date Reservoir Engineer September 14, 2021 4400 TVDss 0.7 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 12 7/20 – 6/21 ORION ANNUAL SURVEILLANCE REPORT FIGURE 3: ORION AVERAGE PRESSURE AT DATUM 13 7/20 – 6/21 ORION ANNUAL SURVEILLANCE REPORT TABLE 3: ORION MONTHLY AVERAGE OIL ALLOCATION FACTORS Date Allocation Factor Jul-20 0.88 Aug-20 0.84 Sep-20 0.83 Oct-20 0.82 Nov-20 0.81 Dec-20 0.83 Jan-21 0.84 Feb-21 0.82 Mar-21 0.85 Apr-21 0.85 May-21 0.84 Jun-21 0.81 1 7/20 – 6/21 POLARIS ANNUAL SURVEILLANCE REPORT 2021 ANNUAL SURVEILLANCE REPORT POLARIS OIL POOL PRUDHOE BAY UNIT JULY 1,2020 –JUNE 30,2021 2 7/20 – 6/21 POLARIS 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 4D)......................................................................................................................... 5 6.Progress of Enhanced Recovery Project Implementation and Reservoir Management Summary (Rule 9e) ........................................................................................................................................ 5 7.Results of Monitoring to Determine Enriched Gas Injectant Breakthrough to Offset Producers (Rule 9f) ......................................................................................................................................... 6 8. Future Development Plans ………………………………………………………………………………………………………………..7 LIST OF ATTACHMENTS FIGURE 1:POLARIS PRODUCTION AND INJECTION HISTORY .............................................................................. 9 FIGURE 2:POLARIS VOIDAGE HISTORY ....................................................................................................... 9 FIGURE 3:POLARIS PRESSURE AT DATUM ................................................................................................. 11 TABLE 1:POLARIS MONTHLY PRODUCTION AND INJECTION SUMMARY ................................................................ 8 TABLE 2:POLARIS PRESSURE SURVEY DETAIL ............................................................................................. 10 TABLE 3:POLARIS MONTHLY AVERAGE OIL ALLOCATION FACTORS ................................................................... 12 3 7/20 – 6/21 POLARIS ANNUAL SURVEILLANCE REPORT PRUDHOE BAY UNIT 2021 POLARIS OIL POOL ANNUAL SURVEILLANCE REPORT 1.INTRODUCTION 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, 2020 through June 30, 2021. 2.VOIDAGE BALANCE BY MONTH OF PRODUCED AND INJECTED FLUIDS (RULE 9A) During the reporting period, field production averaged 7,420 BOPD, 9.6 MMSCFD (FGOR 1,306 SCF/STB), and 5,759 BWPD (WC 44 %). Water injection during this period averaged 9,636 BWIPD with 9.7 MMSCFD of miscible gas injection. The average voidage replacement ratio was 0.91. 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 484A. The pressures reported in Table 2 are representative of the four pressure areas. This data was acquired using static bottomhole 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, 2021 to June 30th, 2022, a minimum of one pressure survey will be taken in each of the active representative areas that contain active wells. Acquiring representative regional average pressures continues to be a challenge in Polaris wells due to the physical characteristics of viscous oil, three sand targets, and multilateral producer wellbores which present a paradigm shift from typical data acquisition in light-oil reservoirs. Pressure gradients around producers and injectors are very shallow due to the low mobility of viscous oil, which results in very slow build-up and fall-off of pressures. Obtaining representative reservoir pressures is further complicated by significant differences in rock and oil properties between sands in the same wellbore, and as a result, productivity (and average sand pressure) varies dramatically between sands. Multilateral producers