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Home My WebLink About2021 Greater Point McIntyre Area GPMA Page 1 ASR for Apr ’21 – Mar ‘22 Prudhoe Bay Unit Lisburne Oil Pool 2022 Annual Reservoir Surveillance Report This Annual Reservoir Report for the period ending March 31, 2022 is submitted to the Alaska Oil and Gas Conservation Commission for the Lisburne Oil Pool in accordance with commission regulations and Conservation Order 207D. This report covers the period from April 1, 2021 through March 31, 2022. A. Reservoir Management 1. Summary Oil production and reservoir management activity in the Lisburne Oil Pool continues under gas cap expansion supported by gas injection at LGI pad and water injection at L5-29. In the Central area, pressure support is supplemented by weak aquifer influx. Pilot seawater injection projects have been on-going in the central Alapah (NK-25), the southern periphery Wahoo (04-350) and the mid- field Wahoo (L5-15) area. Production and injection volumes for the 12-month period ending March 31, 2022 are summarized in Table 1. Oil production volumes include allocated crude oil, condensate and NGL production. 2. Reservoir Pressure Surveys Within the Pool A summary of reservoir pressure surveys obtained during the reporting period is shown in Table 2. The proposed number of Lisburne reservoir pressure surveys to be obtained in the coming plan year April 1 2022 to March 31, 2023 is six total. One apiece at each of the major Lisburne pads (L1, L2, L3, L4 & L5) and one in the Lisburne West Alapah accumulation (well NK-25 or NK-26A). 3. Results and Analysis of Production Logging Surveys There were no production logs obtained from Lisburne wells during the reporting period. B. Development and Production Activity 1. Enhanced Recovery Projects GPMA Page 2 ASR for Apr ’21 – Mar ‘22 a. L5 Gas Cap Water Injection Surveillance (C.O. 207C) The L5 GCWI pilot project commenced injection in July of 2008. The initial injection rate was 2 mbd, and over time has been gradually increased to approximately 17 mbd. As of March 31, 2022, the cumulative volume of seawater injected in L5-29 was 24,420 mbbls. The L5-29 pilot injection demonstrated positive results with likely injection water breakthrough occurring in four offset producer wells (L5-28A, L5-32, L5-33 & L5-36). Pressure response has also been observed in offset wells. The GCWI Pilot was approved for permanent injection under AOGCC Conservation Order 207B.16. The L5-29 injector was shut in for mechanical integrity reasons during the reporting period; however, plans are underway to repair the injector and return it to service. Three pressure fall-off (PFO) tests have been conducted in the L5-29 gas cap water injection well. The PFO analyses show a constant pressure boundary, and skin values of between -3.6 and -3.8. Based on these results, it is inferred that no fracture extension is occurring. Offset well annuli pressures are reported monthly to the Commission by the Hilcorp Well Integrity Engineer via the Monthly Injection Report sent to the AOGCC. b. Waterflooding Pilot Projects A review of the Lisburne development plan identified water injection as a mechanism to provide additional pressure support in the Lisburne reservoirs. A grass roots injection well, 04-350, was completed on the southern periphery of the Wahoo Formation in November 2011 and has injected 9,235 mbbls of seawater as of March 31, 2022. Due to water breakthrough in the L3- 22A producer, the 04-350 injector was shut in in August of 2021 to improve oil rate and recovery in the offset producers. Another pilot water injection project has been undertaken in the mid-field area. Wahoo production wells L5-15 and L5-13 were converted to seawater injection service in March 2013. As of March 31, 2022 the cumulative volume of seawater injected in both these wells was 12,414 mbbls. Confirmed seawater production has occurred in offset L5-16A and L5-17A. L5-13 developed mechanical integrity issues and was plugged and abandoned in November 2017. Due to water breakthrough in offset producers, L5-15 was shut in in August of 2021 to improve oil rate and recovery in the offset producers. In addition, a pilot water injection project into the Alapah Formation has been initiated from the Niakuk Heald Point pad. Alapah producer NK-25 was converted to seawater injection service in March 2013 and has injected 11,846 mbbls of seawater as of March 31, 2022. Offset producer well pressure response and seawater production have been observed. GPMA Page 3 ASR for Apr ’21 – Mar ‘22 2. Well Activity: Drilling Rig No new wells were completed in the Lisburne Formation during the reporting period. 3. Well Activity: Non-Rig The L4 Drill Site was reinstated in late March 2021, bringing online production that had been shut in since 2014. Rate-adding non-rig interventions were also performed during the reporting period. These rate-adding interventions included perforations, hydrate & paraffin removal, hot oil treatment (HOT) jobs, acid stimulations, gas-lift work, profile modifications, fill cleanouts, well integrity repairs, SSSV replacements, continuous methanol injection for hydrate mitigation, and surface component repairs. 