Alaska Logo
Department of Commerce, Community, and Economic Development
Alaska Oil and Gas Conservation
Commission
Loading...
HomeMy WebLinkAbout2020 Prudhoe Satellite Oil Pools 1 2020 ANNUAL SURVEILLANCE REPORT AURORA OIL POOL PRUDHOE BAY UNIT JULY 1, 2019 – JUNE 30, 2020 2 CONTENTS 1. INTRODUCTION 3 2. PROGRESS OF ENHANCED RECOVERY PROJECT IMPLEMENTATION AND RESERVOIR MANAGEMENT SUMMARY (RULE 8A) 3 3. VOIDAGE BALANCE BY MONTH OF PRODUCED AND INJECTED FLUIDS (RULE 8B) 4 4. ANALYSIS OF RESERVOIR PRESSURE SURVEYS WITHIN THE POOL (RULE 8C) 4 5. RESULTS AND ANALYSIS OF SPECIAL MONITORING (RULE 8D) 4 6. REVIEW OF POOL PRODUCTION ALLOCATION (RULE 8E) AND REVIEW OF POOL PRODUCTION ALLOCATION FACTORS AND ISSUES (RULE 4E) 5 7. FUTURE DEVELOPMENT PLANS (RULE 8F) 5 LIST OF ATTACHMENTS Figure 1: Aurora production and injection history 8 Figure 2: Aurora voidage history 8 Table 1: Aurora monthly production and injection summary 6 Table 2: Aurora cumulative voidage by fault block 7 Table 3: Aurora pressure survey detail 9 Table 4: Aurora monthly average oil allocation factors 10 Table 5: Aurora pressures by representative area 10 3 Prudhoe Bay Unit 2020 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, 2019 to June 30, 2020. 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 p lan. 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 cu t, 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 cont inued 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 su rveillance 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 18.1 MBWIPD and 3.8 MMSCFD. Cumulative injection through June 2020 was 135.0 MMSTBW and 51.3 BCF. A total of 20 injectors have been on water injection and 18 injectors have been on MI. 3. VOIDAGE BALANCE BY MONTH OF PRODUCED AND INJECTED FLUIDS (RULE 8 B) During the reporting period, field production averaged 4.4 MBOPD, 11.6 MMSCFD (FGOR 2.7 MSCF/STB), and 17.6 MBWPD (WC 80 %). The average voidage replacement ratio was 0.68. Monthly production, injection, and voidage volumes for the reporting period are summarized in Table 1. Cumulative production, injection, and voidage replacement ratios by fault block are summarized in Table 2. Figures 1 and 2 graphically depict this information since field start-up. Plans to achieve injection withdrawal ratios consistent with the reservoir managemen t 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. Nine static pressure measurements were obtained during the reporting period, covering all active areas, as shown in Table 5. Most producers in the AOP have evidence of pressure response to injection support. For the period of July 1st, 2020 to June 30th, 2021, 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 log were run in the Aurora Field. 5 6. REVIEW OF POOL PRODUCTION ALLOCATION (RULE 8 E) AND REVIEW OF POOL PRODUCTION ALLOCATION FACTORS AND ISSUES (RULE 4E) Aurora 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 Aurora 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. Over the reporting period, the monthly average of daily oil production allocation factors fell within the range of 0.85 and 0.91. Any days with allocation factors of zero were excluded. The monthly averages of daily oil production allocation factors are shown in Table 4. 7. FUTURE DEVELOPMENT PLANS (RULE 8 F) Future development plans are discussed in the 2020 update to the Plan of Development for the Aurora Participating Area, which was filed with the Division of Oil and Gas of the Alaska Department of Natural Resources on September 30, 2019, a copy of which was provided to the Commission. The Commission will be copied when the 2021 update of the Aurora Plan of Development is filed with the Division. 6 TABLE 1: AURORA MONTHLY PRODUCTION AND INJECTION SUMMARY Report Oil Prod Gas Prod Water Prod Water Inj MI Inj Oil Prod Cum Gas Prod Cum Water Prod Cum Water Inj Cum Cum Total Inj (MI+Water) Net Res Voidage Net Voidage Cum Monthly VRR Date STB MSCF STB STB MSCF STB MSCF STB STB RVB RVB RVB RVB/RVB Jul-19 157,308.496,398.594,851.583,170.96,069.47,212,739.137,510,231.66,744,594.128,944,367.162,528,849.449,974 449,974 0.59 Aug-19 43,079.140,530.158,857.147,229.5,102.47,255,818 137,650,761 66,903,451 129,091,596 162,682,186 147,818 147,818 0.51 Sep-19 18,215.31,512.47,120.38,260.0.47,274,033 137,682,273 66,950,571 129,129,856 162,721,211 49,665 49,665 0.44 Oct-19 144,874.324,488.680,230.291,484.2,303.47,418,907 138,006,761 67,630,801 129,421,340 163,019,953 771,124 771,124 0.28 Nov-19 170,872.483,256.590,159.560,722.18,866.47,589,779 138,490,017 68,220,960 129,982,062 163,603,586 524,173 524,173 0.53 Dec-19 184,952.548,216.722,824.674,228.17,263.47,774,731 139,038,233 68,943,784 130,656,290 164,302,002 601,977 601,977 0.54 Jan-20 162,883.440,833.645,529.591,024.18,164.47,937,614 139,479,066 69,589,313 131,247,314 164,916,108 514,233 514,233 0.54 Feb-20 149,373.378,760.610,204.713,016.102,944.48,086,987 139,857,826 70,199,517 131,960,330 165,707,210 246,416 246,416 0.76 Mar-20 153,926.407,467.666,490.763,676.290,559.48,240,913 140,265,293 70,866,007 132,724,006 166,666,306 159,127 159,127 0.86 Apr-20 147,768.373,535.662,894.756,518.300,646.48,388,681 140,638,828 71,528,901 133,480,524 167,624,355 128,036 128,036 0.88 May-20 124,042.272,068.466,718.756,137.305,171.48,512,723 140,910,896 71,995,619 134,236,661 168,584,820 -166,025 -166,025 1.21 Jun-20 141,826.357,875.612,085.746,186.238,646.48,654,549 141,268,771 72,607,704 134,982,847 169,493,891 108,309 108,309 0.89 7 TABLE 2: AURORA CUMULATIVE VOIDAGE BY FAULT BLOCK On Jun-20 Aurora Aurora Aurora Aurora Aurora Aurora Crest*N of Crest**E of Crest*W of Crest*S of Crest* Total Cumulative Injection (rsvb)20,266,050 51,294,072 12,149,122 74,009,987 11,996,349 169,715,580 Total Cumulative Production (rsvb)35,929,122 59,534,593 14,738,970 87,293,311 29,180,653 226,676,651 Cumulative Voidage Replacement Ratio 0.56 0.86 0.82 0.85 0.41 0.75 * Initial Gas Cap ** Solution Gas Only Bo 1.32 rsvb/stb Bg 0.84 rsvb/mscf Bw 1.02 rsvb/stb Rs 0.65 mscf/stb Bg (MI)0.62 rsvb/mscf 8 FIGURE 1: AURORA PRODUCTION AND INJECTION HISTORY FIGURE 2: AURORA VOIDAGE HISTORY 9 TABLE 3 - AURORA PRESSURE SURVEY DETAIL 6. Oil Gravity: 0.9SG/25 API 8. Well Name and Number: 9. API Number 50XXXXXXXXXXXX NO DASHES 10. Type See Instructions 11. AOGCC Pool Code 12. Zone 13. Perforated Intervals Top - Bottom TVDSS 14. Final Test Date 15. Shut-In Time, Hours 16. Press. Surv. Type (see instructions for codes) 17. B.H. Temp. 18. Depth Tool TVDSS 19. Final Observed Pressure at Tool Depth 20. Datum TVDSS (input) 21. Pressure Gradient, psi/ft. 22. Pressure at Datum (cal) S-22B 500292211902 WAG 640120 6613-6667 11/17/2019 11,367 SBHP 142 6,800 2,500 6700 0.440 2455 S-113B 500292309402 O 640120 6697-6644, 6746-6639 10/5/2019 1,383 SBHP 143 6,500 2,732 6700 0.100 2752 S-116A 500292318301 WAG 640120 6776-6749 10/8/2019 1,460 SBHP 135 6,635 4,071 6700 0.440 4100 S-118 500292318800 O 640120 6617-6651, 6697-6711 4/16/2020 52,280 SBHP 125 6,350 2,190 6700 0.340 2309 S-123 500292321900 WAG 640120 6646 - 6675, 6681 - 6693 9/6/2019 