experience cross-flow between laterals completed in different sands and uneven zonal recharge during shut-in. Injectors also suffer from slow bleed-off rates during shut-in. Most injectors now incorporate check valves in the waterflood regulators to limit cross flow, but cross flow can occur where check valves are not present or not holding. These phenomena combine to make the quality of pressure transient analysis (PTA) very questionable, and therefore, extrapolating a representative average reservoir pressure from pressure build- up (PBU) pressure fall-off (PFO) data is very difficult. In order to mitigate these concerns, single point pressure surveys are obtained whenever possible after a well has been offline for several weeks or months to allow maximum build-up or fall-off. Even after a long shut-in time, wells show build-up or fall-off rates of several psi per day. 4 7/20 – 6/21 POLARIS ANNUAL SURVEILLANCE REPORT In light of these challenges, significant effort is being made to obtain high-quality initial pre-injection or pre- production pressure surveys relatively unaffected by pressure gradients applied to the wellbore. Whenever possible, initial pressures by zone are being obtained with an MDT in new producers, or via downhole gauges in injectors. Injector data is expected to become increasingly important as the flood matures. Once development is completed, this becomes the only practical way to collect pressure data on a zonal basis. An analysis of the recent pressure data by polygon follows: S-Pad North This polygon contains producer S-202 and is supported by injectors S-104, S201, S210.Measured pressure in this polygon is 2601 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 1112 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 1926 psi. W-Pad East This polygon contains producer W-203 and is supported by injectors W-207i and W-210i. Measured pressure in the polygon was 2145 psi. 4.RESULTS AND ANALYSIS OF PRODUCTION &INJECTION LOGGING SURVEYS, AND SPECIAL MONITORING (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. A portion of these samples are later used for geochemical production allocation analysis. (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 5 7/20 – 6/21 POLARIS ANNUAL SURVEILLANCE REPORT on WAG activity in the polygon to establish gas chromatography signatures and track returned miscible injectant (MI). Geochemical Fingerprinting This technique has been in use since 1999 in the North Slope viscous oil developments and has shown promise in obtaining a snapshot or relative oil flow splits from individual sands. This data is useful in gauging zonal well performance, identifying problem laterals, and providing a basis by which to optimize offset injection. Wellhead oil samples are taken on roughly a quarterly basis, or as well performance changes. Results to date are mixed with reasonable allocations in some wells, but questionable data in others. Work is ongoing to gather additional baseline oil samples and improve analysis techniques to improve data value. 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 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 zones. 5.REVIEW OF POOL PRODUCTION ALLOCATION (RULE 9D) AND REVIEW OF POOL PRODUCTION ALLOCATION FACTORS AND ISSUES (RULE 4, PART (D)) 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. 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 6 7/20 – 6/21 POLARIS ANNUAL SURVEILLANCE REPORT 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 5,759 BWIPD. Cumulative injection through June 2021 was 39.5 MMSTBW, which has been injected into 21 water injectors. 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 9.7 MMSCFD. Cumulative injection through June 2021 was 13 BCF, which has been injected into 15 water-alternating-gas injectors. Reservoir Management Strategy: The objective of the Polaris 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 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. 