4. Other Activity a. Plant and Pipelines Various scheduled minor plant and pipeline repairs and modifications were completed to protect or enhance production from the Lisburne during the reporting period. b. Support Facilities Lisburne shares North Slope infrastructure with the Point McIntyre and Niakuk Fields. Nine wells from the IPA can produce to the LPC as part of the L2 Re-route Project: L2-03A, L2-07A, L2- 08A, L2-11, L2-13A, L2-14C, L2-18A, L2-21B and L2-29A. c. Production Allocation The production of oil and gas, including those hydrocarbon liquids reported as NGLs, is allocated to the Lisburne Participating Area in accordance with conditions approved by the Alaska Department of Natural Resources, Alaska Department of Revenue, and Alaska Oil and Gas Conservation Commission. There is a test separator at each Lisburne Drill Site. 5. Future Development Plans (C.O. 207) Lisburne Pool oil is predominantly processed at the Lisburne Production Center, which began permanent operation in December 1986. There are currently 84 development wells in the Lisburne Oil Pool. Future development plans are discussed in the 2022 Lisburne Plan of Development filed GPMA Page 4 ASR for Apr ’21 – Mar ‘22 with the Division of Oil and Gas of the Alaska Department of Natural Resources, which the Commission received. The Commission will be copied when the 2022 update of the Lisburne Plan of Development is filed with the Division. GPMA Page 5 ASR for Apr ’21 – Mar ‘22 Tables & Figures Oil + NGL Gas Water Oil + NGL Gas Water Monthly Cum Monthly Cum Date mstbo mmscf mbw mstbo mmscf mbw mmscf bscf mbw mbw 4/1/2021 362.626 6,041 430 206,270 2,360,246 80,644 4,439 2,262,407 457 66,065 5/1/2021 373.876 6,073 513 206,644 2,366,320 81,157 4,538 2,266,945 468 66,533 6/1/2021 323.614 5,555 398 206,967 2,371,875 81,555 2,927 2,269,872 183 66,716 7/1/2021 304.121 5,740 348 207,271 2,377,615 81,903 2,488 2,272,360 427 67,143 8/1/2021 335.618 6,142 419 207,607 2,383,757 82,322 2,914 2,275,274 165 67,308 9/1/2021 310.783 6,341 382 207,918 2,390,097 82,703 3,577 2,278,851 32 67,339 10/1/2021 318.248 6,476 245 208,236 2,396,573 82,948 4,206 2,283,057 0 67,339 11/1/2021 363.403 6,980 287 208,599 2,403,553 83,235 4,401 2,287,458 0 67,339 12/1/2021 335.184 7,038 353 208,934 2,410,592 83,588 4,487 2,291,945 153 67,492 1/1/2022 332.559 6,572 310 209,267 2,417,164 83,898 4,676 2,296,621 195 67,687 2/1/2022 298.922 5,869 298 209,566 2,423,032 84,196 3,768 2,300,390 168 67,855 3/1/2022 326.499 6,368 404 209,892 2,429,400 84,600 3,909 2,304,298 180 68,036 Table 1 - Lisburne Monthly Production & Injection Volumes Monthly Production Cumulative Production Gas Injection Water Injection Table 2 - Lisburne Pressure data April 1, 2021 to March 31, 2022 Well Name Survey Date Pressure (psi) (Datum = 8900' SS) L3-03 9/12/2021 2,794 GPMA Page 6 ASR for Apr ’21 – Mar ‘22 Prudhoe Bay Unit Niakuk Oil Pool 2022 Annual Reservoir Surveillance Report This Annual Reservoir Surveillance Report is submitted to the Alaska Oil and Gas Conservation Commission for the Niakuk Oil Pool in accordance with commission regulations and Conservation Order No. 329A. This report covers the period from April 1, 2021 through March 31, 2022. A. Reservoir Management 1. Summary Oil production and reservoir management activity in the Niakuk Oil Pool continues under waterflood. Reservoir management activity in the Niakuk Oil Pool includes: 1) selective perforating and profile modifications to manage conformance of the waterflood, 2) production and injection profile logging to determine current production and injection zones for potential profile modifications, material balance calculations, and effective full field modeling, 3) pressure surveys to monitor flood performance and 4) analysis of production, Gas Oil Ratio, and Water Oil Ratio trends to highlight poorer performing wells for possible intervention activity. Production and injection volumes and resultant voidage data by month for the 12-month period ending March 31, 2021 are summarized in Tables 1 and 2. 2. Reservoir Pressure Surveys Within the Pool A summary of reservoir pressure surveys obtained during the reporting period is shown in Table 3. The proposed number of Niakuk reservoir pressure surveys to be obtained in the coming plan year April 1, 2022 to March 31, 2023 is three total. One survey apiece in each of the major Niakuk reservoir sector delineations (Segments 1, 2/4 and 3/5) 3. Results of Production Logging, Tracer and Well Surveys (C.O. 329A Rule 9d) No production logs were run during the reporting period. No tracer surveys were performed during this reporting period. GPMA Page 7 ASR for Apr ’21 – Mar ‘22 B. Development and Production Activity 1. Enhanced Recovery Projects a. Progress of Niakuk Waterflood Project Implementation and Reservoir Management Summary (C.O. 329A Rule 9a) The Niakuk waterflood was started in April 1995, in conjunction with the commissioning of permanent facilities at Heald Point, using water from the Initial Participating Area Seawater Treatment Plant. Produced water from the Lisburne Production Center was used between August of 2000 and May 2004. Conversion to seawater injection was completed in September 2004, and seawater injection continues throughout this reporting period. All producing segments (1, 2/4 and 3/5) are receiving pressure support