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Home My WebLink About2023 Prudhoe Satellite Oil Pools1 7/22 – 6/23 POLARIS ANNUAL SURVEILLANCE REPORT 2023 ANNUAL SURVEILLANCE REPORT POLARIS OIL POOL PRUDHOE BAY UNIT JULY 1,2022 –JUNE 30,2023 2 7/22 – 6/23 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) ................................................................................................................. 4 6. PROGRESS OF ENHANCED RECOVERY PROJECT IMPLEMENTATION AND RESERVOIR MANAGEMENT SUMMARY (RULE 9E) .....................................................................................................................................................55 7. RESULTS OF MONITORING TO DETERMINE ENRICHED 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 7/22 – 6/23 POLARIS ANNUAL SURVEILLANCE REPORT PRUDHOE BAY UNIT 2023 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, 2022 through June 30, 2023. 2.VOIDAGE BALANCE BY MONTH OF PRODUCED AND INJECTED FLUIDS (RULE 9A) During the reporting period, field production averaged 7,564 BOPD, 18,389 MMSCFD (FGOR 2,431 SCF/STB), and 7,347 BWPD (WC 49%). Water injection during this period averaged 14,362 BWIPD with 17,059 MMSCFD of miscible gas injection. The average voidage replacement ratio was 1.01. 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, 2023 to June 30, 2024, 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, S-201, S-210, and M- 201. Measured pressure in this polygon is 3146 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 2029 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 pressure in this polygon is 2223 psi. W-Pad East This polygon contains producer W-203 and is supported by injectors W-207i, W-210i, and W-01. No new pressure data in this polygon was acquired during the reporting period. 4 7/22 – 6/23 POLARIS ANNUAL SURVEILLANCE REPORT 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. (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: Injection logs were run on M-201, M-205, W-209, and W-219 during the report period to determine miscible injectant distribution. 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 7/22 – 6/23 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 14,362 BWIPD. Cumulative injection through June 2023 was 48.0 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 17.1 MMSCFD. Cumulative injection through June 2023 was 25.3 BCF. 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. 6 7/22 – 6/23 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 2023 update to the Plan of Development for the Polaris 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 2024 update of the Polaris Plan of Development is filed with the Division. 7 7/22 – 6/23 POLARIS ANNUAL SURVEILLANCE REPORT TABLE 1: POLARIS MONTHLY PRODUCTION AND INJECTION SUMMARY Report Date 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-22 271,991 703,909 165,226 269,929 567,483 32,007,020 33,098,951 23,183,792 42,991,423 55,223,364 199,965 14,263,750 0.75 Aug-22 244,047 628,861 206,920 384,233 601,119 32,251,067 33,727,812 23,390,712 43,375,656 55,972,111 38,419 14,302,170 0.95 Sep-22 238,427 607,265 187,208 285,605 550,809 32,489,494 34,335,077 23,577,920 43,661,261 56,591,057 130,727 14,432,897 0.83 Oct-22 210,488 590,488 180,255 339,483 418,686 32,699,982 34,925,565 23,758,175 44,000,744 57,185,147 115,501 14,548,398 0.84 Nov-22 174,550 513,069 197,551 461,826 114,248 32,874,532 35,438,634 23,955,726 44,462,570 57,720,140 23,898 14,664,434 0.96 Dec-22 199,607 485,369 227,596 517,539 368,268 33,074,139 35,924,003 24,183,322 44,980,109 58,463,815 -58,297 14,606,137 1.09 