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 responded positively to miscible injectant. 7 7/20 – 6/21 POLARIS ANNUAL SURVEILLANCE REPORT 8. Future Development Plans Future development plans are discussed in the 2021 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 January 27, 2021, followed by an amendment on July 15th, 2021. A copy of each was provided to the Commission. The Commission will be copied when the 2022 update of the Western Satellites Plan of Development is filed with the Division. 8 7/20 – 6/21 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-20 149,607 186,651 147,104 284,982 278,364 26,418,133 24,064,711 19,049,927 36,242,162 42,442,085. -75,737 8,861,910 1.20 Aug-20 188,287 204,574 173,289 284,935 395,769 26,606,420 24,269,285 19,223,216 36,527,097 42,967,331 -78,282 8,783,629 1.18 Sep-20 215,190 271,018 207,445 286,153 407,328 26,821,610 24,540,303 19,430,661 36,813,250 43,500,742 9,234 8,792,863 0.98 Oct-20 223,710 313,499 220,033 331,022 225,297 27,045,320 24,853,802 19,650,694 37,144,272 43,970,253 118,089 8,910,952 0.80 Nov-20 212,298 280,093 195,785 379,556 226,219 27,257,618 25,133,895 19,846,479 37,523,828 44,489,336 14,939 8,925,891 0.97 Dec-20 236,592 337,609 198,156 287,032 285,295 27,494,210 25,471,504 20,044,635 37,810,860 44,950,415 129,098 9,054,989 0.78 Jan-21 262,267 346,668 174,810 303,348 233,786 27,756,477 25,818,172 20,219,445 38,114,208 45,397,068 145,725 9,200,714 0.75 Feb-21 206,289 243,915 151,152 286,141 184,683 27,962,766 26,062,087 20,370,597 38,400,349 45,796,880 62,663 9,263,377 0.86 Mar-21 223,120 240,091 162,594 334,107 179,154 28,185,886 26,302,178 20,533,191 38,734,456 46,241,821 40,133 9,303,510 0.92 Apr-21 247,007 326,729 169,777 293,243 290,294 28,432,893 26,628,907 20,702,968 39,027,699 46,712,172 92,887 9,396,398 0.84 May-21 275,583 403,890 160,426 214,390 387,366 28,708,476 27,032,797 20,863,394 39,242,089 47,161,126 173,781 9,570,179 0.72 Jun-21 268,508 383,124 141,426 232,134 459,133 28,976,984 27,415,921 21,004,820 39,474,223 47,671,061 75,544 9,645,723 0.87 9 7/20 – 6/21 POLARIS ANNUAL SURVEILLANCE REPORT FIGURE 1: POLARIS PRODUCTION AND INJECTION HISTORY FIGURE 2: POLARIS VOIDAGE HISTORY 10 7/20 – 6/21 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) S-215 500292310700 WAG 64160 Oa 4989-5016 03/15/21 340 SBHP -4975 1101 5000 0.440 1112 W-213 500292335400 WAG 64160 Oba 4871-4894 08/03/20 3600 SBHP -4672 2158 5000 0.440 2302 W-218 500292340300 WAG 64160 Oba 4948-4970 10/28/20 144 SBHP -5011 1668 5000 0.440 1663 W-218 500292340300 WAG 64160 Obc 5032-5055 10/28/20 144 SBHP -5006 1900 5000 0.440 1897 W-218 500292340300 WAG 64160 Obd 5087-5127 10/28/20 144 SBHP -5092 1881 5000 0.440 1841 W-210 500292333900 WAG 64160 Oba 4893 - 4922 10/17/20 30 SBHP -4671 2000 5000 0.440 2145 S-210 500292363000 WAG 64160 Obd 5187-5189 + 5288-5300 06/01/21 888 SBHP -5202 2690 5000 0.440 2601 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: Micheal Mayfield 23. All tests reported herein w ere made in accordance w ith 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 7/20 – 6/21 POLARIS ANNUAL SURVEILLANCE REPORT FIGURE 3: POLARIS AVERAGE PRESSURE AT DATUM 12 7/20 – 6/21 POLARIS ANNUAL SURVEILLANCE REPORT TABLE 3: POLARIS MONTHLY AVERAGE OIL ALLOCATION FACTORS Date Allocation Factor Jul-20 0.88 Aug-20 0.84 Sep-20 0.83 Oct-20 0.82 Nov-20 0.81 Dec-20 0.83 Jan-21 0.84 Feb-21 0.82 Mar-21 0.85 Apr-21 0.85 May-21 0.84 Jun-21 0.81 7/20 – 6/21 Midnight Sun Annual Surveillance Report 1 2021 ANNUAL RESERVOIR SURVEILLANCE REPORT MIDNIGHT SUN OIL POOL PRUDHOE BAY UNIT JULY 1,2020 –JUNE 30,2021 7/20 – 6/21 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 7 d) 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 7/20 – 6/21 Midnight Sun Annual Surveillance Report 3 Prudhoe Bay Unit 2021 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, 2020 through June 30, 2021. 