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Home My WebLink About2024 Prudhoe Satellite Oil Pools3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503 Phone: 907/777-8300 hilcorp.com Hilcorp North Slope, LLC September 13, 2024 Jessie Chmielowski, Commissioner Greg Wilson, Commissioner Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, AK 99501 RE: Prudhoe Bay Unit Satellite Pools Annual Reservoir Surveillance and Annual Reservoir Properties Reports July 1, 2023 – June 30, 2024 Commissioners, Hilcorp North Slope, LLC, as operator of the Prudhoe Bay Unit, submits the enclosed Annual Reservoir Surveillance Reports and the Annual Reservoir Property Report for the Satellite Oil Pools (Aurora, Borealis, Midnight Sun, Orion and Polaris). The Annual Reservoir Surveillance Reports were prepared in accordance with the latest conservation orders for each pool. In addition, as required by 20 AAC 25.270(e), Hilcorp North Slope will simultaneously file the Annual Reservoir Properties Reports (ARPs, form 10-428) to aogcc.reporting@alaska.gov. The Operators of the Prudhoe Bay Field reserve the right to alter the content of the analyses contained in this report at any time based upon the most recent surveillance information obtained. If you have any questions regarding the reports, please contact Abbie.Barker@hilcorp.com. Thank you, Vanessa Hughes Asset Team Leader, Prudhoe Bay West Hilcorp North Slope, LLC Cc:Stephanie Erickson, ConocoPhillips Alaska, Inc. Greg Keith, ConocoPhillips Alaska, Inc. Becky Steen, ConocoPhillips Alaska, Inc. Todd Griffith, ExxonMobil Alaska, Production Inc. Bo Gao, ExxonMobil Alaska, Production Inc. Gary Selisker, Chevron USA Dave Roby, AOGCC Kenneth J Diemer, DNR, Division of Oil & Gas Allen R Eddy, DNR, Division of Oil & Gas Digitally signed by Vanessa Hughes (793) DN: cn=Vanessa Hughes (793) Date: 2024.09.13 12:17:28 - 08'00' Vanessa Hughes (793) 1 2024 ANNUAL SURVEILLANCE REPORT AURORA OIL POOL PRUDHOE BAY UNIT JULY 1,2023 –JUNE 30,2024 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 2023-2024 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, 2023 to June 30, 2024. 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 24 MBWIPD and 10.9 MMSCFD. Cumulative injection through June 2024 was 166.7 MMSTBW and 69.7 BCF. 3.VOIDAGE BALANCE BY MONTH OF PRODUCED AND INJECTED FLUIDS (RULE 8 B) During the reporting period, field production averaged 4.0 MBOPD,13.5 MMSCFD (FGOR 3.4 MSCF/STB), and 16.0 MBWPD (WC 80%).The average voidage replacement ratio was 1.04. 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.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. 16 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. 5.RESULTS AND ANALYSIS OF SPECIAL MONITORING (RULE 8 D) During the reporting period,no production or injection logs 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) Aurora production adjustments are applied based on the GC-2 allocation factor with a minimum of one well test per month. Over the reporting period, the monthly average of daily oil production allocation factors fell within the range of 0.81 and 1.09.Any days with allocation factor of 0 were excluded.The monthly averages of daily oil production allocation factors are shown in Table 4. 5 7.FUTURE DEVELOPMENT PLANS (RULE 8 F) 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 October 2,2023. 