Jan-23 272,932 610,216 255,029 598,094 433,342 33,347,071 36,534,219 24,438,351 45,578,203 59,327,895 -15,738 14,590,399 1.02 Feb-23 231,430 516,031 242,676 499,742 436,965 33,578,501 37,050,250 24,681,027 46,077,945 60,094,814 -21,721 14,568,678 1.03 Mar-23 266,364 601,603 268,469 507,536 774,030 33,844,865 37,651,853 24,949,496 46,585,481 61,071,843 -125,686 14,442,992 1.15 Apr-23 262,876 572,918 249,596 457,903 746,230 34,107,741 38,224,771 25,199,092 47,043,384 61,982,063 -98,020 14,344,972 1.12 May-23 196,870 453,621 248,971 455,360 650,785 34,304,611 38,678,392 25,448,063 47,498,744 62,832,448 -164,720 14,180,252 1.24 Jun-23 191,424 428,784 252,096 464,973 564,629 34,496,035 39,107,176 25,700,159 47,963,717 63,640,848 -138,963 14,041,289 1.21 8 7/22 – 6/23 POLARIS ANNUAL SURVEILLANCE REPORT FIGURE 1: POLARIS PRODUCTION AND INJECTION HISTORY FIGURE 2: POLARIS VOIDAGE HISTORY 9 7/22 – 6/23 POLARIS ANNUAL SURVEILLANCE REPORT TABLE 2: POLARIS PRESSURE SURVEY DETAIL 10 7/22 – 6/23 POLARIS ANNUAL SURVEILLANCE REPORT FIGURE 3: POLARIS AVERAGE PRESSURE AT DATUM 11 7/22 – 6/23 POLARIS ANNUAL SURVEILLANCE REPORT TABLE 3: POLARIS MONTHLY AVERAGE OIL ALLOCATION FACTORS Date Allocation Factor Jul-22 0.89 Aug-22 0.91 Sep-22 0.94 Oct-22 0.91 Nov-22 0.90 Dec-22 0.93 Jan-23 0.93 Feb-23 0.94 Mar-23 0.90 Apr-23 0.91 May-23 0.91 Jun-23 0.90 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) Hilcorp North Slope, LLC.3800 Centerpoint Dr. Anchorage, AK, 99516 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION RESERVOIR PRESSURE REPORT 1. Operator:2. Address: 3. Unit or Lease Name:4. Field and Pool:5. Datum Reference:7. Gas Gravity: Prudhoe Bay Unit Prudhoe Bay Field, Polaris Oil Pool 5000 TVDss 0.7 Printed Name Natalie Brent Date September 15, 2023 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. Certified Digital Signature Title Sr Reservoir Engineer Form 10-412 Revised 10/2022 Submit PDF and Excel to aogcc.reporting@alaska.gov Digitally signed by Natalie Brent (1028) Date: 2023.09.15 Natalie Brent (1028) 1 7/22 – 6/23 ORION ANNUAL SURVEILLANCE REPORT 2023 ANNUAL SURVEILLANCE REPORT ORION OIL POOL PRUDHOE BAY UNIT JULY 1,2022 –JUNE 30,2023 2 7/22 – 6/23 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).......................................................................................................................... 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 pressure 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 7/22 – 6/23 ORION ANNUAL SURVEILLANCE REPORT PRUDHOE BAY UNIT 2023 ORION OIL POOL ANNUAL SURVEILLANCE REPORT 1.INTRODUCTION 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, 2022 to June 30, 2023. 2.VOIDAGE BALANCE BY MONTH OF PRODUCED AND INJECTED FLUIDS (RULE 9A) During the reporting period, field production averaged 15,103 BOPD, 30.5 MMSCFD (FGOR 2,019 SCF/STB), and 13,759 BWPD (WC 48%). Water injection during this period averaged 18,652 BWIPD with 32,848 MMSCFD of miscible gas injection. The average voidage replacement ratio was 0.86. 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, 2023 to June 30th, 2024, 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. No new pressure data in this polygon was acquired during the reporting period. 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 1855 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 2052 psi. 4 7/22 – 6/23 ORION ANNUAL SURVEILLANCE REPORT 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, and V-224i. Measured pressures in the polygon averaged 1684 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 2275 psi. Polygon 3 This polygon contains producer Z-220 and is supported by injector Z-221. No new pressure data in this polygon was acquired during the reporting period. 