from water injection. There were 4 active injectors in the Niakuk Pool with an average total injection rate of approximately 9,100 bwpd for the reporting period. The current injection strategy is to maintain balanced voidage replacement in each segment, however current voidage is slightly less than 1.0. The producer to injector interactions are being evaluated with decreased injection to monitor production impacts in order to better evaluate depletion options. Injector NK-10 was shut in May of 2021 due to mechanical integrity issues. Work is underway to repair this injector and return it to service in 2022. Injector NK-28i has been shut in since 2015. Work is underway to repair this injector and return it to service in 2022. b. Voidage Balance of Produced and Injected Fluids (C.O. 329A Rule 9b) Tables 1 and 2 detail hydrocarbon production, water injection and resultant voidage data by month for the reporting period. c. Analysis of Reservoir Pressure Surveys Within the Pool (C.O. 329A Rule 9c) Table 3 shows results from the reservoir pressure surveys taken during the reporting period. The pressures in Segments 2/4, 1, and 3/ 5 are generally managed with the original reservoir pressure of approximately 4500 psi as a target/maximum, and the bubble point pressure of 4200 psi as a minimum. GPMA Page 8 ASR for Apr ’21 – Mar ‘22 2. Special Monitoring: NK-43 Well (C.O. 329A Rule 9e) NK-43 is a commingled producer which produces from both the Kuparuk and Sag River reservoirs. The AOGCC approved co-mingled production in NK-43 with production allocated to each reservoir via geochemical analysis in Conservation Order 329B on December 7, 2006. Samples were taken from NK-43 during the reporting period for geochemical analysis to confirm production allocation splits between the Sag River and Kuparuk reservoirs. The analyses showed that ~100% of oil production in NK-43 is from the Kuparuk during the reporting period. 3. Well Activity: Permanent production facilities at Niakuk were commissioned in March 1995. There have been 29 development wells drilled into the Niakuk Oil Pool through the end of the reporting period. During the reporting period, the Niakuk field focused on optimization of producers and scale management to which inhibition treatments were performed. Rate-adding non-rig interventions were performed during the reporting period. These rate-adding interventions included perforations, hot oil treatment (HOT) jobs, gas-lift work, SSSV replacements and surface component repairs. 4. Future Development Plans (C.O. 329A Rule 9f) Future development plans are discussed in the 2020 Niakuk Plan of Development filed with the Division of Oil and Gas of the Alaska Department of Natural Resources, which the commission received. The commission will be copied when the 2021 update of the Niakuk Plan of Development is filed with the Division. GPMA Page 9 ASR for Apr ’21 – Mar ‘22 5. Review of Pool Production Allocation Factors (per Administrative Approval Docket Number: CO-15- 013 Done January 7, 2016) LPC monthly average oil allocation factors are supplied below. The Niakuk Oil Pool and Raven Oil Pool will have the same allocation factors as LPC. Any dates with zero allocation factor were excluded. Allocation factors range from 0.93-1.02. Daily allocation data and daily test data are being retained. Month Year LPC Allocation Factor April 2021 0.93 May 2021 0.93 June 2021 0.98 July 2021 0.94 August 2021 0.95 September 2021 0.93 October 2021 0.94 November 2021 1.02 December 2021 0.97 January 2022 0.96 February 2022 0.95 March 2022 0.95 GPMA Page 10 ASR for Apr ’21 – Mar ‘22 Tables and Figures Gas Inject Water Inject MI Inject Oil Gas Water Monthly Monthly Monthly Oil Gas Date mstbo mmscf mbw mmscf mbw mmscf mstb mstb 4/1/2021 24 5 236 0 348 0 96,424 88,217 5/1/2021 24 9 226 0 317 0 96,448 88,226 6/1/2021 20 15 237 0 125 0 96,468 88,240 7/1/2021 23 20 192 0 354 0 96,491 88,260 8/1/2021 27 19 259 0 230 0 96,518 88,279 9/1/2021 55 35 344 0 58 0 96,573 88,315 10/1/2021 57 40 251 0 0 0 96,630 88,354 11/1/2021 29 24 258 0 0 0 96,659 88,379 12/1/2021 29 14 379 0 272 0 96,688 88,393 1/1/2022 25 8 309 0 387 0 96,713 88,401 2/1/2022 26 7 296 0 366 0 96,739 88,408 3/1/2022 30 12 342 0 412 0 96,769 88,420 Table 1 - Niakuk Monthly Production & Injection Volumes CumulativeMonthly Production Gas Inject Water Inject MI Inject Net Res. Oil Gas Water Monthly Monthly Monthly Voidage Date mrvb mrvb mrvb mrvb mrvb mrvb mvrb 4/1/2021 31 -8 238 0 351 0 -90 5/1/2021 31 -5 228 0 320 0 -66 6/1/2021 26 0 239 0 127 0 139 7/1/2021 30 3 194 0 357 0 -130 8/1/2021 34 1 262 0 233 0 64 9/1/2021 71 -2 347 0 59 0 358 10/1/2021 75 0 254 0 0 0 329 11/1/2021 38 3 260 0 0 0 301 12/1/2021 37 -4 383 0 274 0 142 1/1/2022 33 -6 312 0 391 0 -51 2/1/2022 33 -7 299 0 369 0 -44 3/1/2022 39 -6 345 0 416 0 -37 Table 2 - Niakuk Monthly Voidage Balance Monthly Production Note: Monthly Production/Injection/Voidage/Pressure data (Tables 1 & 2) do not include the injection/production results from NK-08B, NK-14B, NK-15A, NK-38B, or NK-65A wells (Raven). They are subject to a separate Raven Oil Pool Annual Reservoir Report. GPMA Page 11 ASR for Apr ’21 – Mar ‘22 Table 3 – 2021-2022 Pressure Survey Data Table 3 - Niakuk Pressure data April 1, 2021 to March 31, 2022 