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, 2021 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 0.76. E-103 and E-104 injectors came back online near the end of this reporting period – the full effect of increased injection will be seen in the next reporting period. 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 1263 bopd, 5604 bwpd, 10.5 mmscfpd and injected 6975 bwpd and 4.8 mmscfpd of MI for the report period resulting in a total VRR of 0.76 for the period. Monthly production and injection 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. 7/20 – 6/21 Midnight Sun Annual Surveillance Report 4 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 one reservoir pressures was acquired: E-104 (3/21/21). 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) 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 0.88-0.96. Any days with allocation factors of zero were excluded. The monthly averages of daily oil production allocation factors are shown in Table 3. 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 11 f and g) Future development plans are discussed in the 2021 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 January 27, 2021, followed by an amendment on July 15th, 2021. A copy of each was provided to the Commission. The Commission will be copied when the 2022 update of the Western Satellites Plan of Development is filed with the Division. 7/20 – 6/21 Midnight Sun Annual Surveillance Report 5 Figure 1: Midnight Sun Production and Injection History Figure 2: Midnight Sun Voidage History 7/20 – 6/21 Midnight Sun Annual Surveillance Report 6 Figure 3: Midnight Sun Pressure History 7/20 – 6/21 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 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-20 25,957 319,393 282,164 0 422,869 22,440,345 73,733,679 59,856,477 105,715,495 113,713,101 253,750 23,481,080 0.50 Aug-20 27,037 194,048 160,017 0 432,065 22,467,382 73,927,727 60,016,494 105,715,495 113,968,020 49,565 23,530,645 0.84 Sep-20 33,815 262,304 224,510 0 452,806 22,501,197 74,190,031 60,241,004 105,715,495 114,235,175 150,339 23,680,983 0.64 Oct-20 31,821 288,571 255,479 0 451,509 22,533,018 74,478,602 60,496,483 105,715,495 114,501,566 196,643 23,877,626 0.58 Nov-20 48,971 303,459 185,756 359,815 0 22,581,989 74,782,061 60,682,239 106,075,310 114,872,175 45,363 23,922,989 0.89 Dec-20 49,662 314,736 140,380 377,211 0 22,631,651 75,096,797 60,822,619 106,452,521 115,260,702 -11,995 23,910,994 1.03 Jan-21 47,435 307,904 127,448 356,875 0 22,679,086 75,404,701 60,950,067 106,809,396 115,628,284 -10,474 23,900,521 1.03 Feb-21 41,173 297,635 120,935 289,416 0 22,720,259 75,702,336 61,071,002 107,098,812 115,926,382 40,411 23,940,932 0.88 Mar-21 43,419 360,593 138,899 287,532 0 22,763,678 76,062,929 61,209,901 107,386,344 116,222,540 100,091 24,041,023 0.75 Apr-21 35,081 374,088 143,308 282,593 0 22,798,759 76,437,017 61,353,209 107,668,937 116,513,611 109,917 24,150,939 0.73 May-21 41,916 404,070 135,053 241,491 0 22,840,675 76,841,087 61,488,262 107,910,428 116,762,347 167,804 24,318,743 0.60 Jun-21 34,563 394,528 131,445 350,996 0 22,875,238 77,235,615 61,619,707 108,261,424 117,123,873 38,820 24,357,563 0.90 7/20 – 6/21 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-104 500292304900 WI 640158 7857.29-7892.42 3/21/2021 21,360 SBHP 137 7863 3400 8050 0.433 3481 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 Prudhoe Bay Field, Midnight Sun Oil Pool Printed Name Title Date Reservoir Engineer September 9, 2021 8050 TVDss 0.72 3. Unit or Lease Name:4. Field and Pool:5. Datum Reference: Tim Davis 23. All tests reported herein were made in accordance w ith 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 7/20 – 6/21 Midnight Sun Annual Surveillance Report 9 Table 3: Allocation Factors Month Oil Allocation Factor Jul-20 0.92 Aug-20 0.96 Sep-20 0.95 Oct-20 0.93 Nov-20 0.91 Dec-20 0.88 Jan-21 0.91 Feb-21 0.91 Mar-21 0.91 Apr-21 0.93 May-21 0.93 Jun-21 0.89 1 2021 ANNUAL SURVEILLANCE REPORT AURORA OIL POOL PRUDHOE BAY UNIT JULY 1,2020 –JUNE 30,2021 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 2021 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, 2020 to June 30, 2021. 