696 OTHER (60) 1,760 6700 0.430 4637 S-124 500292332300 WAG 640120 6808 - 6816, 6825 - 6835, 6837 - 6854 6864 - 6873, 6881 - 6888 9/6/2019 672 OTHER (63) 650 6700 0.430 3529 S-128 500292343600 WAG 640120 6795, 6753, 6719, 6857, 6816, 6796 11/9/2019 2,339 SBHP 133 6,700 3,355 6700 0.180 3355 S-129 500292343300 O 640120 6724.25-6725.02 6747.41-6752.28 6751.06-6761.81 6763.27-6783.25 6782.90-6740.05 6737.26-6728.57 10/10/2019 2,319 SBHP 148 6,618 3,670 6700 0.280 3694 S-200A 500292284601 O 640120 6735-6754 10/6/2019 1,402 SBHP 143 6,500 2,237 6700 0.150 2283 *Other: Static pressure for water injectors were calculated based tubing fluid level shots and water gradient below known freeze protect volume 7. Gas Gravity: Prudhoe Bay Unit Prudhoe Bay Field: Aurora Oil Pool 6700 TVDss 0.72 August 17th, 2020 3. Unit or Lease Name:4. Field and Pool:5. Datum Reference: ALASKA OIL AND GAS CONSERVATION COMMISSION RESERVOIR PRESSURE REPORT 1. Operator:2. Address: Hilcorp Alaska, LLC 3800 Centerpoint Dr. Anchorage, AK, 99516 STATE OF ALASKA Gavin Dittman 23. All tests reported herein were made in accordance with the applicable rules, regulations and instructions of the Alaska Oil and Gas Conservation Commission. I hereby certify that the foregoing is true and correct to the best of my knowledge. Gavin DittmanSignature Printed Name Title Date Reservoir Engineer 10 TABLE 4 - AURORA MONTHLY AVERAGE OIL ALLOCATION FACTORS Month Oil Jul-19 0.85 Aug-19 0.91 Sep-19 0.85 Oct-19 0.87 Nov-19 0.87 Dec-19 0.87 Jan-20 0.87 Feb-20 0.87 Mar-20 0.86 Apr-20 0.86 May-20 0.88 Jun-20 0.86 TABLE 5: AURORA PRESSURES BY REPRESENTATIVE AREA Representative Area Well Pressure at Datum (psi) S-22B 2455 S-118 2309 S-113B 2752 S-116A 4100 S-128 3355 S-129 3694 East of Crest S-123 4637 North of Crest S-124 3529 Northwest of Crest S-200A 2283 Crest South of Crest 1 2020 ANNUAL SURVEILLANCE REPORT BOREALIS OIL POOL PRUDHOE BAY UNIT JULY 1, 2019 – JUNE 30, 2020 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 PRODUCTIN ALLOCATION FACTORS AND ISSUES (RULE 4G) .................................................... 5 7. OPERATIONS, DEVELOPMENT & RESERVOIR DEPLETION PLANS REVIEW (RULE 9F AND 9G) ................. 5 . LIST OF ATTACHMENTS Figure 1: Borealis production and injection history ......................................................................................... 8 Figure 2: Borealis voidage history .................................................................................................................... 8 Table 1: Borealis monthly production and injection summary ........................................................................ 7 Table 2: Borealis pressure survey detail ........................................................................................................... 9 Table 3: Borealis monthly average oil allocation factors ................................................................................ 10 Table 4: Borealis pressures by representative area ....................................................................................... 10 3 Prudhoe Bay Unit 2020 Borealis Oil Pool Annual Reservoir Report 1. INTRODUCTION This Annual Reservoir Report is submitted to the Alaska Oil and Gas Conservation Commission for the Borealis Oil Pool in accordance with Commission regulations and Conservation Order 471. This report covers the period from July 1, 2019 through June 30, 2020. 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 unde r 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 dril ling 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 t he 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 pre ssure 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 29.5 MBWIPD and 18.0 MMSCFD. Cumulative injection through June 2019 was 228.1 MMSTBW and 109.9 BCF. A total of 22 injectors have been on water injection and 24 injectors have been on MI. 3. VOIDAGE BALANCE BY MONTH OF PRODUCED AND INJECTED FLUIDS (RULE 9B) During the reporting period, field production averaged 4.6 MBOPD, 14.5 MMSCFD (FGOR 3.2 MSCF/STB), and 24.2 MBWPD (WC 84%). 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. Booster pumps were installed at Z Pad to provide increased injection pressure for low injectivity patterns. 4. ANALYSIS OF RESERVOIR PRESSURE SURVEYS WITHIN THE POOL (RULE 9C) Reservoir pressure monitoring is performed in accordance with Rule 5 of Conservation Order 471. A summary of reservoir pressure surveys obtained during the reporting period is shown in Table 2. Five of the newer producers and one injector have been completed with permanent bottomhole gauges, giving valuable information about the flowing conditions, reservoir pressures, and reservoir connectivity on a continuous basis. 13 static pressure measurements were obtained during the reporting period , covering all active areas, as shown in Table 4. Most producers in Borealis have evidence of pressure response to injection support. For the period of July 1st, 2020 to June 30th, 2021, a minimum of one pressure survey will be taken in each of the active representative areas that contain active wells. If all active representative areas contain active wells, a minimum of six pressure surveys will be taken. 5 5. RESULTS AND ANALYSIS OF SPECIAL MONITORING (RULE 9D) During the reporting period, no production or injection logs were run in the Borealis Field. 6. REVIEW OF POOL PRODUCTION ALLOCATION AND WELL TEST EVALUATION (RULE 9E) AND REVIEW OF POOL PRODUCTION ALLOCATION FACTORS AND ISSUES (RULE 4G) Borealis production allocation is performed according to the PBU Western Satellite Production Mete ring 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. 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 0.85 and 0.96 . Any days with allocation factors of zero were excluded. The monthly averages of daily oil production allocation factors are shown in Table 3. 7. OPERATIONS, DEVELOPMENT & RESERVOIR DEPLETION PLANS REVIEW (RULE 9F & G) Miscible gas injection and water-alternating with miscible gas injection is used to increase the economic recovery of Borealis reservoir hydrocarbons. Injection wells are completed for Enha nced 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 s trategy targets a voidage replacement ratio of 1.0 through MI WAG injection to maintain reservoir pressure and to maximize commercial oil production. In March 2010, GC2 reached its permit limit for H2S production. Several Borealis wells were shut in during their MI responses due to elevated H2S in the returned MI. The installation of Metal Triazine injection continues to help maintain H2S production within the allowable limit. Borealis wells continue to show benefits from MI. Summarized below are significant events and accomplishments at Borealis over the past year:  Z-20: Recompleted as Kuparuk producer in 4Q 2019  Z-25: RWO to add Kuparuk injection in 4Q 2019 6  L-119A: Coil tubing sidetrack executed in 1Q 2020  MI was injected into 10 water-alternating-gas injectors  In addition to the aforementioned activity, miscellaneous producer and injector wellwork was executed to minimize oil rate decline. The Borealis owners will continue to evaluate optimal well count, well utility , wellwork and well locations to maximize commercial production. Future development plans are discussed in the 2020 update to the Plan of Development for the Borealis Participating Area, which was filed with the Division of O il and Gas of the Alaska Department of Natural Resources on September 30, 2019, a copy of which was provided to the Commission. The Commission will be copied when the 2021 update of the Borealis Plan of Development is filed with the Division. 