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: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 RVB RVB RVB RVB/RVB Jul-23 144,666 546,949 802,863 1,063,840 155,001 54,597,961 161,456,769 92,110,991 158,949,658 208,273,055 209,111 63,562,664 0.85 Aug-23 119,730 367,194 546,153 1,125,498 83,432 54,717,691 161,823,963 92,657,144 160,075,156 209,479,465 -241,546 63,314,443 1.25 Sep-23 109,629 335,159 398,087 957,644 96,650 54,827,320 162,159,122 93,055,231 161,032,800 210,523,917 -264,285 63,042,426 1.34 Oct-23 106,231 321,936 374,820 876,803 236,950 54,933,551 162,481,058 93,430,051 161,909,603 211,584,121 -306,283 62,717,188 1.42 Nov-23 108,018 274,403 408,031 940,634 226,736 55,041,569 162,755,461 93,838,082 162,850,237 212,702,283 -369,727 62,329,322 1.51 Dec-23 111,588 337,749 444,038 589,520 399,026 55,153,157 163,093,210 94,282,120 163,439,757 213,582,912 -25,709 62,271,690 1.03 Jan-24 130,280 407,550 569,416 615,128 452,506 55,283,437 163,500,760 94,851,536 164,054,885 214,527,097 115,999 62,351,489 0.89 Feb-24 121,979 475,082 528,827 658,377 460,488 55,405,416 163,975,842 95,380,363 164,713,262 215,520,983 75,837 62,390,487 0.93 Mar-24 148,522 500,038 462,876 604,118 473,122 55,553,938 164,475,880 95,843,239 165,317,380 216,468,369 97,585 62,450,222 0.90 Apr-24 133,819 490,012 429,264 520,743 506,437 55,687,757 164,965,892 96,272,503 165,838,123 217,354,032 107,886 62,517,594 0.89 May-24 128,561 510,238 460,386 521,845 526,364 55,816,318 165,476,130 96,732,889 166,359,968 218,254,769 139,072 62,614,557 0.86 Jun-24 108,090 374,786 386,906 297,941 353,922 55,924,408 165,850,916 97,119,795 166,657,909 218,806,414 269,795 62,856,038 0.66 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)Average Pressure (psi) Crest S-31A 4/20/2024 3,645 3,810 Crest S-31A 2/16/2024 4,098 Crest S-22B 2/16/2024 4,321 Crest S-22B 5/30/2024 3,479 Crest S-17C 2/17/2024 3,509 North of Crest S-122 3/30/2024 3,124 3,124 West of Crest S-102A 2/5/2024 3,425 3,222 West of Crest S-100 3/30/2024 2,752 West of Crest S-126 11/13/2023 3,540 West of Crest S-126 4/21/2024 3,374 West of Crest S-113B 5/8/2024 3,017 SE Crest S-37A 5/4/2024 4,297 4,013 SE Crest S-109 1/15/2024 3,173 SE Crest S-32A 2/29/2024 4,096 SE Crest S-123 4/20/2024 4,358 SE Crest S-112 4/21/2024 4,139 Date Oil Allocation Factor Jul-23 0.90 Aug-23 0.88 Sep-23 0.94 Oct-23 0.88 Nov-23 0.91 Dec-23 0.93 Jan-24 0.93 Feb-24 0.88 Mar-24 0.92 Apr-24 0.91 May-24 0.94 Jun-24 0.86 1 2024 ANNUAL SURVEILLANCE REPORT BOREALIS OIL POOL PRUDHOE BAY UNIT JULY 1,2023 –JUNE 30,2024 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 2023-2024 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, 2023 through June 30, 2024. 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 varies based on regional pressure. At Z pad, pressure has dropped because of increased MI injection in favor of water; the current Z pad VRR target is >>1. At L and V pads, pressure is higher, though these pads have still had unfavorable voidage replacement recently. The VRR target at these pads is 1.1. 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 15.9 MBWIPD and 49.3 MMSCFD. Cumulative injection through June 2024 was 258 MMSTBW and 170 BCF. 3.VOIDAGE BALANCE BY MONTH OF PRODUCED AND INJECTED FLUIDS (RULE 9B) During the reporting period, field production averaged 7.0 MBOPD,47.1 MMSCFD (FGOR 6.7 MSCF/STB), and 15.9 MBWPD (WC 70%).The average voidage replacement ratio was 0.78. 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,increasing water injection supply pressure to enhance injection rates where needed, and recompleting wells up hole to the Kuparuk interval for increased injection capacity. Booster pumps were installed at Z Pad to provide increased injection pressure for low injectivity patterns. 4.ANALYSIS OF RESERVOIR PRESSURE SURVEYS WITHIN THE POOL (RULE 9C) Reservoir pressure monitoring is performed in accordance with Rule 5 of Conservation Order 471. A summary of reservoir pressure surveys obtained during the reporting period is shown in Table 2. Five producers and one injector have been completed with permanent bottomhole gauges, giving valuable information about the flowing conditions, reservoir pressures,and reservoir connectivity on a continuous basis. 