4.RESULTS AND ANALYSIS OF PRODUCTION &INJECTION LOGGING SURVEYS, AND SPECIAL MONITORING (RULE 9C) Production Logs: Production logs were run on L-200A, L-202, and L-207 during the reporting period. 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. (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: Injection logs were run on L-213, L-218, L-222, V-137, V-221, Z-221, and Z-223 during the reporting period 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 7/22 – 6/23 ORION ANNUAL SURVEILLANCE REPORT 5.REVIEW OF POOL PRODUCTION ALLOCATION (RULE 9D) AND REVIEW OF POOL PRODUCTION ALLOCATION FACTORS AND ISSUES (RULE 4F) 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 18,652 BWIPD. Cumulative injection through June 2023 was 76.3 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 32.8 MMSCFD. Cumulative injection through June 2022 was 60.3 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 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. 6 7/22 – 6/23 ORION ANNUAL SURVEILLANCE REPORT 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.PROGRESS OF PLANS AND TESTS TO EXPAND THE PRODUCTIVE LIMITS OF THE POOL (RULE 9F) New Sands: As mentioned in previous reports, Orion includes one wells with slotted liner completions in the N-sand; L- 254. 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-200A, L-201, L-202, L-203, L-204, L-207, V-202, V-203, V-204, V-205, V-207, L-206, Z-220. 9.FUTURE DEVELOPMENT PLANS Future development plans are discussed in the 2023 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 2024 update of the Orion Plan of Development is filed with the Division. 7 7/22 – 6/23 ORION ANNUAL SURVEILLANCE REPORT TABLE 1: ORION MONTHLY PRODUCTION AND INJECTION SUMMARY Report Date 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-22 378,652 1,131,515 411,719 364,511 616,541 44,384,430 50,871,513 31,718,619 69,852,716 99,413,753 473,923 -794,575 0.53 Aug-22 466,477 1,212,704 450,092 419,366 670,213 44,850,907 52,084,217 32,168,711 70,272,082 100,232,738 543,791 -61,082 0.53 Sep-22 354,980 917,794 351,720 540,185 684,477 45,205,887 53,002,011 32,520,431 70,812,267 101,182,166 95,107 177,217 0.80 Oct-22 367,661 845,125 384,570 596,436 629,373 45,573,548 53,847,136 32,905,001 71,408,703 102,155,897 90,759 391,912 0.82 Nov-22 426,222 828,694 409,061 521,746 976,091 45,999,770 54,675,830 33,314,062 71,930,449 103,258,754 39,844 540,527 0.88 Dec-22 469,158 967,048 448,477 636,195 871,677 46,468,928 55,642,878 33,762,539 72,566,644 104,415,600 251,261 791,789 0.82 Jan-23 489,451 779,519 404,281 654,427 874,066 46,958,379 56,422,397 34,166,820 73,221,071 105,592,271 92,792 884,581 0.93 Feb-23 443,271 733,469 390,801 562,216 839,220 47,401,650 57,155,866 34,557,621 73,783,287 106,655,249 127,845 1,012,426 0.89 Mar-23 523,168 899,461 440,422 740,944 1,001,292 47,924,818 58,055,327 34,998,043 74,524,231 107,994,364 65,254 1,077,680 0.95 Apr-23 495,181 796,135 427,640 636,636 1,184,103 48,419,999 58,851,462 35,425,683 75,160,867 109,335,987 -34,067 1,043,613 1.03 May-23 542,859 957,097 433,843 595,548 1,787,120 48,962,858 59,808,559 35,859,526 75,756,415 110,991,892 -208,032 835,580 1.14 Jun-23 555,670 1,060,582 469,461 539,737 1,855,253 49,518,528 60,869,141 36,328,987 76,296,152 112,631,625 -84,330 751,251 1.05 8 7/22 – 6/23 ORION ANNUAL SURVEILLANCE REPORT FIGURE 1: ORION PRODUCTION AND INJECTION HISTORY 9 7/22 – 6/23 ORION ANNUAL SURVEILLANCE REPORT FIGURE 2: ORION VOIDAGE HISTORY 10 7/22 – 6/23 ORION ANNUAL SURVEILLANCE REPORT TABLE 