7 TABLE 1: BOREALIS MONTHLY PRODUCTION AND INJECTION SUMMARY Report Oil Prod Gas Prod Water Prod Water Inj MI Inj Oil Prod Cum Gas Prod Cum Water Prod Cum Water Inj Cum Cum Total Inj (MI+Water) Net Res Voidage Net Voidage Cum Monthly VRR Date STB MSCF STB STB MSCF STB MSCF STB STB RB RVB RVB RVB/RVB Jul-19 186,043.771,381.1,102,920.799,719.408,585.88,359,710.133,696,047.128,674,023.218,061,111.288,904,116.783,898 34,547,349 0.58 Aug-19 49,790.185,887.225,911.111,965.23,889.88,409,500 133,881,934 128,899,934 218,173,076 289,034,252 283,818 34,831,166 0.31 Sep-19 115,777.465,931.808,754.684,652.108,387.88,525,277 134,347,865 129,708,688 218,857,728 289,806,643 503,007 35,334,173 0.61 Oct-19 151,572.515,686.769,014.1,162,431.373,454.88,676,849 134,863,551 130,477,702 220,020,159 291,235,489 -116,072 35,218,101 1.09 Nov-19 171,322.577,741.811,546.1,111,075.502,668.88,848,171 135,441,292 131,289,248 221,131,234 292,691,550 -34,820 35,183,281 1.02 Dec-19 149,112.436,512.698,304.1,034,195.756,358.88,997,283 135,877,804 131,987,552 222,165,429 294,225,713 -346,570 34,836,710 1.29 Jan-20 136,413.334,835.826,472.1,023,926.976,394.89,133,696 136,212,639 132,814,024 223,189,355 295,885,721 -420,279 34,416,431 1.34 Feb-20 121,072.327,853.556,839.981,786.846,172.89,254,768 136,540,492 133,370,863 224,171,141 297,421,587 -598,528 33,817,903 1.64 Mar-20 149,546.694,741.728,633.970,313.785,335.89,404,314 137,235,233 134,099,496 225,141,454 298,907,917 -106,821 33,711,081 1.08 Apr-20 136,920.364,949.767,723.951,462.593,635.89,541,234 137,600,182 134,867,219 226,092,916 300,255,977 -149,499 33,561,582 1.12 May-20 156,897.345,389.777,035.983,240.510,088.89,698,131 137,945,571 135,644,254 227,076,156 301,584,968 -106,481 33,455,101 1.09 Jun-20 152,113.275,751.781,399.992,029.705,133.89,850,244 138,221,322 136,425,653 228,068,185 303,043,941 -281,485 33,173,616 1.24 8 FIGURE 1: BOREALIS PRODUCTION & INJECTION HISTORY FIGURE 2: BOREALIS VOIDAGE HISTORY 9 TABLE 2: BOREALIS PRESSURE SURVEY DETAIL 1. Operator: Hilcorp Alaska. LLC 3. Unit or Lease Name:6. Oil Gravity:7. Gas Gravity: Prudhoe Bay Unit 0.9 SG / 25° API 0.72 8. Well Name and Number: 9. API Number 50XXXXXXXXXXXX NO DASHES 10. Type See Instructions 11. AOGCC Pool Code 12. Zone 13. Perforated Intervals Top - Bottom TVDSS 14. Final Test Date 15. Shut-In Time, Hours 16. Press. Surv. Type (see instructions for codes) 17. B.H. Temp. 18. Depth Tool TVDSS 19. Final Observed Pressure at Tool Depth 20. Datum TVDSS (input) 21. Pressure Gradient, psi/ft. 22. Pressure at Datum (cal) L-100 500292285801 O 640130 6562-6613 9/2/2019 586 SBHP 159 6599.93 2768.6 01/25/18 0.43 2768.63 L-102 500292307100 O 640130 10144 - 10170, 10170 - 10200, 10280 - 10290 8/31/2019 2890 SBHP 154.7 6600.06 2912.6 01/25/18 0.50 2912.57 L-105 500292307500 WAG 640130 6213.58-6229.98,6283.69-6300.32,6475.47-6484.87,6484.87- 6492.56,6484.87-6501.96,6492.56-6499.4,6499.4-6501.96,6501.96- 6528.47,6554.13-6559.26 4/13/2020 1344 Other -78.8 680 01/25/18 0.42 3481 L-106 500292305500 O 640130 6496 - 6560 3/9/2020 1134 SBHP 154.85 6565.33 3192.53 01/25/18 0.38 3205.56 L-108 500292309000 WAG 640130 4271.71-4308.01,4335.23-4364.07,4376.28-4391.62,4430.99- 4444.15,4483.7-4515.72,6440.59-6496.1,6504.74-6509.93,6516.84- 6522.88,6526.33-6531.51 4/17/2020 384 Other -78.4 790 01/25/18 0.42 3564 L-116 500292302500 O 640130 6392-6437, 6451-6457,6531-6551 4/16/2020 2043 SBHP 152 6525.41 3720 01/25/18 0.48 3755.86 L-119 500292307700 WAG 640130 6382 - 6384, 6473 - 6475, 6577 - 6602, 6609 - 6622 12/30/2019 9024 Other -78.9 534 01/25/18 0.42 3307 L-119A 500292307701 WAG 640130 6647-6649 4/1/2020 273 SBHP 124 6599.61 2988 01/25/18 0.33 2988.13 L-120 500292306400 O 640130 6477 - 6511 6521 - 6527 6/16/2020 788 SBHP 150 6499.94 3559 01/25/18 0.42 3601.16 V-117 500292315600 O 640130 6640.9-6622.68,6616.5-6604.36,6598.39-6600.85,6633.84- 6633.01,6633.01-6631.42,6631.42-6629.95,6624.53- 6624.21,6624.21-6624.12,6625.23-6626.62,6626.62- 6628.62,6628.62-6633.47,6627.57-6612.1,6612.02-6598.3,6596.72- 6596.74,6597.57-6608.84,6616.21-6620.87 7/19/2019 3981 SBHP 154.44 6599.88 3113.93 01/25/18 0.42 3113.98 V-122 500292332800 O 640130 6633.07-6625.4, 6620.42-6611.13, 6606.5-6603.16, 6601.28- 6596.49, 6595.92-6601.47, 6602.68-6603.59, 6605.05-6619.23, 6635.44-6631.5, 6631.34-6632.11, 6631.01-6630.72, 6632.17- 6631.23, 6630.7-6635.79, 6636.1-6637.88 9/12/2019 816 SBHP 155 6408.02 2368 01/25/18 0.44 2452.48 Z-102 500292335300 WAG 640130 6506 - 6525, 6529 - 6538, 6514 - 6513, 6512 - 6507, 6505 - 6501 9/9/2019 840 Other -81.3 370 01/25/18 0.41 3141 Z-25 500292190200 WAG 640130 6498 - 6508, 6523 - 6527 11/12/2019 181 SBHP 147.4 6700.23 2749.16 01/25/18 0.51 2698.5 *Other: Static pressure for water injectors were calculated based tubing fluid level shots and water gradient below known freeze protect volume Gavin Dittman 23. All tests reported herein were made in accordance with the applicable rules, regulations and instructions of the Alaska Oil and Gas Conservation Commission. I hereby certify that the foregoing is true and correct to the best of my knowledge. Gavin DittmanSignature Printed Name Title Date Reservoir Engineer August 20th, 2020 4. Field and Pool:5. Datum Reference: Prudhoe Bay Field, Borealis Oil Pool 6600 TVDss STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION RESERVOIR PRESSURE REPORT 2. Address: 3800 Centerpoint Dr. Anchorage, AK, 99503 10 TABLE 3: BOREALIS MONTHLY AVERAGE OIL ALLOCATION FACTORS Month Oil Jul-19 0.86 Aug-19 0.91 Sep-19 0.85 Oct-19 0.87 Nov-19 0.96 Dec-19 0.87 Jan-20 0.87 Feb-20 0.88 Mar-20 0.86 Apr-20 0.86 May-20 0.88 Jun-20 0.86 TABLE 4: BOREALIS PRESSURES BY REPRESENTATIVE AREA Representative Area Well Pressure at Datum (psi) L-105 3481 L-106 3206 L-108 3564 Northeast of V Pad V-122 2452 Z-102 3141 Z-25 2699 South of V Pad V-117 3114 Southwest of L Pad L-100 2769 L-102 2913 L-116 3756 L-119 3307 North of V Pad Z Pad North of L Pad 1 7/19 – 6/20 ORION ANNUAL SURVEILLANCE REPORT 2020 ANNUAL SURVEILLANCE REPORT ORION OIL POOL PRUDHOE BAY UNIT JULY 1, 2019 – JUNE 30, 2020 2 7/19 – 6/20 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 4, PART (F)) ........................ 5 6. PROGRESS OF ENHANCED RECOVERY PROJECT IMPLEMENTATION AND RESERVOIR MANAGEMENT SUMMARY (RULE 9E) ........................................................................... 