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Home My WebLink About2022 Greater Point McIntyre Area3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503 Phone: 907/777-8300 hilcorp.com Hilcorp North Slope, LLC June 15, 2023 Brett Huber, Sr., Chair Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, AK 99501 RE: Prudhoe Bay Unit, Greater Point McIntyre (GPMA) Oil Pools Annual Reservoir Surveillance Reports Annual Reservoir Properties Reports April 1, 2022 – March 31, 2023 Chairman Huber, Hilcorp North Slope, LLC, as operator of the Prudhoe Bay Unit, submits the enclosed Annual Reservoir Surveillance Reports for the Greater Point McIntyre (GPMA) Oil Pools in accordance with the latest Conservation Orders for each pool. In addition, Hilcorp North Slope will simultaneously file the Annual Reservoir Properties Reports (ARPs, form 10-428) for the GPMA Oil Pools under this cover and to aogcc.reporting@alaska.gov. The Operators of the Prudhoe Bay Field reserve the right to alter the content of the analyses contained in this report at any time based upon the most recent surveillance information obtained. If you have any questions regarding the reports, please contact Abbie.Barker@hilcorp.com. Thank you, Max Shayer Reservoir Engineer, Prudhoe Bay East Hilcorp North Slope, LLC Cc:Stephanie Erickson, ConocoPhillips Alaska, Inc. Greg Keith, ConocoPhillips Alaska, Inc. Becky Steen, ConocoPhillips Alaska, Inc. Todd Griffith, ExxonMobil Alaska, Production Inc. Jeff Farr, ExxonMobil Alaska, Production Inc. Bo Gao, ExxonMobil Alaska, Production Inc. Gary Selisker, Chevron USA Dave Roby, AOGCC Heather Beat, DNR, Division of Oil & Gas Digitally signed by Max Shayer (3477) DN: cn=Max Shayer (3477) Date: 2023.06.15 16:28:01 - 08'00' Max Shayer (3477) GPMA Page 1 ASR for Apr ’22 –Mar ‘23 Prudhoe Bay Unit Lisburne Oil Pool 2023 Annual Reservoir Surveillance Report This Annual Reservoir Report for the period ending March 31, 2023 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, 2022 through March 31, 2023. 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) and the mid-field Wahoo (L5-15) area. Production and injection volumes for the 12-month period ending March 31, 2023 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, 2023 to March 31, 2024 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 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, 2023, the cumulative volume of seawater injected in L5-29 was 25,386 mbbls. The L5-29 pilot injection demonstrated positive results with likely injection water breakthrough occurring in four offset GPMA Page 2 ASR for Apr ’22 –Mar ‘23 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;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 9,535 mbbls of seawater as of March 31,2023. 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, 2023 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 13,777 mbbls of seawater as of March 31, 2023. Offset producer well pressure response and seawater production have been observed. GPMA Page 3 ASR for Apr ’22 –Mar ‘23 2.Well Activity: Drilling Rig Four coil tubing drilling (CTD)wells were completed in the Lisburne Formation during the reporting period.In order of drilling sequence: 1.L1-01L1 Completed in the Wahoo Formation, downdip from the gas cap, and perforated in Zones 5 & 6. Well was intentionally completed to allow the mother-bore to flow commingled with L1 lateral. 2.L1-13L1 Completed in the Wahoo Formation, downdip from the gas cap, west of L1-01L1, and perforated in Zones 6 & 7. Well was intentionally completed to allow the mother-bore to flow commingled with L1 lateral. 3.L3-18 Completed in the Wahoo Formation, downdip from the gas cap, and perforated in Zone 7. Well was intentionally completed to allow the mother-bore to flow commingled with L1 lateral. 4.L4-03 Completed in the Wahoo Formation, downdip from the gas cap, north of L4 pad, and perforated in Zones 6 & 7. Well was intentionally completed to allow the mother-bore to flow commingled with L1 lateral. 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-sustaining,non-rig interventions were also performed during this reporting period, including hydrate mitigation and gas-lift work. 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, including the LPC Rich Gas to CGF project. 