2: ORION PRESSURE SURVEY DETAIL 11 7/22 – 6/23 ORION ANNUAL SURVEILLANCE REPORT FIGURE 3: ORION AVERAGE PRESSURE AT DATUM 12 7/22 – 6/23 ORION ANNUAL SURVEILLANCE REPORT TABLE 3: ORION MONTHLY AVERAGE OIL ALLOCATION FACTORS Date Allocation Factor Jul-22 0.89 Aug-22 0.91 Sep-22 0.94 Oct-22 0.91 Nov-22 0.90 Dec-22 0.93 Jan-23 0.93 Feb-23 0.94 Mar-23 0.90 Apr-23 0.91 May-23 0.91 Jun-23 0.90 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) Hilcorp North Slope, LLC.3800 Centerpoint Dr. Anchorage, AK, 99516 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION RESERVOIR PRESSURE REPORT 1. Operator:2. Address: 3. Unit or Lease Name:4. Field and Pool:5. Datum Reference:7. Gas Gravity: Prudhoe Bay Unit Prudhoe Bay Field, Orion Oil Pool 4400 TVDss 0.7 Printed Name Natalie Brent Date September 15, 2023 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. Certified Digital Signature Title Sr Reservoir Engineer Form 10-412 Revised 10/2022 Submit PDF and Excel to aogcc.reporting@alaska.gov Digitally signed by Natalie Brent (1028) Date: 2023.09.15 Natalie Brent (1028) 1 2023 ANNUAL SURVEILLANCE REPORT AURORA OIL POOL PRUDHOE BAY UNIT JULY 1,2022 –JUNE 30,2023 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)4 7.FUTURE DEVELOPMENT PLANS (RULE 8F)5 LIST OF ATTACHMENTS Figure 1: Aurora production and injection history 7 Figure 2: Aurora voidage history 7 Table 1: Aurora monthly production and injection summary 6 Table 2: Aurora pressure survey detail 8 Table 3: Aurora monthly average oil allocation factors 9 Table 4: Aurora pressures by representative area 9 3 Prudhoe Bay Unit 2023 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, 2022 to June 30, 2023. 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 25.7 MBWIPD and 9.1 MMSCFD. Cumulative injection through June 2022 was 157.9 MMSTBW and 65.8 BCF. 3.VOIDAGE BALANCE BY MONTH OF PRODUCED AND INJECTED FLUIDS (RULE 8 B) During the reporting period, field production averaged 4.7 MBOPD, 22.1 MMSCFD (FGOR 4.7 MSCF/STB), and 16.9 MBWPD (WC 78%). The average voidage replacement ratio was 0.80. 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. 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 2. 2 static pressure measurements were obtained during the reporting period, covering two representative areas, as shown in Table 4.Most producers in the AOP have evidence of pressure response to injection support. For the period of July 1st, 2023 to June 30th, 2024, 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) During the reporting period, no production or injection logs were run in the Aurora Pool. 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. 5 Over the reporting period, the monthly average of daily oil production allocation factors fell within the range of 0.89 and 0.94. Any days with allocation factors of zero were excluded. The monthly averages of daily oil production allocation factors are shown in Table 3. 7.FUTURE DEVELOPMENT PLANS (RULE 8 F) Future development plans are discussed in the 2023 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 2024 update of the Orion Plan of Development is filed with the Division. 