6 7. PROGRESS OF PLANS AND TESTS TO EXPAND THE PRODUCTIVE LIMITS OF THE POOL (RULE 9F) ....................................................................................................................... 8 8. RESULTS OF MONITORING TO DETERMINE ENRICHED GAS INJECTANT BREAKTHROUGH TO OFFSET PRODUCERS (RULE 9G) ................................................... 8 9. FUTURE DEVELOPMENT PLANS..................................................................................... 8 LIST OF ATTACHMENTS Figure 1: Orion production and injection history ........................................................................................... 10 Figure 2: Orion voidage history ...................................................................................................................... 10 Figure 3: Orion pressures at datum................................................................................................................ 13 Table 1: Orion monthly production and injection summary ............................................................................ 9 Table 2: Orion pressure survey detail ............................................................................................................ 11 Table 3: Orion monthly average oil allocation factors ................................................................................... 15 3 7/19 – 6/20 ORION ANNUAL SURVEILLANCE REPORT PRUDHOE BAY UNIT 2020 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, 2019 to June 30, 2020. 2. V OIDAGE BALANCE BY MONTH OF PRODUCED AND INJECTED FLUIDS (RULE 9A) During the reporting period, field production averaged 3858 BOPD, 7.783 MMSCFD (FGOR 2,017 SCF/STB), and 6,817 BWPD (WC 64 %). Water injection during this period averaged 11,920 BWIPD with 9,543 MMSCFD of miscible gas injection. The average voidage replacement ratio was 1.23. 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, 2020 to June 30th, 2021, 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. Acquiring representative regional average pressures continues to be a challenge in Orion wells due to the physical characteristics of viscous oil, multiple sand targets, and multilateral producer wellbores which present a paradigm shift from typical data acquisition in light-oil reservoirs. Pressure gradients around producers and injectors are very shallow due to the low mobility of viscous oil , which results in very slow build-up and fall-off of pressures. Obtaining representative reservoir pressures is further complicated by significant differences in rock and oil properties between sands in the same wellbore, and as a result, productivity (and average sand pressure) varies dramatically between sands. Multilateral producers experience crossflow between laterals completed in different Schrader Bluff sands while shut-in, which can result in uneven zonal recharge. Injectors also suffer from slow bleed-off rates. Most injectors now incorporate check valves in the waterflood regulators to limit cross flow, but cross flow can occur where check valves are not present or not holding. These phenomena combine to make the quality of pressure transient analysis (PTA) questionable, and therefore, extrapolating a representative average reservoir pressure from pressure build-up (PBU) or pressure fall-off (PFO) data is difficult. In order to mitigate these concerns, single point pressure surveys are obtained whenever possible after a well has been offline for several weeks or months 4 7/19 – 6/20 ORION ANNUAL SURVEILLANCE REPORT to allow maximum build-up or fall-off. Even after a long shut-in time, wells show build-up or fall-off rates of several psi per day. In light of these challenges, significant effort is being made to obtain high-quality initial pre-injection or pre-production pressure surveys relatively unaffected by pressure gradients applied to the wellbore. Whenever possible, initial pressures by zone are being obtained with an MDT in new producers, or via downhole gauges in injectors. Injector data is becoming increasingly important as the flood matures. Once development is completed, this becomes the only practical way to collect pressure data on a zonal basis. An analysis of the recent pressure data by polygon follows: Polygon 1 This polygon contains producer L-200 and is supported by injectors L-211i, L-212i, and L-218i. During the reporting period, no new pressures were acquired as there was no production or injection from the polygon. Poylgon 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 from 1830 psi to 1664 psi. During the reporting period, producer L-203 was offline for sanding issues, L-250 was offline for most of the reporting period due to flow assurance issues. Polygon 2 This polygon contains producers V-202, V-203, V-204, V-205 and is supported by injectors L-213i, V-210i, V- 211i, V-212i, V-213i, V-214i, V-215i, V-216i, V-217i, V-218i, V-222i, V-223i, V-225i, V-229i. Measured pressures in the polygon range from 1962 psi to 1508 psi. Polygon 2A This polygon contains producers L-201, L-204, and V-207 and is supported by injectors L-210i, L-214Ai, L- 222, V-219i, V-220i, V-221i, V-224i, and V-227i. Measured pressures in the polygon range from 1528 psi to 1286 psi. Polygon 5S This polygon contains producer L-205A and is supported by injectors L-220i and L-221i. Measured pressures in the polygon range from 2391 psi to 2296 psi. Producer L-205A was offline for most of the reporting period due flow assurance issues caused by low flow rates. 4. RESULTS AND ANALYSIS OF PRODUCTION & INJECTION L OGGING SURVEYS, AND SPECIAL MONITORING (RULE 9 C) Production Logs: 5 7/19 – 6/20 ORION ANNUAL SURVEILLANCE REPORT No new production logs have been gathered over 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 prod ucer, and tested for API, viscosity, WC, and sand quantity. This data helps track changes in production from different sands, waterflood or MI response, and sanding tendencies. A portion of these samples is later used for geochemical production allocation analysis. (2) Wellhead samples are analysed quarterly for water properties to identify changes between formation water production and waterflood breakthrough. This data is also useful for identifying matrix bypass events (MBE) because produced water will have similar properties as injected water. (3) A produced water supply sample is analysed quarterly to serve as a baseline for analysis of well production samples. (4) Gas sampling is done monthly or quarterly depending on WAG activity in the polygon to establish gas chromatography signatures and track returned miscible injectant (MI). Geochemical Fingerprinting: This technique has been in use since 1999 in the North Slope viscous oil developments, and has shown promise in obtaining snapshot relative oil flow splits from individual sands. This data is useful in gauging zonal well performance, identifying problem laterals, and providing a basis by which to optimize offset injection. Wellhead oil samples are taken on roughly a qu arterly basis, or as well performance changes. Results to date are mixed with reasonable allocations in some wells, but questionable data in others. Work is ongoing to gather additional baseline oil samples, and improve analysis techniques to improve dat a value. Injection Logs: No injection logs were run during the reporting period. Injection logs are used to quality check waterflood regulating valve performance while in water service or to determine the distribution of miscible injectant between zones. Real-time Downhole Pressure Gauges in Injectors: Monitoring of individual zonal pressures is continuing on all injectors with downhole gauges installed. Real-time data has confirmed offtake from offset producers, formation and healing of MBE’s, pre ssure transmission across the OWC, and helped tremendously in identifying underperforming injection regulators. 