Well Name Survey Date Pressure (psi) (Datum = 9200' SS) NK-10 10/1/2021 4,225 GPMA Page 12 ASR for Apr ’21 – Mar ‘22 Prudhoe Bay Unit Pt. McIntyre Oil Pool 2022 Annual Reservoir Surveillance Report This Annual Reservoir Report for the period ending March 31, 2022 is submitted to the Alaska Oil and Gas Conservation Commission for the Pt. McIntyre Oil Pool in accordance with Commission regulations and Conservation Order 317B. This report covers the period between April 1, 2021 and March 31, 2022. A. Reservoir Management 4. Summary Production and injection volumes for the 12-month period ending March 31, 2022 are summarized in Table 1. Current well locations are shown in Figure 1. The dominant oil recovery mechanisms in the Pt. McIntyre Oil Pool are waterflooding and miscible gas injection in the down-structure area north of the Terrace Fault and gravity drainage in the up- structure area referred to as the Gravity Drainage (GD) Area. Gas injection commenced in the gas cap with field startup to replace voidage and promote gravity drainage. The waterflood was in continuous operation during the reporting period with 16 wells on either water injection or miscible gas injection, supporting 15 patterns (one pattern has two injectors). 5. Progress of Enhanced Recovery Project Implementation and Reservoir Management Summary (Rule 15 a) During the 12 month period from April 2021 – March 2022, a total of 21.1 BCF of MI (miscible injectant) was injected into Point McIntyre patterns. 6. Voidage Balance by Month of Produced and Injected Fluids (Rule 15 b) Monthly production and injection surface volumes are summarized in Table 1. A voidage balance of produced fluids and injected fluids for the report period is shown in Table 2. As summarized in these analyses, monthly voidage is targeted to be balanced with injection. Negative net reservoir voidage values in Table 2 indicate Injection Withdrawal Ratios greater than 1. GPMA Page 13 ASR for Apr ’21 – Mar ‘22 7. Analysis of Reservoir Pressure Surveys within the Pool (Rule 15 c) Reservoir pressure monitoring is performed in accordance with Rule 12 of Conservation Order 317B. A summary of reservoir pressure surveys obtained during the reporting period is shown in Table 3. Nine pressure surveys were obtained during the reporting period. The proposed number of Pt McIntyre reservoir pressure surveys to be obtained in the coming plan year April 1 2022 to March 31, 2023 is three total. Two reservoir pressure surveys are proposed for the waterflood/MI pattern dominated parts of the field and one pressure surveys is proposed for the Gravity Drainage / Gravity Drainage Water Flood Interaction (GD/GDWFI) dominated part of the field. 8. Results and Analysis of Production & Injection Logging Surveys (Rule 15 d) Production profile logs were run on multiple wells in the GDWFI dominated area of the field to ascertain the oil, water, and gas entry points to identify additional development opportunities. These production profile logs were run in P1-04, P1-06, P1-07A, and P1-17. The information collected from these wells showed a consistent trend of gas entry depths associated with gas cap expansion. The information also informed the decision to sidetrack the P1-06 producer to target the remaining oil column in the GDWFI dominated area of the field. 9. Results of Any Special Monitoring (Rule 15 e) No special monitoring was performed during the reporting period. B. Development and Production Activity 1. Well Activity There are a total of 26 well penetrations drilled from DS-PM1 including sidetracked, P&A and suspended wells. There are a total of 76 well penetrations drilled from DS-PM2. An additional water/MI injector (P1-25) is located at the West Dock staging area. During the reporting period, the scale management program continued for Pt Mac wells and included regular scale inhibition treatments. No new Pt Mac wells were put on MI for the first time. GPMA Page 14 ASR for Apr ’21 – Mar ‘22 2. Other Activities d. Pipelines i. The P-15004 produced water injection booster pump was reinstated in February of 2021 to improve water injection rates at Point McIntyre. ii. Figure 2 shows the existing pipeline configuration together with the miscible injectant distribution pipelines from LPC and CGF to the Pt. McIntyre drill sites. iii. Pt. McIntyre production is processed at LPC and GC-1. PM1 wells can only flow to the LPC. Between March of 2004 and November 2011 all wells at drill site PM2 could be flowed to either the LPC (high pressure system) or to GC-1 (low pressure system) via a 36” three phase line from PM2 to GC-1. As a result of this connection, wellhead pressures were lowered for the PM2 wells flowing to GC-1 by approximately 400 psi and utilized approximately 80 MB/D of available water handling capacity at GC-1. On November 12th 2011, the 36” line from PM2 to GC-1 was shut-in due to the integrity status of the line. Repair of the pipeline was completed October 2016, and all PM2 production now flows to GC-1, no production from PM2 flows to LPC. With reduced backpressure, increased water and gas handling capacity at GC1, and optimization of the well sorts, production from PM2 has been increased. iv. In May of 2021 the production common line was successfully upsized at PM2 to