11 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. 5 5.RESULTS AND ANALYSIS OF SPECIAL MONITORING (RULE 9D) During the reporting period, no production or injection logs were run in the Borealis Field. 6.REVIEW OF POOL PRODUCTION ALLOCATION AND WELL TEST EVALUATION (RULE 9E)AND REVIEW OF POOL PRODUCTION ALLOCATION FACTORS AND ISSUES (RULE 4G) Borealis production allocation is performed according to the PBU Western Satellite Production Metering Plan. Allocation relies on performance curves to determine the daily theoretical production from each well. The GC-2 allocation factor is now being applied to adjust the total Borealis production similar to IPA production allocation procedures.A minimum of one well test per month is used to check the performance curves and to verify system performance. 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.A phase dyanamics meter was installed at the Z pad expansion in 2024.Overall, improvements in both well test quality and accuracy have been observed. Over the reporting period, the monthly average of daily oil production allocation factors fell within the range of 0.81 and 1.09 . 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. 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 October 2,2023. 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 Net Res Voidage Net Voidage Cum Monthly VRR Date STB MSCF STB STB MSCF STB MSCF STB STB RVB RVB RVB RVB/RVB Jul-23 213,890 1,191,904 499,955 572,979 1,090,968 98,569,528 175,945,252 167,522,742 252,500,314 354,838,408 410,136 73,522,591 0.76 Aug-23 168,557 1,153,024 401,536 682,691 1,030,526 98,738,085 177,098,276 167,924,278 253,183,005 356,180,506 166,472 73,894,752 0.89 Sep-23 171,173 1,235,959 373,914 550,381 1,363,745 98,909,258 178,334,235 168,298,192 253,733,386 357,592,920 139,671 74,254,219 0.91 Oct-23 171,203 1,125,458 474,810 524,482 1,518,141 99,080,461 179,459,693 168,773,002 254,257,868 359,074,384 80,738 74,536,645 0.95 Nov-23 176,132 1,240,492 498,148 439,538 1,462,777 99,256,593 180,700,185 169,271,150 254,697,406 360,434,030 326,805 75,085,337 0.81 Dec-23 213,132 1,351,788 594,754 432,103 1,693,530 99,469,725 182,051,973 169,865,904 255,129,509 361,929,085 412,060 75,739,987 0.78 Jan-24 229,971 1,477,642 602,364 427,555 1,727,345 99,699,696 183,529,615 170,468,268 255,557,064 363,440,420 522,293 76,526,939 0.74 Feb-24 242,455 1,631,062 576,726 396,029 1,601,018 99,942,151 185,160,677 171,044,994 255,953,093 364,840,961 745,472 77,563,518 0.65 Mar-24 241,025 1,596,010 474,611 432,736 1,702,550 100,183,176 186,756,687 171,519,605 256,385,829 366,342,260 510,006 78,357,527 0.75 Apr-24 234,283 1,637,311 418,269 398,565 1,571,507 100,417,459 188,393,998 171,937,874 256,784,394 367,727,117 598,454 79,246,478 0.70 May-24 245,778 1,845,380 417,529 426,211 1,617,606 100,663,237 190,239,378 172,355,403 257,210,605 369,169,030 724,318 80,297,432 0.67 Jun-24 241,596 1,714,217 467,903 516,266 1,601,931 100,904,833 191,953,595 172,823,306 257,726,871 370,693,981 579,247 81,181,073 0.72 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 Date Oil Allocation Factor Jul-23 0.90 Aug-23 0.88 Sep-23 0.94 Oct-23 0.88 Nov-23 0.91 Dec-23 0.93 Jan-24 0.93 Feb-24 0.88 Mar-24 0.92 Apr-24 0.91 May-24 0.94 Jun-24 0.86 TABLE 4: BOREALIS PRESSURES BY REPRESENTATIVE AREA Representative Area Well Date Pressure at Datum (psi) North of L Pad L-118 4/2/2024 2,330 Southwest of L Pad L-110 4/30/2024 3,015 North of V Pad V-101 4/3/2024 2,858 North of V Pad L-107 4/2/2024 2,606 North of V Pad V-108 4/8/2024 3,341 North of V Pad L-120 4/1/2024 3,586 North of V Pad V-107 4/3/2024 2,952 Northeast of V Pad V-115 4/3/2024 2,760 Northeast of V Pad V-106A 4/8/2024 3,199 South of