5. REVIEW OF P OOL P RODUCTION ALLOCATION (RULE 9D) AND REVIEW OF POOL PRODUCTION ALLOCATION FACTORS A ND ISSUES (RULE 4, PART (F )) Orion production allocation was performed in accordance with the PBU Western Satellite Production Metering Plan, subject to ongoing review and approved changes. Allocation relied on performance curves to determine the daily theoretical production from each well. The GC-2 allocation factor was applied to adjust Orion production on a daily basis. A minimum of one well test per month was used to check the 6 7/19 – 6/20 ORION ANNUAL SURVEILLANCE REPORT performance curves, and to verify system performance, with more frequent testing during new well start - up and after significant wellwork. 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 E NHANCED RECOVERY PROJECT IMPLEMENTATION AND RESERVOIR MANAGEMENT SUMMARY (RULE 9 E) 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 11,920 BWIPD. Cumulative injection through June 2019 was 59.8 MMSTBW Enhanced Recovery Project - Miscible Injectant: In 2006, approval to implement an enhanced oil recovery project in the Orion oil pool using Prudhoe Bay miscible injectant was granted via C.O. 505A. Injection of miscible injectant began later that year in the updip portion of Polygon 2. The current MI strategy is to inject smaller slugs of miscible injectant to improve the efficiency of the flood. To date, miscible injectant has been injected in Polygon 1A, Polygon 2, Polygon 2A, and Polygon 5. During the reporting period, average injection rate was 9.5 MMSCFD. Cumulative injection through June 2020 was 35.1 BCF. Reservoir Management Strategy: The objective of the Orion oil pool reservoir management strategy is to manage reservoir development and depletion to maximize commercial production consistent with prudent oil field engineering practices. Key to this is achieving a balanced voidage replacement ratio requir ed to keep reservoir pressure above the bubble point. Individual floods are managed with downhole waterflood regulating valves in the injectors, as well as limited capabilities of reducing offtake in the producers by shutting in or choking laterals. 7 7/19 – 6/20 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: fau lts, fractures, matrix short-circuit through high perm streaks, and what is believed to be the creation of tunnels or “worm holes”. 7. PROGRESS OF PLANS AND TESTS TO EXPAND THE PRODUCTIVE LIMITS OF THE POOL (RULE 9F) New Sands: As mentioned in previous reports, Orion includes three wells with slotted liner completions in the N -sand; L-203, L-205, and V-207. 8. RESULTS OF M ONITORING TO D ETERMINE ENRICHED GAS INJECTANT BREAKTHROUGH TO OFFSET PRODUCERS (RULE 9G) A response to miscible injectant is indicated by an increase in produced gas rate, an increase in formation gas-oil-ratio, and a reduction in the producing ratio of C1 (methane) to C3 (propane). To date, in the life of the field, responses to miscible injectant have been observed in the following producers: L-201, L-202, V-202, V-203, V-204, V-205, and V-207. 9. FUTURE D EVELOPMENT PLANS Future development plans are discussed in the 2020 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, 2019, a copy of which was provided to the Commission. The Commission will be copied when the 2021 update of the Orion Plan of Development is filed with the Division. 8 7/19 – 6/20 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-19 155,932 288,548 255,651 492,820 179,091 38,443,661 37,914,409 20,164,866 55,967,992 75,269,526 -48,556 -1,253,935 1.09 Aug-19 32,273 61,399 46,664 53,355 2,910 38,475,934 37,975,808 20,211,530 56,021,347 75,325,131 53,913 -1,200,022 0.51 Sep-19 70,735 166,637 121,860 287,416 81,180 38,546,669 38,142,446 20,333,390 56,308,763 75,663,317 -59,451 -1,259,473 1.21 Oct-19 121,664 228,401 177,058 448,691 203,261 38,668,333 38,370,846 20,510,448 56,757,454 76,236,419 -160,890 -1,420,363 1.39 Nov-19 146,663 286,294 199,072 496,469 211,622 38,814,996 38,657,141 20,709,519 57,253,923 76,862,709 -137,423 -1,557,786 1.28 Dec-19 133,731 254,538 183,196 373,497 349,231 38,948,727 38,911,679 20,892,715 57,627,420 77,445,987 -139,665 -1,697,450 1.31 Jan-20 95,703 222,217 141,483 318,725 486,357 39,044,429 39,133,895 21,034,198 57,946,145 78,054,850 -257,277 -1,954,727 1.73 Feb-20 93,389 218,625 157,902 368,614 525,530 39,137,819 39,352,520 21,192,100 58,314,759 78,737,214 -318,188 -2,272,915 1.87 Mar-20 138,653 289,222 292,312 368,791 401,387 39,276,472 39,641,742 21,484,412 58,683,550 79,346,511 -71,426 -2,344,342 1.13 Apr-20 145,899 276,877 318,482 408,536 375,952 39,422,371 39,918,619 21,802,894 59,092,086 79,980,944 -67,306 -2,411,647 1.12 May-20 143,580 280,124 300,947 356,189 345,181 39,565,951 40,198,743 22,103,841 59,448,275 80,544,351 -15,148 -2,426,795 1.03 Jun-20 130,101 268,045 293,506 377,695 321,448 39,696,052 40,466,788 22,397,347 59,825,969 81,115,478 -48,214 -2,475,009 1.09 9 7/18 – 6/19 PBU Orion Annual Reservoir Report FIGURE 1: ORION PRODUCTION AND INJECTION HISTORY 10 7/18 – 6/19 PBU Orion Annual Reservoir Report FIGURE 2: ORION VOIDAGE HISTORY 11 7/18 – 6/19 PBU Orion Annual Reservoir Report TABLE 2: ORION PRESSURE SURVEY DETAIL 12 7/18 – 6/19 PBU Orion Annual Reservoir Report FIGURE 3: ORION AVERAGE PRESSURE AT DATUM 13 7/18 – 6/19 PBU Orion Annual Reservoir Report TABLE 3: ORION MONTHLY AVERAGE OIL ALLOCATION FACTORS Date Allocation Factor Jul-19 0.85 Aug-19 0.91 Sep-19 0.85 Oct-19 0.87 Nov-19 0.87 Dec-19 0.87 Jan-20 0.86 Feb-20 0.86 Mar-20 0.95 Apr-20 0.85 May-20 0.86 Jun-20 0.85 1 7/1 – 6/20 POLARIS ANNUAL SURVEILLANCE REPORT 2020 ANNUAL SURVEILLANCE REPORT POLARIS OIL POOL PRUDHOE BAY UNIT JULY 1, 2019 – JUNE 30, 2020 2 7/1 – 6/20 POLARIS ANNUAL SURVEILLANCE REPORT CONTENTS 1. INTRODUCTION ................................................................................................................... 3 2. V OIDAGE 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 P OOL PRODUCTION ALLOCATION (RULE 9D) AND REVIEW OF POOL PRODUCTION ALLOCATION FAC TORS AND ISSUES (RULE 4, PART (D)) ............................................................. 5 6. PROGRESS OF E NHANCED RECOVERY PROJECT IMPLEMENTATION AND RESERVOIR MANAGEMENT SUMMARY (RULE 9E) .......................................................................................................... 