improve offtake rates from the Point McIntyre field. e. Produced Water During the 12-month reporting period, the LPC continued to provide produced water for injection at Point McIntyre. Additional produced water is provided from FS1 to LPC for injection at Pt. McIntyre. f. Support Facilities Pt. McIntyre will continue to share North Slope infrastructure with the Lisburne Participating Area ("LPA") and the Initial Participating Areas to minimize duplication of facilities. GPMA Page 15 ASR for Apr ’21 – Mar ‘22 3. Future Development Plans (rule 15 f) Permanent production facilities at Pt. McIntyre were commissioned in 1993. There have been 97 development wells drilled into the Pt. McIntyre Oil Pool through the end of the reporting period. Future development plans are discussed in the 2022 Pt. McIntyre Plan of Development filed with the Division of Oil and Gas of the Alaska Department of Natural Resources, which the Commission. The Commission will be copied when the 2022 update of the Pt. McIntyre Plan of Development is filed with the division. GPMA Page 16 ASR for Apr ’21 – Mar ‘22 Tables and Figures Gas Inject Water Inject MI Inject Oil Gas Water Monthly Monthly Monthly Oil Gas Date mstbo mmscf mbw mmscf mbw mmscf mstb mstb 4/1/2021 454 4,896 4,141 4,902 4,942 1588.25 485,833 1,641,897 5/1/2021 353 4,051 2,909 4,939 5,381 1569.725 486,186 1,645,948 6/1/2021 499 5,094 4,448 4,501 4,965 1497.086 486,685 1,651,041 7/1/2021 520 5,254 4,929 4,881 3,877 1900.119 487,205 1,656,295 8/1/2021 478 5,326 4,960 5,995 3,542 2451.588 487,683 1,661,621 9/1/2021 468 4,739 4,748 4,688 4,708 1772.949 488,150 1,666,360 10/1/2021 497 6,252 4,701 4,845 4,395 1884.677 488,647 1,672,612 11/1/2021 430 5,134 4,150 4,830 4,683 1681.153 489,077 1,677,746 12/1/2021 442 5,490 4,988 4,818 4,593 1559.765 489,519 1,683,236 1/1/2022 426 5,748 4,790 5,060 4,952 1902.173 489,945 1,688,984 2/1/2022 381 5,139 4,319 5,051 4,617 1551.721 490,326 1,694,123 3/1/2022 419 5,221 4,625 5,549 5,094 1691.543 490,745 1,699,345 Table 1 - Pt McIntyre Monthly Production & Injection Volumes Monthly Production Cumulative Gas Inject Water Inject MI Inject Net Res. Oil Gas Water Monthly Monthly Monthly Voidage Date mrvb mrvb mrvb mrvb mrvb mrvb mvrb 4/1/2021 632 3,105 4,203 3,345 5,016 984.715 -1,405 5/1/2021 492 2,581 2,952 3,370 5,461 973.2295 -3,780 6/1/2021 694 3,217 4,515 3,071 5,040 928.19332 -613 7/1/2021 723 3,315 5,003 3,330 3,935 1178.07378 599 8/1/2021 664 3,386 5,034 4,090 3,595 1519.98456 -121 9/1/2021 650 2,991 4,819 3,199 4,779 1099.22838 -616 10/1/2021 691 4,008 4,772 3,306 4,461 1168.49974 536 11/1/2021 598 3,280 4,212 3,296 4,753 1042.31486 -1,001 12/1/2021 614 3,517 5,063 3,288 4,662 967.0543 278 1/1/2022 593 3,701 4,862 3,453 5,026 1179.34726 -502 2/1/2022 530 3,309 4,384 3,446 4,686 962.06702 -871 3/1/2022 583 3,345 4,694 3,786 5,170 1048.75666 -1,383 Table 2 - Pt McIntyre Monthly Voidage Balance Monthly Production GPMA Page 17 ASR for Apr ’21 – Mar ‘22 Table 3 – Point McInytre Pressure data April 1, 2021 to March 31, 2022 Well Name Survey Date Pressure (psi) (Datum = 8,800' SS) P1-04 10/1/2021 3,784 P1-08A 7/1/2021 3,809 P1-17 7/2/2021 3,799 P1-23 7/3/2021 3,795 P2-19A 5/30/2021 3,988 P2-20 5/30/2021 3,921 P2-37A 5/19/2021 4,009 P2-51A 5/22/2021 3,595 P2-54A 5/20/2021 3,779 GPMA Page 18 ASR for Apr ’21 – Mar ‘22 Figure 1 Pt. McIntyre Well Location Map Unit Boundary GPMA Page 19 ASR for Apr ’21 – Mar ‘22 PM2 Approximate Scale 0 1Miles Prudhoe Bay Existing Pipelines Pipelines for EOR PM1 LG1 L1 CCP CGF L2 L3 L5 NK L4 LPC Figure 2. Drill Site and Pipeline Configuration GC1* * GC1 location not to scale Figure 3 GPMA Page 20 ASR for Apr ’21 – Mar ‘22 Prudhoe Bay Unit Raven Oil Pool and Sag River Undefined Oil Pool 2022 Annual Reservoir Surveillance Report This Annual Reservoir Report for the period ending March 31, 2022 is submitted to the Alaska Oil and Gas Conservation Commission for the Raven Oil Pool in accordance with Commission regulations and Conservation Order 570. Data for the Sag River Undefined Oil Pool is included here as the Raven Oil Pool will eventually be expanded to encompass the Sag River Undefined Oil Pool once pool limits are defined. This report covers the period between April 1, 2021 and March 31, 2022. A. Reservoir Management 1. Summary Raven is a small oil and gas field in the Permo-Triassic interval (Ivishak and Sag River) located beneath the Niakuk Field (Kuparuk reservoir). Production from the Raven Field started in March 2001 with the completion of the Sag River in NK- 43. The Sag River in NK-43 was subsequently isolated with a cast iron bridge plug (CIBP), and the well was perforated in the Kuparuk reservoir and produced until 1/2/06 when the CIBP was removed and the Sag River commingled with the Kuparuk. Production from NK-38A began in March 2005 from the Ivishak reservoir. NK-38A was sidetracked and NK-38B began production September 2016 from the optimized location. NK-14B was spudded in March 2017 and is an extension well delineating the outer boundaries of the Raven Oil Pool. The well came on production from the Sag River formation in late June, 2017 and by the middle of August had what later was determined to be a production casing leak. The well was shut-in from September, 2017 – March, 2018 to