V Pad V-117 4/3/2024 3,181 Z Pad Z-108 5/8/2024 2,851 7/23 –6/24 Midnight Sun Annual Surveillance Report 1 2024 ANNUAL RESERVOIR SURVEILLANCE REPORT MIDNIGHT SUN OIL POOL PRUDHOE BAY UNIT JULY 1,2023 –JUNE 30,2024 7/23 –6/24 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 7/23 –6/24 Midnight Sun Annual Surveillance Report 3 Prudhoe Bay Unit 2024 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 1,2023,through June 30, 2024. Progress of Enhanced Recovery Project Implementation and Reservoir Management Summary (Rule 11a) Production and injection volumes for the 12-month period ending June 30,2024,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 1.30.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 654 bopd, 5318 bwpd,7.95 mmscfpd and injected 12.6 mbwpd and 1.8 mmscfpd of MI for the report period resulting in a total VRR of 1.30 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. 7/23 –6/24 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 one pressure survey was obtained in E-102, which showed a pressure of 3,783 psi at datum. 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 0.97-1.03. 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 2024 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 October 2, 2023.A copy was provided to the Commission. The Commission will be copied when the 2025 update of the Western Satellites Plan of Development is filed with the Division. 7/23 –6/24 Midnight Sun Annual Surveillance Report 5 Figure 1: Midnight Sun Production and Injection History Figure 2: Midnight Sun Voidage History 7/23 –6/24 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-24 Jan-26psiaMidnight Sun Pressure History (measured at 8050 ft. TVDss datum) 7/23 –6/24 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 = 0.80 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-23 27,367 233,259 233,989 304,324 0 23,469,519 81,502,523 68,542,699 119,874,011 131,524,129 90,663 20,158,876 0.78 Aug-23 29,222 268,297 232,954 304,120 87,887 23,498,741 81,770,820 68,775,653 120,178,131 131,889,226 60,353 20,219,230 0.86 Sep-23 27,829 317,173 231,245 287,246 1,803 23,526,570 82,087,993 69,006,898 120,465,377 132,186,153 154,302 20,373,532 0.66 Oct-23 19,735 333,585 226,960 303,957 0 23,546,305 82,421,578 69,233,858 120,769,334 132,499,229 135,886 20,509,418 0.70 Nov-23 22,397 318,346 202,689 296,109 0 23,568,702 82,739,924 69,436,547 121,065,443 132,804,221 112,458 20,621,877 0.73 Dec-23 26,232 328,149 193,005 402,587 254,143 23,594,934 83,068,073 69,629,552 121,468,030 133,368,830 -147,778 20,474,099 1.35 Jan-24 23,146 294,457 174,426 557,701 0 23,618,080 83,362,530 69,803,978 122,025,731 133,943,262 -199,489 20,274,609 1.53 Feb-24 24,432 247,381 132,794 513,876 0 23,642,512 83,609,911 69,936,772 122,539,607 134,472,554 -223,808 20,050,801 1.73 Mar-24 23,112 285,691 151,923 510,116 0 23,665,624 83,895,602 70,088,695 123,049,723 134,997,974 -178,859 19,871,943 1.52 Apr-24 4,497 84,694 34,102 438,532 0 23,670,121 83,980,296 70,122,797 123,488,255 135,449,662 -362,406 19,509,537 5.06 May-24 209 5,322 12,253 413,629 0 23,670,330 83,985,618 70,135,050 123,901,884 135,875,700 -410,083 19,099,454 26.70 Jun-24 11,251 193,449 120,097 290,704 305,328 23,681,581 84,179,067 70,255,147 124,192,588 136,355,268 -231,257 18,868,198 1.93 7/23 –6/24 Midnight Sun Annual Surveillance Report 8 Table 2:MIDNIGHT SUN PRESSURE SURVEY DETAILS 6. Oil Gravity: 25 - 29 8. Well Name and Number: 9. API Number 50XXXXXXXXXXXX NO DASHES 10. Type See Instructions 11. AOGCC Pool Code 12. Zone 13. Perforated Intervals Top - Bottom TVDSS 14. Final Test Date 15. Shut-In Time, Hours 16. Press. Surv. Type (see instructions for codes) 17. B.H. Temp. 18. Depth Tool TVDSS 19. Final Observed Pressure at Tool Depth 20. Datum TVDSS (input) 21. Pressure Gradient, psi/ft. 22. Pressure at Datum (cal) E-102 500292304200 O 640158 8053-8079,8129-8155,8119-8129,8098- 8119,8145-8155,8129-8145 4/06/2024 7028 SBHP 161 8049.79 3783 8050 0.3217 3783 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. 