6 TABLE 1: AURORA MONTHLY PRODUCTION AND INJECTION SUMMARY Report Date 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-22 158,170 781,134 515,289 579,050 247,832 52,886,353 153,609,617 85,663,522 149,098,507 190,945,477 561,919 59,867,921 0.57 Aug-22 144,610 705,422 482,561 639,356 321,526 53,030,963 154,315,039 86,146,083 149,737,863 191,796,966 347,040 60,120,535 0.71 Sep-22 137,594 598,535 389,103 453,172 319,441 53,168,557 154,913,574 86,535,186 150,191,035 192,457,255 347,391 60,394,285 0.66 Oct-22 137,736 541,295 372,354 446,643 320,486 53,306,293 155,454,869 86,907,540 150,637,678 193,111,532 288,175 60,621,646 0.69 Nov-22 135,520 720,010 475,663 550,823 356,645 53,441,813 156,174,879 87,383,203 151,188,501 193,894,491 413,814 60,933,828 0.65 Dec-22 160,360 721,974 500,471 636,988 363,568 53,602,173 156,896,853 87,883,674 151,825,489 194,769,631 367,771 61,210,331 0.70 Jan-23 167,917 714,054 481,459 781,846 397,971 53,770,090 157,610,907 88,365,133 152,607,335 195,813,856 178,451 61,302,567 0.85 Feb-23 134,842 642,242 465,565 839,313 219,930 53,904,932 158,253,149 88,830,698 153,446,648 196,806,312 127,935 61,345,918 0.89 Mar-23 141,987 709,048 585,505 1,178,405 250,844 54,046,919 158,962,197 89,416,203 154,625,053 198,163,808 -52,933 61,196,610 1.04 Apr-23 121,945 651,651 522,708 1,080,591 215,960 54,168,864 159,613,848 89,938,911 155,705,644 199,399,906 -59,446 61,044,874 1.05 May-23 132,063 682,930 646,956 1,138,937 177,862 54,300,927 160,296,778 90,585,867 156,844,581 200,671,897 65,574 61,015,582 0.95 Jun-23 152,368 613,042 722,261 1,041,237 135,860 54,453,295 160,909,820 91,308,128 157,885,818 201,818,191 224,841 61,169,972 0.84 7 FIGURE 1: AURORA PRODUCTION AND INJECTION HISTORY FIGURE 2: AURORA VOIDAGE HISTORY 8 TABLE 2 - AURORA PRESSURE SURVEY DETAIL 9 TABLE 3 - AURORA MONTHLY AVERAGE OIL ALLOCATION FACTORS TABLE 4 - AURORA PRESSURES BY REPRESENTATIVE AREA Representative Area Well Date Pressure at Datum (psi) Crest East of Crest North of Crest S-122 4/12/2023 2544 Northwest of Crest S-101 7/8/2022 2947 South of Crest 6. Oil Gravity: 0.9 SG / 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-101 500292296800 Water Injector Injecting WI 6780- 6752,6791- 6800,6760- 6791 7/8/2022 288 FL 4390.46 6700 .45 psi/ft 2947 S-122 500292326500 Oil Producer O8 6675.19- 6688.98, 6704.98- 6712.94, 6715.61- 6717.57, 6718.65- 6718.09, 6717.3- 6716.55, 6716.06- 6716.39, 6716.37- 6715.66, 6715.42- 6716.77, 6717.45- 6715.76, 6713.48- 6707.92, 6706.22- 6699.03, 6695.59- 6693.61, 6695.59- 6686.3, 6695.59- 6680.67, 6693.61- 6686.3, 6686.3- 6680.67 4/12/2023 120 SBHP 6704 2546 6700 0.45 2544 Hilcorp North Slope, LLC.3800 Centerpoint Dr. Anchorage, AK, 99516 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION RESERVOIR PRESSURE REPORT 1. Operator:2. Address: 3. Unit or Lease Name:4. Field and Pool:5. Datum Reference:7. Gas Gravity: Prudhoe Bay Unit Prudhoe Bay Field, Aurora Oil Pool 6700 TVDss 0.72 Printed Name Natalie Brent Date September 15, 2023 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. Certified Digital Signature Title Sr Reservoir Engineer Form 10-412 Revised 10/2022 Submit PDF and Excel to aogcc.reporting@alaska.gov Digitally signed by Natalie Brent (1028) Date: 2023.09.15 Natalie Brent (1028) 1 2023 ANNUAL SURVEILLANCE REPORT BOREALIS OIL POOL PRUDHOE BAY UNIT JULY 1,2022 –JUNE 30,2023 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 ...................................................................................... 7 Figure 2: Borealis voidage history................................................................................................................ 7 Table 1: Borealis monthly production and injection summary ..................................................................... 6 Table 2: Borealis pressure survey detail ...................................................................................................... 8 Table 3: Borealis monthly average oil allocation factors .............................................................................. 