determine failure and repair options. NK-14B has since been restored to production. NK-15A was drilled and completed in March, 2018 in a position on the structure that was believed to be better situated to support and waterflood the structure for the NK-38B offtake. However, the Ivishak reservoir encountered by NK-15A was found to be wet and low permeability. In December of 2020 the Sag River formation was perforated in the NK-15A well as rich gas potential was identified and it was determined that no further utility in the Ivishak existed. After perforating, NK- 15A came online at over 1,500 BOPD. NK-08B was drilled and completed in April 2019 into an un-swept part of the Sag River formation within the Raven reservoir. The well came on production in May 2019 has been a full-time producer since that time. GPMA Page 21 ASR for Apr ’21 – Mar ‘22 As NK-38B seems to exhibit aquifer support based on pressure and water analysis, NK-65A injection had been decreased to a VRR less than 1, and in May of 2020 the well was shut in for a well line repair. During this shut-in period it was determined that the support from NK-65A was not needed as the NK-15A confirmed that the Ivishak had already been swept in the fault block that NK-38B produced from. An evaluation was completed to assess the potential for NK-65A to be converted to a rich gas producer, similar to NK-15A, to maximize rate and recovery from the North and Central Raven fault blocks. Upon completion of the evaluation it was determined additional recoverable hydrocarbons could be captured from both the Sag and Ivishak rich gas. In December of 2021 the NK-65A was converted to production service and has produced a cumulative 150 MSTBO to-date from the Ivishak rich gas. The long-term depletion plan is to optimize hydrocarbon production in the Raven reservoir through voidage replacement from water injection as a supplement to aquifer influx in order to keep reservoir pressure at levels that will optimize oil recovery as well as develop up the rich gas potential that has been proven with the NK-15A. The Raven Pool voidage replacement ratio for the reporting period is deliberately less than 1.0 due the known aquifer influx influence. NK-14B production is included in voidage calculations, however as there is no connectivity with NK-65A injection rates are not managed to support NK-14B offtake. NK-14B will continue to be monitored and continued information analysis will allow for optimization of long-term depletion plans for the Sag River. 2. Analysis of Reservoir Pressure Surveys Within the Pool Static pressure surveys have been conducted on the wells in the field. Table 3 shows results of static reservoir pressure surveys conducted on the wells since March 2005. The most recent static reservoir pressure in NK-38B was taken in February 2021 and reservoir pressure was 4,252 psi (datum). No additional static reservoir pressures were acquired during the reporting period. The proposed number of Raven reservoir pressure surveys to be obtained in the coming plan year April 1, 2022 to March 31, 2023 is two total. Hilcorp requests flexibility with specifying the two separate wells that will be surveyed while noting that Raven has a low well count. 3. Results of Production Logging, Tracer and Well Surveys No production logs were run during the reporting period. No tracer surveys were performed during the reporting period. GPMA Page 22 ASR for Apr ’21 – Mar ‘22 B. Development and Production Activity 1. Progress of Enhanced Recovery Project Implementation and Reservoir Management Summary Waterflood at Raven began in October 2005, using water from the Initial Participating Area Seawater Treatment facilities. NK-65A was converted to a rich gas producer, similar to NK-15A, to maximize recovery at Raven. Future development drilling to provide injection support to NK-08B and NK-14B is also currently be evaluated. 2. Voidage Balance of Produced and Injected Fluids Tables 1 and 2 detail the production, injection and calculated voidage by month for the reporting period. 3. Special Monitoring: NK-43 Well (C.O. 329A Rule 9e) NK-43 is a commingled producer which produces from both the Kuparuk and Sag River reservoirs. The AOGCC approved co-mingled production in NK-43 with production allocated to each reservoir via geochemical analysis in Conservation Order 329B on December 7, 2006. Samples were taken from NK-43 on November 2nd, 2021, for geochemical analysis to confirm production allocation splits between the Sag River and Kuparuk reservoirs. This analysis showed that ~100% of oil production in NK-43 is from the Kuparuk during the reporting period. 