5 7. RESULTS OF M ONITORING TO D ETERMINE ENRICHED GAS INJECTANT BREAKTHROUGH TO OFFSET PRODUCERS (RULE 9F) ........................................................................................................ 7 8. FUTURE DEVELOPMENT PLANS…………………………………………………………………………………………. 8 LIST OF ATTACHMENTS Figure 1: Polaris production and injection history ........................................................................................... 10 Figure 2: Polaris voidage history ...................................................................................................................... 10 Figure 3: Polaris pressure at datum ................................................................................................................. 12 Table 1: Polaris monthly production and injection summary ............................................................................ 9 Table 2: Polaris pressure survey detail ............................................................................................................ 11 Table 3: Polaris monthly average oil allocation factors ................................................................................... 14 3 7/1 – 6/20 POLARIS ANNUAL SURVEILLANCE REPORT PRUDHOE BAY UNIT 2020 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, 2019 through June 30, 2020. 2. VOIDAGE BALANCE BY M ONTH OF PRODUCED AND INJECTED FLUIDS (RULE 9A) During the reporting period, field production averaged 4,399 BOPD, 6.3 MMSCFD (FGOR 1424 SCF/STB), and 5,094 BWPD (WC 54 %). Water injection during this period averaged 6,436 BWIPD with 3.4 MMSCFD of miscible gas injection. The average voidage replacement ratio was 0.81. 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, 2020 to June 30th, 2021, a minimum of one pressure survey will be taken in each of the active representative areas that contain active wells. Acquiring representative regional average pressures continues to be a challenge in Polaris wells due to the physical characteristics of viscous oil, three sand targets, and multilateral producer wellbores which present a paradigm shift from typical data acquisition in light -oil reservoirs. Pressure gradients around producers and injectors are very shallow due to the low mobility of viscous oil, which results in very slow build-up and fall-off of pressures. Obtaining representative reservoir pressures is further complicated by significant differences in rock and oil properties between sands in the same wellbore, and as a result, productivity (and average sand pressure) varies dramatically between sands. Multilateral producers experience cross-flow between laterals completed in different sands and uneven zonal recharge during shut-in. Injectors also suffer from slow bleed-off rates during shut-in. Most injectors now incorporate check valves in the waterflood regulators to limit cross flow, but cross flow can occur where check valves are not present or not holding. These phenomena combine to make the quality of pressure transient analysis (PTA) very questionable, and therefore, extrapolating a representative average reservoir pressure from pressure build- up (PBU) pressure fall-off (PFO) data is very difficult. In order to mitigate these concerns, single point pressure surveys are obtained whenever possible after a well has been offline for several weeks or months to allow maximum build-up or fall-off. Even after a long shut-in time, wells show build-up or fall-off rates of several psi per day. 4 7/1 – 6/20 POLARIS ANNUAL SURVEILLANCE REPORT In light of these challenges, significant effort is being made to obtain high-quality initial pre-injection or pre- production pressure surveys relatively unaffected by pressure gradients applied to the wellbore. Whenever possible, initial pressures by zone are being obtained with an MDT in new producers, or via downhole gauges in injectors. Injector data is expected to become increasingly important as the flood matures. Once development is completed, this becomes the only practical way to collect pressure data on a zonal basis. An analysis of the recent pressure data by polygon follows: S-Pad North This polygon contains producer S-202 and is supported by injectors S-104, S201, S210. Measured pressure in this polygon is 2153 psi. S-202 is a new drill well POP 12/2019 and is currently testing 1863 BOPD. 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 1297 psi. W-Pad North This polygon contains producers W-200, W-201, W-202, W-204, W-205, and W-211 and is supported by injectors W-209i, W-212i, W-213i, W-214i, W-215i, W-216i, W-217i, W-218i, W-219i, W-220i, W-221i, and W-223i. Measured pressures in this polygon is 1890 psi. W-Pad East This polygon contains producer W-203 and is supported by injectors W-207i and W-210i. Measured pressure in the polygon was 2428 psi. 4. RESULTS AND ANALYSIS OF PRODUCTION & I NJECTION L OGGING SURVEYS, AND SPECIAL M ONITORING (RULE 9C) Production Logs: No production logs were run during the reporting period. Prior production logs have frequently been adversely affected by well slugging. Future production logging candidates will be evaluated on a case by case basis. Well fluids sampling A well fluids sampling program is ongoing to gather high quality and frequency surveillance data: (1) Uncontaminated wellhead samples are obtained monthly to quarterly on each producer, and tested for API, viscosity, WC, and sand quantity. This data helps track changes in production from different sands, waterflood or MI response, and sanding tendencies. A portion of these samples are later used for geochemical production allocation analysis. (2) Wellhead samples are analysed quarterly for water properties to identify changes between formation water production and waterflood breakthrough. This data is also useful for identifying matrix bypass events (MBE) because produced water will have similar properties as injected water. (3) A produced water supply sample is analysed quarterly to serve as a baseline for analysis of well production samples. (4) Gas sampling is done monthly or quarterly depending 5 7/1 – 6/20 POLARIS ANNUAL SURVEILLANCE REPORT on WAG activity in the polygon to establish gas chromatography signatures and track returned miscible injectant (MI). Geochemical Fingerprinting This technique has been in use since 1999 in the North Slope viscous oil developments, and has shown promise in obtaining a snapshot or relative oil flow splits from individual sands. This data is useful in gauging zonal well performance, identifying problem laterals, and providing a basis by which to optimize offset injection. Wellhead oil samples are taken on roughly a quarterly basis, or as well performance changes. Results to date are mixed with reasonable allocations in some wells, but questionable data in others. Work is ongoing to gather additional baseline oil samples, and improve analysis techniques to improve data value. Injection Logs: No new injection logs were run in this area. Injection logs are typically run to quality check waterflood regulating valve performance while in water service or to determine the distribution of miscible injectant between zones. Real-time Downhole Pressure Gauges in Injectors Monitoring of individual zonal pressures is continuing on all injectors with downhole gauges installed. Real - time data has confirmed offtake from offset producers, formation and healing of MBE’s, pressure transmission across the OWC, and helped tremendously in identifying underperforming injection zones. The current Polaris injector basis of design calls for individual zonal pressure gauge installation in all future injectors. 