7. Gas Gravity: Prudhoe Bay Unit Hilcorp North Slope, LLC 3800 Centerpoint Dr, Suite 1400, Anchorage, AK 99503 Prudhoe Bay Field, Midnight Sun Pool 8050 TVDss 0.72 3. Unit or Lease Name:4. Field and Pool:5. Datum Reference: RESERVOIR PRESSURE REPORT 1. Operator:2. Address: 7/23 –6/24 Midnight Sun Annual Surveillance Report 9 Table 3: Allocation Factors Date Allocation Factor Jul-23 1.00 Aug-23 0.98 Sep-23 1.00 Oct-23 1.02 Nov-23 1.00 Dec-23 1.00 Jan-24 1.00 Feb-24 0.97 Mar-24 1.00 Apr-24 0.99 May-24 1.00 Jun-24 1.03 1 7/23 –6/24 ORION ANNUAL SURVEILLANCE REPORT 2024 ANNUAL SURVEILLANCE REPORT ORION OIL POOL PRUDHOE BAY UNIT JULY 1,2023 –JUNE 30,2024 2 7/23 –6/24 ORION ANNUAL SURVEILLANCE REPORT CONTENTS 1.INTRODUCTION..................................................................................................................................3 2.VOIDAGE BALANCE BY MONTH OF PRODUCED AND INJECTED FLUIDS (RULE 9A)................................3 3.ANALYSIS OF RESERVOIR PRESSURE SURVEYS WITHIN THE POOL (RULE 9B)........................................3 4.RESULTS AND ANALYSIS OF PRODUCTION & INJECTION LOGGING SURVEYS, AND SPECIAL MONITORING (RULE 9C).....................................................................................................................4 5.REVIEW OF POOL PRODUCTION ALLOCATION (RULE 9D)AND REVIEW OF POOL PRODUCTION ALLOCATION FACTORS AND ISSUES (RULE 4F)....................................................................................4 6.PROGRESS OF ENHANCED RECOVERY PROJECT IMPLEMENTATION AND RESERVOIR MANAGEMENT SUMMARY (RULE 9E)..........................................................................................................................5 7.RESULTS OF MONITORING TO DETERMINE ENRICHED GAS INJECTANT BREAKTHROUGH TO OFFSET PRODUCERS (RULE 9G).......................................................................................................................6 8.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 7/23 –6/24 ORION ANNUAL SURVEILLANCE REPORT PRUDHOE BAY UNIT 2023-2024 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 1,2023 to June 30, 2024. 2.VOIDAGE BALANCE BY MONTH OF PRODUCED AND INJECTED FLUIDS (RULE 9A) During the reporting period, field production averaged 22,922 BOPD,41.7 MMSCFD (FGOR 1,821 SCF/STB), and 15,310 BWPD (WC 40%).Water injection during this period averaged 29,510 BWIPD with 61,332 MMSCFD of miscible gas injection. The average voidage replacement ratio was 1.12. 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, 2024 to June 30th, 2025, 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 L-233 and is supported by injectors L-117i,L-211i, L-212i,L-218i, L-240i.Measured pressure in this polygon is 1798 psi. Polygon 1A This polygon contains producers L-202, L-203, and L-250 and is supported by injectors L-215i, L-216i, L-217i, L-219i, and L-223i.Measured pressures in the polygon averaged 1938 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 2177 psi. Polygon 2A This polygon contains producers L-201, L-204, and V-207 and is supported by injectors L-210i, L-214Ai, L- 222i,V-137i,V-219i, V-220i, V-221i,and V-224i. Measured pressures in the polygon averaged 1062 psi. 4 7/23 –6/24 ORION ANNUAL SURVEILLANCE REPORT Polygon 5S This polygon contains producer L-205A and is supported by injectors L-220i and L-221i.Measured pressures in the polygon averaged 2371 psi. Polygon 3 This polygon contains producers Z-220, Z-222, Z-228, Z-229, and W-26B and is supported by injectors Z- 221i, Z-223i, Z-234i, Z-235i, and W-241i.Measured pressures in the polygon averaged 2676 psi. 4.RESULTS AND ANALYSIS OF PRODUCTION &INJECTION LOGGING SURVEYS,AND SPECIAL MONITORING (RULE 9C) Production Logs: Production logs were run on L-292 and L-295 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-240 and V-220 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.