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 practice 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 17.6 MBWIPD and 14.9 MMSCFD. Cumulative injection through June 2021 was 141.4 MMSTBW and 56.8 BCF. A total of 15 injectors have been on water injection and 9 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 6.0 MBOPD, 14.8 MMSCFD (FGOR 2.5 MSCF/STB), and 18.3 MBWPD (WC 75 %). The average voidage replacement ratio was 0.78. 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 reservoir 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. Five 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, 2021 to June 30th, 2022, 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-100: NCS packers were used to determine flow splits to evaluate water entry points o Consistent fluid splits along wellbore; not a water shut off candidate at this time ·S-44A: Sliding sleeves shifted to determine flow splits and evaluate water entry points o Subsequent cement squeeze targeting water bearing interval reduced water production by more than 1000 bwpd without impacting oil production 5 During the reporting period, no production or injection log were run in the Aurora Field. 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 0.88.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 2021 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 January 27, 2021, followed by an amendment on July 15th, 2021. A copy of each was provided to the Commission. The Commission will be copied when the 2022 update of the Western Satellites 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-20 168,740.397,693.716,919.682,046.251,313.48,823,289. 141,666,464. 73,324,623. 135,664,893. 170,345,391. 329,978 55,573,862 0.72 Aug-20 162,098.422,981.670,083.648,317.243,544.48,985,387 142,089,445 73,994,706 136,313,210 171,157,672 329,088 55,902,951 0.71 Sep-20 166,741.423,880.623,090.561,051.312,035.49,152,128 142,513,325 74,617,796 136,874,261 171,923,406 333,863 56,236,814 0.70 Oct-20 187,697.493,452.646,246.527,747.411,001.49,339,825 143,006,777 75,264,042 137,402,008 172,716,528 398,520 56,635,334 0.67 Nov-20 173,607.432,096.564,995.446,109.476,480.49,513,432 143,438,873 75,829,037 137,848,117 173,466,977 303,272 56,938,606 0.71 Dec-20 206,659.496,321.545,502.487,581.615,609.49,720,091 143,935,194 76,374,539 138,335,698 174,345,987 234,538 57,173,144 0.79 Jan-21 185,106.427,428.434,754.465,310.655,940.49,905,197 144,362,622 76,809,293 138,801,008 175,227,286 50,560 57,223,703 0.95 Feb-21 193,990.497,369.463,312.527,823.605,499.50,099,187 144,859,991 77,272,605 139,328,831 176,141,075 101,285 57,324,988 0.90 Mar-21 189,862.433,003.466,958.685,081.579,846.50,289,049 145,292,994 77,739,563 140,013,912 177,199,362 -84,384 57,240,604 1.09 Apr-21 180,990.450,791.537,203.546,118.494,161.50,470,039 145,743,785 78,276,766 140,560,030 178,062,783 182,454 57,423,059 0.83 May-21 184,827.469,155.509,528.290,315.469,023.50,654,866 146,212,940 78,786,294 140,850,345 178,649,698 446,747 57,869,805 0.57 Jun-21 178,040.471,472.502,774.566,975.340,862.50,832,906 146,684,412 79,289,068 141,417,320 179,439,347 230,370 58,100,175 0.77 7 TABLE 2: AURORA CUMULATIVE VOIDAGE BY FAULT BLOCK On Jun-21 Aurora Aurora Aurora Aurora Aurora Aurora Crest*N of Crest**E of Crest*W of Crest*S of Crest* Total