5. REVIEW OF P OOL PRODUCTION ALLOCATION (RULE 9D) AND REVIEW OF POOL PRODUC TION ALLOCATION FACTORS A ND ISSUES (RULE 4, PART (D)) Polaris production allocation was performed in accordance with the PBU Western Satellite Production Metering Plan, subject to ongoing review and approved changes. Allocation relied on performance curves to determine the daily theoretical production from each well. The GC -2 allocation factor was applied to adjust Polaris production on a daily basis. A minimum of one well test per month was used to check the performance curves, and to verify system performance, with more frequent testing during new well start - up and after significant wellwork. The monthly averages of daily oil production allocat ion 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. P ROGRESS OF ENHANCED R ECOVERY PROJECT IMPLEMENTATION AND RESERVOIR M ANAGEMENT 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 6 7/1 – 6/20 POLARIS ANNUAL SURVEILLANCE REPORT 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 accuratel y 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 6,436 BWIPD. Cumulative injection through June 2020 was 35.9 MMSTBW, which has been injected into 21 water injectors. Two new water injectors have been placed into service during the reporting period to support the new drill well S-202. 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 3.3 MMSCFD. Cumulative injection through June 2020 was 9.43 BCF, which has been injected into 15 water-alternating-gas injectors. One new MI injector has been added to support the new drill well S-202. Reservoir Management Strategy: The objective of the Polaris oil pool reservoir management strategy is to manage rese rvoir development and depletion to maximize commercial production consistent with prudent oil field engineering practices. Key to this is achieving a balanced voidage replacement ratio required to keep reservoir pressure above the bubble point. Individual floods will be managed with downhole waterflood regulating valves in the injectors, as well as limited capabilities of reducing offtake in the producers by shutting in or choking laterals. Learnings over the last few years have revealed significant differences in productivity and oil mobility between Schrader Bluff sands. These learnings have led to changes in completion designs and operational strategies. In addition, the emergence of matrix bypass events has further highlighted the complexity of the Schrader Bluff sands. It is expected that the reservoir management strategy will continually be evaluated and revised as appropriate throughout the life of the field. 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”. 7 7/1 – 6/20 POLARIS ANNUAL SURVEILLANCE REPORT During the reporting period, no new matrix bypass events were identified. 7. RESULTS OF MONITORING TO DETERMINE ENRICHED GAS INJECTANT BREAKTHROUGH TO OFFSET P RODUCERS (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, no new responses to miscible injectant were observed. To date, in the life of the field, response to miscible injectant have been observed in the following producers: S-213A and W-204. 8. Future Development Plans Future development plans are discussed in the 2020 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, 2019, a copy of which was provided to the Commission. The Commission will be copied when the 2021 update to the Polaris Plan of Development is filed with the Division. 8 7/18 – 6/19 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-19 100,953 98,717 143,718 223,491 44,899 24,763,866 21,689,877 17,187,228 33,831,683 39,125,867 34,808 11,497,875 0.88 Aug-19 12,022 11,212 6,961 31,242 0 24,775,888 21,701,089 17,194,189 33,862,925 39,157,422 -7,902 11,489,973 1.33 Sep-19 14,670 18,535 15,500 53,681 0 24,790,558 21,719,624 17,209,689 33,916,606 39,211,639 -15,368 11,474,605 1.40 Oct-19 114,299 108,545 146,322 319,348 0 24,904,857 21,828,169 17,356,011 34,235,954 39,534,181 -21,059 11,459,048 1.07 Nov-19 140,885 178,211 187,839 204,248 15,186 25,045,742 22,006,380 17,543,850 34,440,202 39,749,583 179,705 11,656,244 0.55 Dec-19 181,912 218,704 212,632 209,025 57,996 25,227,654 22,225,084 17,756,482 34,649,227 39,995,496 229,953 11,906,033 0.52 Jan-20 175,203 192,222 201,629 216,911 57,746 25,402,857 22,417,306 17,958,111 34,866,138 40,249,224 209,450 12,115,482 0.55 Feb-20 144,521 205,604 168,410 192,237 160,430 25,547,378 22,622,910 18,126,521 35,058,375 40,539,641 121,986 12,237,468 0.70 Mar-20 174,104 392,680 194,830 183,273 157,425 25,721,482 23,015,590 18,321,351 35,241,648 40,819,202 296,120 12,533,588 0.49 Apr-20 182,198 230,036 204,166 204,346 188,009 25,903,680 23,245,626 18,525,517 35,445,994 41,138,397 174,990 12,708,578 0.65 May-20 191,299 262,028 186,717 233,949 294,528 26,094,979 23,507,654 18,712,234 35,679,943 41,551,402 90,242 12,798,821 0.82 Jun-20 173,557 370,408 190,596 277,237 259,706 26,268,536 23,878,062 18,902,830 35,957,180 41,987,235 121,758 12,920,579 0.78 9 7/18 – 6/19 POLARIS ANNUAL SURVEILLANCE REPORT FIGURE 1: POLARIS PRODUCTION AND INJECTION HISTORY FIGURE 2: POLARIS VOIDAGE HISTORY 10 7/18 – 6/19 POLARIS ANNUAL SURVEILLANCE REPORT TABLE 2: POLARIS PRESSURE SURVEY DETAIL 11 7/18 – 6/19 POLARIS ANNUAL SURVEILLANCE REPORT FIGURE 3: POLARIS AVERAGE PRESSURE AT DATUM 12 7/18 – 6/19 POLARIS ANNUAL SURVEILLANCE REPORT TABLE 3: POLARIS MONTHLY AVERAGE OIL ALLOCATION FACTORS Date Allocation Factor Jul-19 0.85 Aug-19 0.90 Sep-19 0.85 Oct-19 0.87 Nov-19 0.87 Dec-19 0.87 Jan-20 0.85 Feb-20 0.86 Mar-20 0.84 Apr-20 0.85 May-20 0.85 Jun-20 0.86 7/19 – 6/20 Midnight Sun Annual Surveillance Report 1 2020 ANNUAL RESERVOIR SURVEILLANCE REPORT MIDNIGHT SUN OIL POOL PRUDHOE BAY UNIT JULY 1, 2019 – JUNE 30, 2020 7/19 – 6/20 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 11 f & g) 4 LIST OF ATTACHMENTS Figure 1: Midnight Sun Monthly Production and Injection History ................................................................. 5 Figure 2: Midnight Sun Voidage History .......................................................................................................... 6 Figure 3: Midnight Sun Pressure History ......................................................................................................... 7 Table 1: Midnight Sun Monthly Production, Injection, Voidage Balance Summary ........................................ 8 Table 2: Midnight Sun Pressure Survey Details ............................................................................................... 