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. 5 7/23 –6/24 ORION ANNUAL SURVEILLANCE REPORT 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 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. During the reporting period, average injection rate was 29,510 BWIPD. Cumulative injection through June 2024 was 87.1 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 61.3 MMSCFD.Cumulative injection through June 2024 was 82.7 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. 6 7/23 –6/24 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.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-206,L-207,L-233, L-253, L-292,V-202, V-203, V-204, V- 205,V-207,V-234,Z-220, Z-222, Z-228, Z-229, and W-26B. 8.FUTURE DEVELOPMENT PLANS Future development plans are discussed in the 2024 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 October 2, 2023, a copy of which was provided to the Commission.The Commission will be copied when the 2025 update of the Orion Plan of Development is filed with the Division. 7 7/23 –6/24 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-23 654,755.1,208,602.454,119.522,977.1,970,798.50,173,283.62,077,743.36,783,106.76,819,129.114,322,603.11,532 242,337 0.99 Aug-23 693,347.1,277,685.465,737.532,386.1,773,077.50,866,630 63,355,428 37,248,843 77,351,515 115,906,428 202,462 444,799 0.89 Sep-23 559,470.1,253,056.345,901.560,359.1,749,317.51,426,100 64,608,484 37,594,744 77,911,874 117,504,488 -55,865 388,934 1.04 Oct-23 622,747.1,368,577.467,066.908,489.1,640,570.52,048,847 65,977,061 38,061,810 78,820,363 119,389,998 -101,486 287,447 1.06 Nov-23 673,047.1,265,627.490,176.1,041,521.1,521,575.52,721,894 67,242,688 38,551,986 79,861,884 121,339,664 -162,266 125,182 1.09 Dec-23 655,556.1,109,012.512,252.1,479,184.1,425,578.53,377,450 68,351,700 39,064,238 81,341,068 123,674,730 -631,952 -506,770 1.37 Jan-24 705,412.1,080,305.425,665.1,196,327.1,474,105.54,082,862 69,432,005 39,489,903 82,537,395 125,752,743 -438,872 -945,642 1.27 Feb-24 629,806.1,151,542.436,713.1,031,529.1,544,322.54,712,668 70,583,547 39,926,616 83,568,924 127,705,737 -321,955 -1,267,598 1.20 Mar-24 794,777.1,285,023.500,433.962,998.1,887,815.55,507,445 71,868,570 40,427,049 84,531,922 129,792,176 -178,556 -1,446,154 1.09 Apr-24 831,862.1,264,113.496,439.880,827.2,362,863.56,339,307 73,132,683 40,923,488 85,412,749 132,075,900 -362,150 -1,808,303 1.19 May-24 818,598.1,555,104.497,484.931,400.2,519,364.57,157,905 74,687,787 41,420,972 86,344,149 134,503,039 -343,576 -2,151,879 1.16 Jun-24 727,200.1,414,009.496,185.723,310.2,516,847.57,885,105 76,101,796 41,917,157 87,067,459 136,718,522 -290,570 -2,442,449 1.15 8 7/23 –6/24 ORION ANNUAL SURVEILLANCE REPORT FIGURE 1: ORION PRODUCTION AND INJECTION HISTORY 9 7/23 –6/24 ORION ANNUAL SURVEILLANCE REPORT FIGURE 2: ORION VOIDAGE HISTORY 10 7/23 –6/24 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-204 500292331400 O 640135 OA, Oba, Obb, Obc,4354-4690 11/30/2023 690 SBHP 76 4328.29 1060 4400 0.0234 1062 L-207 500292370200 O 640135 Oba 4334-4229 1/26/2024 1857 SBHP 82 4200.03 1726 4400 0.3595 1798 L-247 500292376600 O 640135 Obd 4149-4420 11/12/2023 0 SBHP 4216 1884 4400 .46 1969 L-254 500292375200 WI 640135 Obd 4363-4456 6/18/2024 168 FL -74 480 4400 .353 2208 L-293 500292374900 WI 640135 NB 3931-4013 3/3/2024 1344 SBHP 84 3985.76 1885 4400 0.4434 2069 Z-235 500292376000 WI 640135 Obc 4897- 