Cumulative Injection (rsvb)21,938,617 53,979,683 12,610,806 77,913,109 12,997,132 179,439,347 Total Cumulative Production (rsvb)38,613,893 64,537,640 15,347,327 94,583,144 30,940,265 244,022,269 Cumulative Voidage Replacement Ratio 0.57 0.84 0.82 0.82 0.42 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-120 500292318600 WAG 640120 6516-6541, 6548-6577, 6629-6640, 6713-6725 5/6/2021 240 Other 6700 3921 S-113B 500292309402 O 640120 6697-6644, 6746-6639 6/10/2021 983 SBHP 140 6,300 2,758 6700 0.031 2769 S-112 500292309900 WAG 640120 6641-6655, 6672-6679, 6703-6673, 6648-6668, 6675-6636 4/30/2021 408 Other 6700 4466 S-111 500292325700 WAG 640120 6771 - 6782, 6792-6805, 6819-6827, 6831-6834, 6860, 6799- 6801, 6805-6812, 6823-6829, 6869-6870, 6830-6864 5/6/2021 240 Other 6700 3578 S-114A 500292311601 WAG 640120 6658-6685 5/5/2021 216 Other 6700 3856 *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 Pool6700 TVDss 0.72 August 23rd, 2021 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, 99516 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 know ledge. Gavin DittmanSignature Printed Name Title Date Reservoir Engineer 10 TABLE 4 - AURORA MONTHLY AVERAGE OIL ALLOCATION FACTORS Oil Allocation Factor Jul-20 0.88 Aug-20 0.84 Sep-20 0.83 Oct-20 0.82 Nov-20 0.81 Dec-20 0.83 Jan-21 0.84 Feb-21 0.82 Mar-21 0.85 Apr-21 0.85 May-21 0.83 Jun-21 0.81 TABLE 5: AURORA PRESSURES BY REPRESENTATIVE AREA Representative Area Well Pressure at Datum (psi) Crest S-120 3921 South of Crest S-113B 2769 East of Crest S-112 4466 North of Crest S-111 3578 Northwest of Crest S-114A 3856 1 2021 ANNUAL SURVEILLANCE REPORT BOREALIS OIL POOL PRUDHOE BAY UNIT JULY 1,2020 –JUNE 30,2021 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 2020 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, 2020 through June 30, 2021. 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 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 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 26.0 MBWIPD and 22.9 MMSCFD. Cumulative injection through June 2021 was 238 MMSTBW and 118 BCF.A total of 21 injectors have been on water injection and 11 injectors have been on MI. 3.VOIDAGE BALANCE BY MONTH OF PRODUCED AND INJECTED FLUIDS (RULE 9B) During the reporting period, field production averaged 7.1 MBOPD, 24.0 MMSCFD (FGOR 3.4 MSCF/STB), and 30.1 MBWPD (WC 81%). The average voidage replacement ratio was 0.74. 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 of the newer 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. Six 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, 2021 to June 30th, 2022, 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) ·Production profile logs o V-117: Anomalously high water production since it was drilled; PPROF used to determine water entry points and inform potential water shut off options o V-109: PPROF did not reach the Kuparuk reservoir o L-106: Mature producer, high water cut. PPROF used to determine water entry points and inform potential water shut off options ·Injection profile logs o Z-35: Plug set to isolate the Ivishak, PPROF run to confirm no flow below the Kuparuk 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 MicroMotion 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 0.82 and 0.88 . 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 throughout 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. 