9 Table 3: Midnight Sun Monthly Allocation Factors ....................................................................................... 10 7/19 – 6/20 Midnight Sun Annual Surveillance Report 3 Prudhoe Bay Unit 2020 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, 2019 through June 30, 2020. Progress of Enhanced Recovery Project Implementation and Reservoir Management Summary (Rule 11a) Production and injection volumes for the 12-month period ending June 30, 2020 are summarized in Table 1. The objective of the Midnight Sun reservoir management strategy is to manage reservoir development and depletion to maximize commercial production consistent with prudent oil field engineering practices. During primary depletion , both the E-101 and the E-102 producers experienced increasing gas-oil-ratios (GORs). Consequently, production was restricted to conserve reservoir energy. Produced water injection into the Midnight Sun reservoir commenced in October 2000 and continues to provide pressure support to Midnight Sun. The objective of water injection is to increase reservoir pressure, reduce GOR’s to enable wells to be produced at their full capacity, and maximize areal sweep efficiency. There is a risk of oil in-flux into the gas cap from mid-field water injection. Placement of the wells drilled in 2001 and voidage management are minimizing this risk. A historical VRR target of 1.0 to 1.3 is designed to increase reservoir pressure while minimizing re - saturation of oil into the gas cap. During the period covered by the report, the VRR averaged 0.64. Midnight Sun oil production volume decreased during the reporting period in an effort to increase VRR. 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 811 bopd, 6047 bwpd, 4.5 mmscfpd and injected 378 bwpd and 9.7 mmscfpd of MI for the report period resulting in a total VRR of 0.64 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. 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 7/19 – 6/20 Midnight Sun Annual Surveillance Report 4 is shown in Table 2. For the report period four reservoir pressures were acquired: E-103 (10/14/19, 4/9/20 & 4/9/20) and E-102 (11/18/19). Results and Analysis of Production & Injection Logging Surveys (Rule 11d) During the 2019-2020 reporting period, 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 has been performed according to the PBU Western Satellite Production Metering Plan for the report period. Over the reporting period, the monthly average of the daily oil production allocation factors fell within the range of 0.91-0.98. Any days with allocation factors of zero were excluded. The monthly averages of daily oil production allocation factors are shown in Table 3. Electronic files containing daily allocation data and daily test data for a minimum of five years are being retained. Future Development Plans and Review of Plan of Operations and Development (Rule 11f and g) Future development plans are discussed in the Annual Progress Report and Update of 2020 Plan of Development for the Midnight Sun Participating Area, which was filed with the Division of Oil and Gas of the Alaska Department of Natural Resources on Sep tember 30, 2019, a copy of which was provided to the Commission. The Commission will be copied when the Annual Progress Report and Update of 2021 Midnight Sun Plan of Development is filed with the Division. 7/19 – 6/20 Midnight Sun Annual Surveillance Report 5 Figure 1: Midnight Sun Production and Injection History Figure 2: Midnight Sun Voidage History 7/19 – 6/20 Midnight Sun Annual Surveillance Report 6 Figure 3: Midnight Sun Pressure History Table 1: Midnight Sun Monthly Production, Injection, Voidage Balance Summary Assumptions for Production Table: Oil Formation Volume Factor = 1.29 rb/stb Water Formation Volume Factor = 1.03 rb/stb Gas Formation Volume Factor = 0.798 rb/Mscf MI Formation Volume Factor = 0.59 rb/Mscf Report Oil Prod Gas Prod Water Prod Water Inj MI Inj Oil Prod Cum Gas Prod Cum Water Prod Cum Water Inj Cum Cum Total Inj (MI+Water) Net Res Voidage Net Voidage Cum Monthly VRR Date STB MSCF STB STB MSCF STB MSCF STB STB RB RVB RVB RVB/RVB Jul-19 21,358 174,578 195,769 138,045 0 22,139,791 71,953,684 57,562,842 105,715,495 111,359,579 182,346 22,142,076 0.44 Aug-19 29,832 189,185 266,081 0 232,836 22,169,623 72,142,869 57,828,923 105,715,495 111,496,952 276,090 22,418,166 0.33 Sep-19 22,938 130,682 193,801 0 166,299 22,192,561 72,273,551 58,022,724 105,715,495 111,595,069 199,962 22,618,127 0.33 Oct-19 33,794 132,778 223,929 0 337,254 22,226,355 72,406,329 58,246,653 105,715,495 111,794,049 141,476 22,759,603 0.58 Nov-19 23,402 121,338 182,916 0 332,953 22,249,757 72,527,667 58,429,569 105,715,495 111,990,491 85,343 22,844,947 0.70 Dec-19 25,785 135,946 207,411 0 323,898 22,275,542 72,663,613 58,636,980 105,715,495 112,181,591 126,753 22,971,700 0.60 Jan-20 21,668 100,039 174,516 0 335,331 22,297,210 72,763,652 58,811,496 105,715,495 112,379,436 61,107 23,032,807 0.76 Feb-20 23,147 111,216 164,332 0 242,033 22,320,357 72,874,868 58,975,828 105,715,495 112,522,235 113,635 23,146,442 0.56 Mar-20 24,631 129,595 152,108 0 418,111 22,344,988 73,004,463 59,127,936 105,715,495 112,768,921 9,384 23,155,826 0.96 Apr-20 22,573 158,594 143,826 0 313,099 22,367,561 73,163,057 59,271,762 105,715,495 112,953,649 78,003 23,233,830 0.70 May-20 24,058 119,798 153,391 0 415,535 22,391,619 73,282,855 59,425,153 105,715,495 113,198,815 5,911 23,239,741 0.98 Jun-20 22,769 131,431 149,160 0 448,803 22,414,388 73,414,286 59,574,313 105,715,495 113,463,609 -12,412 23,227,330 1.05 7/19 – 6/20 Midnight Sun Annual Surveillance Report 7 Table 2: MIDNIGHT SUN PRESSURE SURVEY DETAILS 7/19 – 6/20 Midnight Sun Annual Surveillance Report 8 Table 3: Midnight Sun Monthly Allocation Factors Month Oil Allocation Factor Jul-19 0.98 Aug-19 0.95 Sep-19 0.95 Oct-19 0.95 Nov-19 0.96 Dec-19 0.98 Jan-20 0.98 Feb-20 0.95 Mar-20 0.94 Apr-20 0.94 May-20 0.94 Jun-20 0.91 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) 640120 Aurora 6700 150 18 44 45 .72 0.72 3423 3464 3235 29.1 .72 112 53 1.35 1.35 .858 717 2661 640130 Borealis 6600 158 18 22 44 2.97 2.81 3442 2761 3127 24.1 .72 141 36 1.23 1.24 .861 457 3159 640135 Orion 4400 87 27.6 220 46.5 11.2 11 1950 1836 1824 18.7 .7 415 98 1.12 1.12 .830 272 2107 640160 Polaris 5000 98 26.4 78 54 8 7.4 2250 2013 1942 18.2 .65 391 91 1.15 1.15 .868 310 1424 640158 Midnight Sun 8050 160 21 540 18 1.68 1.68 4045 4045 3131 27 0.725 94 59 1.3 1.3 0.86 717 5525 Reservoir Engineer 8/25/2020 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION ANNUAL RESERVOIR PROPERTIES REPORT 1. Operator:2. Address: Gavin Dittman I hereby certify that the foregoing is true and correct to the best of my knowledge. Signature Hilcorp North Slope, LLC 3800 Centerpoint Dr, Suite 1400 Anchorage, AK 99503 Printed Name Title Date Form 10-428 Rev. 05/2017 INSTRUCTIONS ON REVERSE SIDE Digitally signed by Gavin Dittman (4007) DN: cn=Gavin Dittman (4007), ou=Users Date: 2020.09.10 12:44:16 -08'00' Gavin Dittman (4007)