4. Future Development Plans (C.O. 570) Permanent production facilities that Raven utilizes were commissioned in March 1995. There have been 5 development wells drilled into the Raven Oil Pool through the end of the reporting period. Future development plans are discussed in the 2020 Raven Plan of Development filed with the Division of Oil and Gas of the Alaska Department of Natural Resources, which the Commission received. The Commission will be copied when the 2022 update of the Raven Plan of Development is filed with the division. GPMA Page 23 ASR for Apr ’21 – Mar ‘22 5. Review of Pool Production Allocation Factors (per Administrative Approval Docket Number: CO-15- 013 Done January 7, 2016) LPC monthly average oil allocation factors are supplied below. The Niakuk Oil Pool and Raven Oil Pool will have the same allocation factors as LPC. Any dates with zero allocation factor were excluded. Allocation factors range from 0.93-1.02. Daily allocation data and daily test data are being retained. Month Year LPC Allocation Factor April 2021 0.93 May 2021 0.93 June 2021 0.98 July 2021 0.94 August 2021 0.95 September 2021 0.93 October 2021 0.94 November 2021 1.02 December 2021 0.97 January 2022 0.96 February 2022 0.95 March 2022 0.95 GPMA Page 24 ASR for Apr ’21 – Mar ‘22 Tables and Figures Gas Inject Water Inject MI Inject Oil + NGL Gas Water Monthly Monthly Monthly Oil Gas Date mstbo mmscf mbw mmscf mbw mmscf mstb mstb 4/1/2021 56 561 174 0 0 0 5,272 27,887 5/1/2021 60 580 182 0 0 0 5,325 28,467 6/1/2021 55 582 143 0 0 0 5,373 29,049 7/1/2021 40 470 107 0 0 0 5,411 29,519 8/1/2021 51 505 146 0 0 0 5,456 30,023 9/1/2021 43 475 121 0 0 0 5,494 30,498 10/1/2021 45 468 78 0 0 0 5,533 30,966 11/1/2021 44 453 68 0 0 0 5,571 31,419 12/1/2021 69 919 95 0 0 0 5,632 32,339 1/1/2022 73 1,076 69 0 0 0 5,698 33,415 2/1/2022 47 876 75 0 0 0 5,741 34,291 3/1/2022 52 892 79 0 0 0 5,789 35,183 Table 1 - Raven Monthly Production & Injection Volumes CumulativeMonthly Production Gas Inject Water Inject MI Inject Net Res. Oil Gas Water Monthly Monthly Monthly Voidage Date mrvb mrvb mrvb mrvb mrvb mrvb mvrb 4/1/2021 76 389 176 0 0 0 640 5/1/2021 81 401 184 0 0 0 666 6/1/2021 75 405 144 0 0 0 624 7/1/2021 57 329 108 0 0 0 494 8/1/2021 70 349 147 0 0 0 566 9/1/2021 59 332 122 0 0 0 513 10/1/2021 60 326 79 0 0 0 464 11/1/2021 59 316 69 0 0 0 443 12/1/2021 94 652 96 0 0 0 843 1/1/2022 100 768 69 0 0 0 937 2/1/2022 67 633 76 0 0 0 776 3/1/2022 73 642 79 0 0 0 794 Table 2 - Raven Monthly Voidage Balance Monthly Production Note: Monthly Production/Injection/Voidage for the Ivishak and Sag River. GPMA Page 25 ASR for Apr ’21 – Mar ‘22 Table 3 – Raven & Sag River Undefined Ivishak & Sag Pressure Survey Data Since March 2005 Sw Name Test Date Pres Surv Type Datum Ss Pres Datum NK-38A 3/29/2005 SBHP 9850 4973 NK-38A 8/1/2005 SBHP 9850 4237 NK-38A 8/7/2005 SBHP 9850 4273 NK-65A 8/9/2005 SBHP 9850 4463 NK-65A 8/15/2005 SBHP 9850 4295 NK-38A 12/24/2005 SBHP 9850 4210 NK-65A 5/24/2006 SBHP 9850 4414 NK-38A 7/26/2006 SBHP 9850 4155 NK-65A 7/26/2006 SBHP 9850 4400 NK-38A 1/23/2007 SBHP 9850 4104 NK-38A 7/6/2007 SBHP 9850 3758 NK-65A 8/16/2007 SBHP 9850 4827 NK-38A 8/24/2007 SBHP 9850 4370 NK-38A 10/30/2007 SBHP 9850 4379 NK-38A 6/9/2008 SBHP 9850 3543 NK-65A 8/17/2008 SBHP 9850 4379 NK-38A 9/2/2008 SBHP 9850 3507 NK-38A 4/29/2009 SBHP 9850 3537 NK-38A 5/18/2009 SBHP 9850 3928 NK-65A 8/8/2009 SFO 9850 4525 NK-38A 8/31/2009 SBHP 9850 4165 NK-65A 6/5/2010 SFO 9850 4534 NK-38A 7/6/2010 SBHP 9850 4090 NK-65A 6/4/2011 SBHP 9850 4468 NK-38A 6/6/2011 SBHP 9850 4402 NK-65A 6/27/2012 SFO 9850 4497 NK-38A 7/14/2012 SBHP 9850 3976 NK-65A 7/13/2013 SFO 9850 4429 NK-38A 12/26/2013 SBHP 9850 3549 NK-38A 6/26/2014 SBHP 9850 3564 GPMA Page 26 ASR for Apr ’21 – Mar ‘22 NK-65A 7/13/2014 SFO 9850 4674 NK-43 3/12/2015 SBHP 9850 4057 NK-38A 7/31/2015 SBHP 9850 3386 NK-38A 6/3/2016 SBHP 9850 3061 NK-38B 8/21/2016 SBHP 9850 4412 NK-14B 4/27/2017 MDT -Sag 9850 4608 NK-14B 7/28/2017 SBHP - Sag 9850 3801 NK-14B 11/24/2017 SBHP- Sag 9850 4090 NK-38B 7/21/2017 SBHP 9850 4053 NK-15A 7/2/2018 SBHP 9850 4346 NK-38B 7/17/2018 SBHP 9850 4210 NK-14B 3/31/2019 PBU – Sag 9850 2454 NK-65A 10/19/2018 PBU 9850 4491 NK-08B 4/30/2019 SBHP 9850 4815 NK-38B 9/13/2019 SBHP 9850 4257 NK-38B 2/24/2021 SBHP 9850 4252 GPMA Page 27 ASR for Apr ’21 – Mar ‘22 3. Field and Pool Code:4. Pool Name5. 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)640120Prudhoe Bay, Pt McIntyre Oil Pool880018022.00200.0015.000.90.9437743083876270.72251561.391.390.8380512,445640130Prudhoe Bay, Niakuk Oil Pool920018720.00500.0028.000.941.04444638004016250.723501051.351.330.94660400640135Prudhoe Bay, W Beach Oil Pool880017511.0037.0058.001.081.0842504068360925.70.7191921.361.360.8574123,032640152Prudhoe Bay, N Prudhoe Bay Oil Pool924520620.00265.0040.000.4250.42539253870361032.50.882502201.541.540.9598232,902640158Prudhoe Bay, Raven Oil Pool985020720.00265.0030.000.40.36497349734160320.882502201.871.870.95162119,243640144Prudhoe Bay, Lisburne Oil Pool8900183101300.90.9449043002911270.7210001251.3851.3850.85583024,400STATE OF ALASKAALASKA OIL AND GAS CONSERVATION COMMISSIONANNUAL RESERVOIR PROPERTIES REPORT1. Operator:2. Address:Tommy NenahloI hereby certify that the foregoing is true and correct to the best of my knowledge.Tommy NenahloSignatureHilcorp North Slope, LLC3800 Centerpoint Drive #1400; Anchorage, AK 99503Printed NameTitleDate 6/8/2022 Reservoir Engineer GPMA Page 28 ASR for Apr ’21 – Mar ‘22 6. Oil Gravity: 0.9 SG/27* API8. Well Name and Number:9. API Number 50XXXXXXXXXXXX NO DASHES10. Type See Instructions11. AOGCC Pool Code12. Zone13. Perforated Intervals Top - Bottom TVDSS14. Final Test Date15. Shut-In Time, Hours16. Press. Surv. Type (see instructions for codes)17. B.H. Temp.18. Depth Tool TVDSS19. Final Observed Pressure at Tool Depth20. Datum TVDSS (input)21. Pressure Gradient, psi/ft.22. Pressure at Datum (cal)L3-0350029235350000Oil Producer Shut-In6401448911-8993,9011-8932,9052-9033,8960-8962,9088-9094,9033-9032,9011-8970,8682-8879,9094-9094,8925-8867,8962-8993,9094-9084,9016-9081,9088-9084,9080-9057,9052-9018,8925-8888,8887-8867,9032-9018,8862-8844,8888-8887,8970-8970,8970-8932,8813-8789,8839-8817,8911-8960,9016-9068,9068-9069,9069-90819/12/202111,425SBHP1808,9002,7948900.4296 PSI/FT 2794.09STATE OF ALASKAALASKA OIL AND GAS CONSERVATION COMMISSIONRESERVOIR PRESSURE REPORT1. Operator:2. Address:Hilcorp North Slope3800 Centerpoint Dr, #1400, Anchorage, AKLisburne Field, Lisburne Oil PoolPrinted NameTitleDateReservoir EngineerJune 8, 20228900 TVDss.93. Unit or Lease Name:4. Field and Pool:5. Datum Reference:Tommy Nenahlo23. 