4898,4895- 4893,4880- 4880,4847- 4844,4911- 4910,4884- 4886,4888- 4882,4904- 4905,4899- 4893,4858- 4861,4844- 4846,4895- 4894,4865- 4865 6/18/2024 168 FL 4400 0.442 2676 L-223 500292341500 WI 640135 NB 4376-4395 6/3/2024 5040 SBHP 4338.93 1974 4400 .44 2001 L-223 500292341500 WI 640135 OA 4501-4538 6/3/2024 5040 SBHP 4477.12 2012 4400 .44 1978 L-223 500292341500 WI 640135 Oba 4566-4599 6/3/2024 5040 SBHP 4559.78 1993 4400 .44 1923 L-223 500292341500 WI 640135 Obc 4666-4686 6/3/2024 5040 SBHP 4641.77 2033 4400 .44 1927 L-223 500292341500 WI 640135 Obd 4717-4765 6/3/2024 5040 SBHP 4713.88 2002 4400 .44 1864 V-225 500292341900 WI 640135 Obc 4485-4505 1/15/2024 120 SBHP 4481.68 2213 4400 .44 2177 L-221 500292338500 WI 640135 NB 4089-4104 8/25/2023 216 SBHP 4038.44 2196 4400 .44 2355 L-221 500292338500 WI 640135 OA 4221-4258 8/25/2023 216 SBHP 4176.16 2256 4400 .44 2354 L-221 500292338500 WI 640135 Oba 4285-4315 8/25/2023 216 SBHP 4275.69 2393 4400 .44 2448 L-221 500292338500 WI 640135 Obc, Obc 4328-4401 8/25/2023 216 SBHP 4329.52 2316 4400 .44 2347 L-221 500292338500 WI 640135 Obd 4432-4480 8/25/2023 216 SBHP 4426.24 2360 4400 .44 2348 7. Gas Gravity: Prudhoe Bay Unit Hilcorp North Slope, LLC 3800 Centerpoint Dr, Suite 1400, Anchorage, AK 99503 Prudhoe Bay Field, Orion Oil Pool 4400 TVDss 0.7 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: 11 7/23 –6/24 ORION ANNUAL SURVEILLANCE REPORT FIGURE 3: ORION AVERAGE PRESSURE AT DATUM 12 7/23 –6/24 ORION ANNUAL SURVEILLANCE REPORT TABLE 3: ORION MONTHLY AVERAGE OIL ALLOCATION FACTORS 1 7/23 –6/24 POLARIS ANNUAL SURVEILLANCE REPORT 2024 ANNUAL SURVEILLANCE REPORT POLARIS OIL POOL PRUDHOE BAY UNIT JULY 1,2023 –JUNE 30,2024 2 7/23 –6/24 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 7/23 –6/24 POLARIS ANNUAL SURVEILLANCE REPORT PRUDHOE BAY UNIT 2023 -2024 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 1,2023 through June 30,2024. 2.VOIDAGE BALANCE BY MONTH OF PRODUCED AND INJECTED FLUIDS (RULE 9A) During the reporting period, field production averaged 6,709 BOPD,16,748 MMSCFD (FGOR 2,496 SCF/STB), and 9,624 BWPD (WC 59%). Water injection during this period averaged 15,810 BWIPD with 19,361 MMSCFD of miscible gas injection. The average voidage replacement ratio was 1.11. 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, 2024 to June 30, 2025, 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 3244 psi which is the average of M-201 and M-205 reported static pressures. 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 1941 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 1532 psi. W-Pad East This polygon contains producer W-203 and is supported by injectors W-207i,W-210i, and W-01.Measured pressure in this polygon is 2161 psi. 4 7/23 –6/24 POLARIS ANNUAL SURVEILLANCE REPORT 4.RESULTS AND ANALYSIS OF PRODUCTION &INJECTION LOGGING SURVEYS,AND SPECIAL MONITORING (RULE 9C) Production Logs: Production logs were run on W-202 and M-200 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 S-104 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 7/23 –6/24 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. During the reporting period, average injection rate was 15,810 BWIPD.Cumulative injection through June 2024 was 53.7 MMBW. 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 19.4 MMSCFD.Cumulative injection through June 2024 was 32.4 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. 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 6 7/23 –6/24 POLARIS ANNUAL SURVEILLANCE REPORT events appear to have a multitude of probable causes: faults, fractures, matrix short-circuit through high perm streaks, and what is believed to be the creation of tunnels or “worm holes”. During the reporting period,a new matrix bypass event from W-221 to W-204 through the Oba horizon was 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-200,W-205, W-203, S-213A, S-202 responded positively to miscible injectant. 