6 Summarized below are significant events and accomplishments at Borealis over the past year: ·Z-31: Recompleted as a Borealis injector in 2Q 2021 ·Z-35: Water and MI injection test in the Kuparuk; evaluating for future Borealis recomplete ·Z-34: Production test in the Kuparuk to determine OWC in SE Borealis (ongoing) ·MI was injected into 11 water-alternating-gas injectors ·In addition to the aforementioned activity, miscellaneous producer and injector wellwork was executed to minimize oil rate decline. The Borealis owners will continue to evaluate optimal well count, well utility, wellwork and well locations to maximize commercial production. Future development plans are discussed in the 2021 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 January 27, 2021, followed by an amendment on July 15th, 2021. A copy of each was provided to the Commission. The Commission will be copied when the 2022 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-20 163,201.253,350.772,052.913,333.841,139.90,013,445. 138,474,672. 137,197,705. 228,981,518. 304,506,180. -293,567 32,880,049 1.25 Aug-20 164,779.352,937.702,747.888,582.646,276.90,178,224 138,827,609 137,900,452 229,870,100 305,822,111 -154,806 32,725,243 1.13 Sep-20 194,636.487,813.750,794.907,389.773,500.90,372,860 139,315,422 138,651,246 230,777,489 307,236,291 -80,358 32,644,885 1.06 Oct-20 206,039.876,227.835,371.895,886.717,333.90,578,899 140,191,649 139,486,617 231,673,375 308,603,800 309,363 32,954,248 0.82 Nov-20 219,555.663,862.868,767.727,833.765,503.90,798,454 140,855,511 140,355,384 232,401,208 309,828,080 373,244 33,327,493 0.77 Dec-20 233,050.735,233.921,497.712,165.665,228.91,031,504 141,590,744 141,276,881 233,113,373 310,974,051 568,007 33,895,500 0.67 Jan-21 242,504.865,565.897,866.754,965.778,521.91,274,008 142,456,309 142,174,747 233,868,338 312,234,348 522,682 34,418,182 0.71 Feb-21 223,708.785,088.894,396.635,318.616,056.91,497,716 143,241,397 143,069,143 234,503,656 313,270,681 668,256 35,086,438 0.61 Mar-21 238,755.950,877.1,046,554.842,476.712,772.91,736,471 144,192,274 144,115,697 235,346,132 314,580,350 674,382 35,760,820 0.66 Apr-21 248,150.915,262.1,041,372.783,226.635,933.91,984,621 145,107,536 145,157,069 236,129,358 315,781,351 768,087 36,528,907 0.61 May-21 242,868.957,186.1,131,360.692,996.648,025.92,227,489 146,064,722 146,288,429 236,822,354 316,896,912 965,204 37,494,111 0.54 Jun-21 212,198.919,891.1,124,498.740,993.546,923.92,439,687 146,984,613 147,412,927 237,563,347 317,999,227 907,596 38,401,706 0.55 8 FIGURE 1: BOREALIS PRODUCTION & INJECTION HISTORY FIGURE 2: BOREALIS VOIDAGE HISTORY 9 TABLE 2: BOREALIS PRESSURE SURVEY DETAIL 1. Operator: BP Exploration (Alaska) Inc. 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-104 500292306000 O 640130 6495-6534 04/10/21 5800 SBHP 157 6525 3748 6600 0.401 3778 L-109 500292304600 WAG 640130 4202-4226, 4267-4296, 4307-4320, 4363-4381, 4414-4448, 4474- 4484, 6584-6611, 6621-6648 04/12/21 5856 Other 6600 2954 L-120 500292306400 O 640130 6477 - 6511 6521 - 6527 04/09/21 7910 SBHP 156 6500 4066 6600 0.321 4098 V-117 500292315600 O 640130 6641 - 6623, 6617 - 6604, 6598 - 6601, 6634 - 6633, 6633 - 6631, 6631 - 6630, 6625 - 6624, 6624 - 6624, 6625 - 6627, 6627 - 6629, 6629 - 6633, 6628 - 6612, 6612 - 6598, 6597 - 6597, 6598 - 6609, 6616 - 6621,04/08/21 19078 SBHP 153 6600 3060 6600 0.442 3060 V-121 500292334800 WAG 640130 6663 - 6668 6672 - 6678 6682 - 6689 6689 - 6702 6707 - 6714 6720 - 6729 04/29/21 384 Other 6600 3337 Z-113 500292345000 O 640130 6462-6552, 6564-6569, 6566-6551 03/08/21 170 SBHP 148 6531 2740 6600 0.135 2749 *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 Reservoir Engineer August 23rd, 2021 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: P.O. Box 196612, 900 E. Benson Blvd., Anchorage, AK 99519-6612 10 TABLE 3: BOREALIS MONTHLY AVERAGE OIL ALLOCATION FACTORS Oil Allocation Factor Jul-20 0.88 Aug-20 0.84 Sep-20 0.83 Oct-20 0.82 Nov-20 0.82 Dec-20 0.83 Jan-21 0.84 Feb-21 0.82 Mar-21 0.85 Apr-21 0.85 May-21 0.84 Jun-21 0.82 TABLE 4: BOREALIS PRESSURES BY REPRESENTATIVE AREA Representative Area Well Pressure at Datum (psi) North of V Pad L-104 3778 Northeast of V Pad V-121 3337 Z Pad Z-113 2749 South of V Pad V-117 3060 Southwest of L Pad L-109 2954 North of L Pad L-120 4098