9 Table 4: Borealis pressures by representative area ...................................................................................... 9 3 Prudhoe Bay Unit 2023 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, 2022 through June 30, 2023. 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 17.0 MBWIPD and 46.7 MMSCFD. Cumulative injection through June 2022 was 252 MMSTBW and 152 BCF. 3.VOIDAGE BALANCE BY MONTH OF PRODUCED AND INJECTED FLUIDS (RULE 9B) During the reporting period, field production averaged 8.3 MBOPD, 44.6 MMSCFD (FGOR 5.4 MSCF/STB), and 23.5 MBWPD (WC 74%). 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. 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. Three static pressure measurements were obtained during the reporting period, covering three 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, 2023 to June 30th, 2024, 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 pool. 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 0.89 and 0.94. 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. 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 2023 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, 2022. A copy was provided to the Commission. The Commission will be copied when the 2024 update of the Western Satellites Plan of Development is filed with the Division. 6 TABLE 1: BOREALIS MONTHLY PRODUCTION AND INJECTION SUMMARY Report Date 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-22 271,039 1,334,557 842,208 595,149 1,214,434 95,591,383 159,804,131 159,281,134 246,329,590 337,994,150 1,066,752 42,757,852 0.66 Aug-22 256,523 1,375,302 759,019 651,761 1,487,818 95,847,906 161,179,433 160,040,153 246,981,351 339,587,911 783,108 43,138,682 0.81 Sep-22 247,231 1,202,632 618,514 416,976 1,290,876 96,095,137 162,382,065 160,658,667 247,398,327 340,817,740 820,093 43,619,349 0.72 Oct-22 289,814 1,587,364 678,988 452,881 1,220,181 96,384,951 163,969,429 161,337,655 247,851,208 342,040,719 1,312,478 44,464,146 0.59 Nov-22 267,809 1,496,998 685,921 505,492 1,319,437 96,652,760 165,466,427 162,023,576 248,356,700 343,379,427 1,095,031 45,115,153 0.67 Dec-22 261,390 1,452,759 632,233 514,831 1,555,146 96,914,150 166,919,186 162,655,809 248,871,531 344,873,893 834,108 45,519,164 0.79 Jan-23 234,272 1,271,816 611,785 508,193 1,508,279 97,148,422 168,191,002 163,267,594 249,379,724 346,332,465 644,302 45,789,870 0.84 Feb-23 228,509 1,226,154 659,992 551,658 1,261,570 97,376,931 169,417,156 163,927,586 249,931,382 347,682,846 751,355 46,182,467 0.77 Mar-23 261,827 1,374,992 760,036 574,684 1,446,573 97,638,758 170,792,148 164,687,622 250,506,066 349,171,646 892,977 46,676,146 0.75 Apr-23 225,813 1,171,104 735,305 494,278 1,555,738 97,864,571 171,963,252 165,422,927 251,000,344 350,645,310 647,757 46,985,327 0.83 May-23 249,394 1,598,929 935,966 448,435 1,730,881 98,113,965 173,562,181 166,358,893 251,448,779 352,180,344 1,245,014 47,736,336 0.67 Jun-23 241,673 1,191,167 663,894 478,556 1,449,327 98,355,638 174,753,348 167,022,787 251,927,335 353,571,840 689,178 48,087,600 0.80 7 FIGURE 1: BOREALIS PRODUCTION & INJECTION HISTORY FIGURE 2: BOREALIS VOIDAGE HISTORY 8 TABLE 2: BOREALIS PRESSURE SURVEY DETAIL 9 TABLE 3: BOREALIS MONTHLY AVERAGE OIL ALLOCATION FACTORS TABLE 4: BOREALIS PRESSURES BY REPRESENTATIVE AREA Representative Area Well Date Pressure at Datum (psi) North of L Pad L-116A 1/15/2023 2348.64 North of V Pad Northeast of V Pad South of V Pad Southwest of L Pad L-112 11/26/2022 2222 Z Pad Z-108 9/28/2022 2568 6. Oil Gravity: 0.9 SG / 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) L-112 500292312900 Abandoned Abandoned 6693-6716 11/26/2022 2304 SBHP 157 6617.64 2228 