8.Future Development Plans Future development plans are discussed in the 2024 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 October 2,2023,a copy of which was provided to the Commission.The Commission will be copied when the 2025 update of the Polaris Plan of Development is filed with the Division. 7 7/23 –6/24 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-23 213,447.470,166.292,227.510,692.556,267.34,709,482.39,577,342.25,992,386.48,474,409.64,490,407.-103,176 9,703,076 1.14 Aug-23 202,326.481,874.300,905.553,796.558,328.34,911,808 40,059,216 26,293,291 49,028,205 65,384,738 -140,970 9,562,105 1.19 Sep-23 158,792.354,788.241,305.486,583.465,367.35,070,600 40,414,004 26,534,596 49,514,788 66,155,407 -188,252 9,373,853 1.32 Oct-23 184,549.434,123.322,454.536,194.630,719.35,255,149 40,848,127 26,857,050 50,050,982 67,075,394 -187,599 9,186,254 1.26 Nov-23 210,807.551,618.305,361.570,776.471,960.35,465,956 41,399,745 27,162,411 50,621,758 67,935,054 -53,232 9,133,022 1.07 Dec-23 211,440.520,969.335,722.543,236.445,241.35,677,396 41,920,714 27,498,133 51,164,994 68,750,867 3,392 9,136,414 1.00 Jan-24 214,974.570,012.333,483.537,866.477,569.35,892,370 42,490,726 27,831,616 51,702,860 69,580,653 19,383 9,155,797 0.98 Feb-24 204,375.527,140.289,936.463,072.515,475.36,096,745 43,017,866 28,121,552 52,165,932 70,357,641 -5,923 9,149,874 1.01 Mar-24 225,839.528,286.284,474.471,484.696,566.36,322,584 43,546,152 28,406,026 52,637,416 71,251,779 -110,894 9,038,980 1.14 Apr-24 207,877.522,202.262,959.376,321.679,393.36,530,461 44,068,354 28,668,985 53,013,737 72,039,499 -44,090 8,994,890 1.06 May-24 233,158.627,925.267,998.385,192.815,847.36,763,619 44,696,279 28,936,983 53,398,929 72,918,051 -46,366 8,948,525 1.06 Jun-24 181,320.523,932.275,886.335,541.754,091.36,944,939 45,220,211 29,212,869 53,734,470 73,709,402 -54,670 8,893,855 1.07 8 7/23 –6/24 POLARIS ANNUAL SURVEILLANCE REPORT FIGURE 1: POLARIS PRODUCTION AND INJECTION HISTORY FIGURE 2: POLARIS VOIDAGE HISTORY 9 7/23 –6/24 POLARIS ANNUAL SURVEILLANCE REPORT TABLE 2: POLARIS PRESSURE SURVEY DETAIL 6. Oil Gravity: 15-23 8. Well Name and Number: 9. API Number 50XXXXXXXXXXXX NO DASHES 10. Type See Instructions 11. AOGCC Pool Code 12. Zone 13. Perforated Intervals Top - Bottom TVDSS 14. Final Test Date 15. Shut-In Time, Hours 16. Press. Surv. Type (see instructions for codes) 17. B.H. Temp. 18. Depth Tool TVDSS 19. Final Observed Pressure at Tool Depth 20. Datum TVDSS (input) 21. Pressure Gradient, psi/ft. 22. Pressure at Datum (cal) W-01A 500292186601 WI 64160 Oba, Obc, Obd 4995- 5020,5130- 5174,8894- 8922,8922- 8936,5078- 5104 6/20/2024 3777.68 SBHP 98 4999.85 2161 5000 0.5401 2161 W-211 500292308000 O 64160 Oba, Obc, Obd, Obe 5127- 5156,5067- 5076,5191- 5220,5258- 5263 8/12/2023 1896 SBHP 96 5000.74 1532 5000 0.0995 1532 M-201 500292371100 WI 64160 Oba 5106-5214 5/9/2024 174 PBU 95 4994.92 3384 5000 0.44 3386 M-205 500292373300 WI 64160 Obd 5277-5288 5/9/2024 180 PBU 109 5150.09 3167 5000 0.44 3101 S-215 500292310700 WI 64160 Obd 5240-5267 2/24/2024 480 PFO 5218 2037 5000 0.44 1941 7. Gas Gravity: Prudhoe Bay Unit Hlcorp North Slope, LLC 3800 Centerpoint Dr, Suite 1400, Anchorage, AK 99503 Prudhoe Bay Field, Polaris Oil Pool 5000 TVDss 0.7 3. Unit or Lease Name:4. Field and Pool:5. Datum Reference: STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION RESERVOIR PRESSURE REPORT 1. Operator:2. Address: 10 7/23 –6/24 POLARIS ANNUAL SURVEILLANCE REPORT FIGURE 3: POLARIS AVERAGE PRESSURE AT DATUM 11 7/23 –6/24 POLARIS ANNUAL SURVEILLANCE REPORT TABLE 3: POLARIS MONTHLY AVERAGE OIL ALLOCATION FACTORS