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.Tommy NenahloSignature7. Gas Gravity:Prudhoe Bay Unit GPMA Page 29 ASR for Apr ’21 – Mar ‘22 6. Oil Gravity:8. Well Name and Number:9. API Number 50XXXXXXXXXXXX NO DASHES10. Type See Instructions11. AOGCC Pool Code12. Zone13. Perforated Intervals Top - Bottom TVDSS14. Final Test Date15. Shut-In Time, Hours16. Press. Surv. Type (see instructions for codes)17. B.H. Temp.18. Depth Tool TVDSS19. Final Observed Pressure at Tool Depth20. Datum TVDSS (input)21. Pressure Gradient, psi/ft.22. Pressure at Datum (cal)NK-1050029224250000Water Injector Shut-In6401489183-9243,9296-9298,9322-9345,9252-9266,9243-9252,9252-9298,9266-929610/1/2021FL-609200ESTIMATED FROM FLUID SHOT TAKEN 4225Printed NameTommy NenahloDateJune 8, 202223. 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.SignatureTommy NenahloTitleReservoir Engineer3. Unit or Lease Name:4. Field and Pool:5. Datum Reference:7. Gas Gravity:Prudhoe Bay UnitPrudhoe Bay Field, Niakuk Oil Pool 9200 TVDssSTATE OF ALASKAALASKA OIL AND GAS CONSERVATION COMMISSIONRESERVOIR PRESSURE REPORT1. Operator:2. Address:Hilcorp North Slope3800 Centerpoint Dr, #1400, Anchorage, AK GPMA Page 30 ASR for Apr ’21 – Mar ‘22 6. Oil Gravity:8. Well Name and Number:9. API Number 50XXXXXXXXXXXX NO DASHES10. Type See Instructions11. AOGCC Pool Code12. Zone13. Perforated Intervals Top - Bottom TVDSS14. Final Test Date15. Shut-In Time, Hours16. Press. Surv. Type (see instructions for codes)17. B.H. Temp.18. Depth Tool TVDSS19. Final Observed Pressure at Tool Depth20. Datum TVDSS (input)21. Pressure Gradient, psi/ft.22. Pressure at Datum (cal)P1-0450029223660000Oil Producer Flowing6401808906-8980,8872-8875,8872-8889,8795-8837,8855-8859,8859-8872,8927-8941,8826-8837,8752-8769,8837-8855,8918-8927,9016-9091,8855-8872,8803-8826,8795-8889,8941-8976,8976-8980,8998-9016,8998-9091,8906-8941,8875-8889,8714-8730,8795-8855,8906-8918,8795-880310/1/20214SBHP1828,8003,7848800.4321 PSI/FT3783.87P1-08A50029223840100Oil Producer Shut-In6401808769-8768,8764-8762,8770-8770,8771-87707/1/20211,087SBHP1768,6633,7688800.3030 PSI/FT 3809.45P1-1750029223580000Oil Producer Flowing6401808807-8882,8725-8735,8898-9057,8697-8717,8759-87927/2/2021153SBHP1868,8003,7998800.4305 PSI/FT 3799.08P1-2350029226900000Oil Producer Shut-In6401808970-8983,8951-8970,8932-8983,9024-9048,9073-9086,8932-8951,8895-8901,9008-90217/3/202179SBHP1888,8003,7958800.4214 PSI/FT3794.88P2-19A50029227650100Oil Producer Gas Lift6401809040-9051,9056-9068,9053-90415/30/2021320SBHP1838,8003,9888800.4378 PSI/FT3988.1P2-2050029226640000Oil Producer Flowing6401808851-8857,8961-8970,8819-8848,8857-8883,9023-9033,8990-9009,8857-8905,8942-8950,8883-8905,8942-8961,8950-89615/30/2021329SBHP8,8003,9218800.4470 psi/ft3921.14P2-37A50029225760100Oil Producer Shut-In6401809006-9002,9026-9036,9052-9057,9012-90215/19/20215,950SBHP1798,8004,0098800.4309 PSI/FT 4009.04P2-51A50029222620100Oil Producer Gas Lift6401809080-89475/22/2021124SBHP1858,8003,5958800.4308 PSI/FT3595.1P2-54A50029224700100Oil Producer Shut-In6401808844-8841,8848-8844,8885-8900,8839-8844,8852-88615/20/20215,951SBHP1236,0843,4368800.1263 PSI/FT 3778.96Printed NameTommy NenahloDateJune 8, 202223. 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.SignatureTommy NenahloTitleReservoir Engineer3. Unit or Lease Name:4. Field and Pool:5. Datum Reference:7. Gas Gravity:Prudhoe Bay UnitPrudhoe Bay Field, Pt McIntyre Oil Pool 8800 TVDssSTATE OF ALASKAALASKA OIL AND GAS CONSERVATION COMMISSIONRESERVOIR PRESSURE REPORT1. Operator:2. Address:Hilcorp North Slope3800 Centerpoint Dr, #1400, Anchorage, AK GPMA Page 31 ASR for Apr ’21 – Mar ‘22 6. Oil Gravity:8. Well Name and Number:9. API Number 50XXXXXXXXXXXX NO DASHES10. Type See Instructions11. AOGCC Pool Code12. Zone13. Perforated Intervals Top - Bottom TVDSS14. Final Test Date15. Shut-In Time, Hours16. Press. Surv. Type (see instructions for codes)17. B.H. Temp.18. Depth Tool TVDSS19. Final Observed Pressure at Tool Depth20. Datum TVDSS (input)21. Pressure Gradient, psi/ft.22. Pressure at Datum (cal)Printed NameTommy NenahloDateJune 8, 202223. 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.SignatureTommy NenahloTitleReservoir Engineer3. Unit or Lease Name:4. Field and Pool:5. Datum Reference:7. Gas Gravity:Prudhoe Bay UnitPrudhoe Bay Field, Raven Oil Pool 9850 TVDssSTATE OF ALASKAALASKA OIL AND GAS CONSERVATION COMMISSIONRESERVOIR PRESSURE REPORT1. Operator:2. Address:Hilcorp North Slope3800 Centerpoint Dr, #1400, Anchorage, AK GPMA Page 32 ASR for Apr ’21 – Mar ‘22