6600 .3403 PSI/FT 2222 Z-108 500292329200 Oil Producer SI O 6656-6580 9/28/2022 87600 SBHP -6618 2576 6600 0.44 2568 L-116A 500292302501 Oil Producer Gas Lift O 6472- 6472,6475- 6478,6476- 6477,6478- 6478,6477- 6476 1/15/2023 432 SBHP 151 6323.77 2228 6600 .4367 PSI/FT 2348.64 Hilcorp North Slope, LLC.3800 Centerpoint Dr. Anchorage, AK, 99516 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION RESERVOIR PRESSURE REPORT 1. Operator:2. Address: 3. Unit or Lease Name:4. Field and Pool:5. Datum Reference:7. Gas Gravity: Prudhoe Bay Unit Prudhoe Bay Field, Borealis Oil Pool 6600 TVDss 0.72 Printed Name Natalie Brent Date September 15, 2023 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. Certified Digital Signature Title Sr Reservoir Engineer Form 10-412 Revised 10/2022 Submit PDF and Excel to aogcc.reporting@alaska.gov Digitally signed by Natalie Brent (1028) Date: 2023.09.15 Natalie Brent (1028) 7/22 – 6/23 Midnight Sun Annual Surveillance Report 1 2023 ANNUAL RESERVOIR SURVEILLANCE REPORT MIDNIGHT SUN OIL POOL PRUDHOE BAY UNIT JULY 1,2022 –JUNE 30,2023 7/22 – 6/23 Midnight Sun Annual Surveillance Report 2 CONTENTS 1. Introduction 3 2. Progress of Enhanced Recovery Project Implementation and Reservoir Management (Rule 11a) 3 3. Voidage Balance by Month of Produced and Injected Fluids (Rule 11b) 3 4. Analysis of Reservoir Pressure Surveys within the Pool (Rule 11c) 4 5. Results and Analysis of Production and Injection Logging Surveys (Rule 11d) 4 6. Results of Well Allocation and Test Evaluation (Rule 11e) and Review of Pool Production Factors and Issues (Rule 7d) 4 7. Future Development Plans and Review of Plan of Operations and Development (Rule 11f, 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 7/22 – 6/23 Midnight Sun Annual Surveillance Report 3 Prudhoe Bay Unit 2023 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, 2022, through June 30, 2023. Progress of Enhanced Recovery Project Implementation and Reservoir Management Summary (Rule 11a) Production and injection volumes for the 12-month period ending June 30, 2023, 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 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 11b) 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 930 bopd, 9484 bwpd, 4.2 mmscfpd and injected 11.1 mbwpd and 11.3 mmscfpd of MI for the report period resulting in a total VRR of 1.48 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. 7/22 – 6/23 Midnight Sun Annual Surveillance Report 4 Analysis of Reservoir Pressure Surveys within the Pool (Rule 11c) 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 no reservoir pressure data was acquired. Reservoir pressures will be acquired in the 2023-2024 ASR period. Results and Analysis of Production & Injection Logging Surveys (Rule 11d) 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 11e) and Review of Pool Production Factors and Issues (Rule 7d) 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 0.92-1.00. 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, g) Future development plans are discussed in the 2023 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, 2022. A copy was provided to the Commission. The Commission will be copied when the 2024 update of the Western Satellites Plan of Development is filed with the Division. 7/22 – 6/23 Midnight Sun Annual Surveillance Report 5 Figure 1: Midnight Sun Production and Injection History Figure 2: Midnight Sun Voidage History 7/22 – 6/23 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) 7/22 – 6/23 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 7/1/2022 23,432 51,958 233,082 503,126 0 23,126,298 79,799,201 65,080,041 116,035,662 9,516,281 125,131,338 -217,801 21,660,552 1.77 8/1/2022 22,024 52,796 237,471 343,192 248,053 23,148,322 79,851,997 65,317,512 116,378,854 9,764,334 125,631,177 -203,585 21,456,967 1.69 9/1/2022 23,137 65,970 253,344 313,470 437,745 23,171,459 79,917,967 65,570,856 116,692,324 10,202,079 126,212,320 -259,731 21,197,236 1.81 10/1/2022 33,055 67,076 250,211 345,634 462,359 23,204,514 79,985,043 65,821,067 117,037,958 10,664,438 126,841,115 -300,721 20,896,515 1.92 11/1/2022 30,762 51,073 239,170 334,530 448,555 23,235,276 80,036,116 66,060,237 117,372,488 11,112,993 127,450,329 -304,089 20,592,427 2.00 12/1/2022 25,006 76,753 264,428 327,125 423,182 23,260,282 80,112,869 66,324,665 117,699,613 11,536,175 128,036,945 -245,685 20,346,742 1.72 1/1/2023 19,953 138,988 308,261 330,212 492,303 23,280,235 80,251,857 66,632,926 118,029,825 12,028,478 128,667,522 -212,485 20,134,257 1.51 2/1/2023 21,966 149,168 283,007 303,108 339,133 23,302,201 80,401,025 66,915,933 118,332,933 12,367,611 129,179,811 -112,328 20,021,930 1.28 3/1/2023 33,665 163,801 328,078 323,515 480,092 23,335,866 80,564,826 67,244,011 118,656,448 12,847,703 129,796,286 -150,562 19,871,368 1.32 4/1/2023 38,625 216,013 395,925 310,726 304,205 23,374,491 80,780,839 67,639,936 118,967,174 13,151,908 130,295,815 71,690 19,943,058 0.87 5/1/2023 35,428 210,838 284,269 304,091 426,306 23,409,919 80,991,677 67,924,205 119,271,265 13,578,214 130,860,549 -114,551 19,828,507 1.25 6/1/2023 32,233 277,587 384,505 298,422 72,460 23,442,152 81,269,264 68,308,710 119,569,687 13,650,674 131,210,675 239,707 20,068,214 0.59 7/22 – 6/23 Midnight Sun Annual Surveillance Report 8 Table 2: MIDNIGHT SUN PRESSURE SURVEY DETAILS 7/22 – 6/23 Midnight Sun Annual Surveillance Report 9 Table 3: Allocation Factors Date Allocation Factor Jul-22 0.92 Aug-22 0.92 Sep-22 0.92 Oct-22 0.93 Nov-22 0.95 Dec-22 0.91 Jan-23 0.91 Feb-23 0.93 Mar-23 0.95 Apr-23 0.96 May-23 0.97 Jun-23 1.00 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) Hilcorp North Slope, LLC.3800 Centerpoint Dr. Anchorage, AK, 99516 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION RESERVOIR PRESSURE REPORT 1. Operator:2. Address: 3. Unit or Lease Name:4. Field and Pool:5. Datum Reference:7. Gas Gravity: Prudhoe Bay Unit Prudhoe Bay Field, Midnight Sun Oil Pool 8050 TVDss 0.72 Printed Name Natalie Brent Date September 15, 2023 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. Certified Digital Signature Title Sr Reservoir Engineer Form 10-412 Revised 10/2022 Submit PDF and Excel to aogcc.reporting@alaska.gov Digitally signed by Natalie Brent (1028) Date: 2023.09.15 Natalie Brent (1028) 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 4486 640135 Orion 4400 87 27.6 220 46.5 11.2 11 1950 1836 1840 18.7 .7 415 98 1.12 1.12 .830 272 2019 640160 Polaris 5000 98 26.4 78 54 8 7.4 2250 2013 1890 18.2 .65 391 91 1.15 1.15 .868 310 2431 640120 Aurora 6700 150 18 44 45 .72 0.72 3423 3464 2746 29.1 .72 112 53 1.35 1.35 .858 717 4685 640130 Borealis 6600 158 18 22 44 2.97 2.81 3442 2761 2380 24.1 .72 141 36 1.23 1.24 .861 457 5400 Sr Reservoir Engineer 9/15/2023 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION ANNUAL RESERVOIR PROPERTIES REPORT 1. Operator:2. Address: Hilcorp North Slope, LLC 3800 Centerpoint Dr. Anchorage, AK, 99516 Printed Name Title DateNatalie Brent I hereby certify that the foregoing is true and correct to the best of my knowledge. Certified Digital Signature Form 10-428 Revised 10/2022 Submit in PDF and Excel to aogcc.reporting@alaska.gov Digitally signed by Natalie Brent (1028) Date: 2023.09.15 Natalie Brent (1028)