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. GPMA Page 4 ASR for Apr ’22 –Mar ‘23 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 88 development wells in the Lisburne Oil Pool. Future development plans are discussed in the 2022 Lisburne Plan of Development filed with the Division of Oil and Gas of the Alaska Department of Natural Resources.The Commission will be copied when the 2023 update of the Lisburne Plan of Development is filed with the Division. GPMA Page 5 ASR for Apr ’22 –Mar ‘23 Tables & Figures Table 2 –Lisburne Pressure Data April 1, 2022 to March 31, 2023 Well Name Survey Date Pressure (psi) Datum = 8900’ SS 04-350 2/12/2023 3,212 L2-20 3/26/2023 2,673 Oil + NGL Oil NGL Gas Water Oil + NGL Gas Water Monthly Cum Monthly Cum Date mstbo mstbo mstbo mmscf mbw mstbo mmscf mbw mmscf mmscf mbw mbw 4/1/2022 319.313 254.212 65.101 6,535 292 210,212 2,435,935 84,892 3,668 2,307,966 171 68,206 5/1/2022 268.74 224.47 44.27 5,486 262 210,481 2,441,421 85,153 2,756 2,310,723 172 68,379 6/1/2022 310.89 265.276 45.614 6,082 271 210,791 2,447,502 85,424 2,625 2,313,348 154 68,533 7/1/2022 308.16 260.381 47.779 6,493 324 211,100 2,453,995 85,748 2,216 2,315,565 163 68,696 8/1/2022 310.852 264.665 46.187 6,099 369 211,410 2,460,094 86,117 1,882 2,317,447 108 68,804 9/1/2022 291.712 245.279 46.433 5,733 393 211,702 2,465,827 86,509 2,165 2,319,612 150 68,954 10/1/2022 314.477 257.443 57.034 6,817 504 212,017 2,472,644 87,013 3,114 2,322,726 178 69,133 11/1/2022 335.581 271.955 63.626 7,276 331 212,352 2,479,921 87,345 3,582 2,326,309 181 69,314 12/1/2022 350.34 285.397 64.943 9,185 350 212,703 2,489,106 87,695 3,286 2,329,595 173 69,486 1/1/2023 388.139 314.222 73.917 7,500 436 213,091 2,496,606 88,131 3,125 2,332,720 159 69,645 2/1/2023 330.07 274.164 55.906 6,387 424 213,421 2,502,993 88,555 2,572 2,335,292 149 69,794 3/1/2023 385.896 316.547 69.349 7,481 453 213,807 2,510,474 89,007 2,849 2,338,142 173 69,967 Monthly Production Table 1 - Lisburne Monthly Production & Injection Volumes Cumulative Production Gas Injection Water Injection GPMA Page 6 ASR for Apr ’22 –Mar ‘23 Prudhoe Bay Unit Niakuk Oil Pool 2023 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, 2022 through March 31, 2023. 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, 2023 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.No pressure surveys were obtained in the Niakuk Oil Pool in the reporting period. The proposed number of Niakuk reservoir pressure surveys to be obtained in the coming plan year April 1, 2023 to March 31, 2024 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 ’22 –Mar ‘23 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 2 active injectors in the Niakuk Pool with an average total injection rate of approximately 12,500 bwpd for the reporting period. The current injection strategy is to maintain roughly balanced voidage replacement in each segment. Since the end of the reporting period, long-term shut-in injector NK-23 has been restored to injection to provide additional support to the western portion of the field. 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.No pressure surveys were obtained in the Niakuk Oil Pool in 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 ’22 –Mar ‘23 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.NK-43 is currently shut in and future geochemical analysis for production allocation will be performed when the well is returned to production. 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 2022 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 2023 update of the Niakuk Plan of Development is filed with the Division. GPMA Page 9 ASR for Apr ’22 –Mar ‘23 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 0.96-1.05. Daily allocation data and daily test data are being retained. Month Year LPC Allocation Factor April 2022 0.97 May 2022 0.98 June 2022 1.05 July 2022 1.01 August 2022 1.02 September 2022 1.00 October 2022 0.96 November 2022 0.98 December 2022 1.01 January 2023 0.98 February 2023 1.00 March 2023 1.00 GPMA Page 10 ASR for Apr ’22 –Mar ‘23 Tables and Figures 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. Gas Inject Water Inject MI Inject Oil NGL Gas Water Monthly Monthly Monthly Oil Gas Date mstbo mstbo mmscf mbw mmscf mbw mmscf mstb mstb 4/1/2022 27 0.166 6 238 0 390 0 96,797 88,427 5/1/2022 24 0.28 14 220 0 395 0 96,820 88,441 6/1/2022 39 0.818 48 409 0 397 0 96,860 88,489 7/1/2022 36 0.651 36 498 0 442 0 96,896 88,525 8/1/2022 38 1.145 64 650 0 263 0 96,933 88,588 9/1/2022 32 0.823 42 623 0 372 0 96,965 88,631 10/1/2022 28 0.56 27 475 0 406 0 96,994 88,658 11/1/2022 39 0.864 42 352 0 403 0 97,033 88,700 12/1/2022 37 0.704 41 472 0 400 0 97,069 88,741 1/1/2023 30 0.945 42 451 0 366 0 97,099 88,783 2/1/2023 28 0.724 36 494 0 341 0 97,128 88,819 3/1/2023 31 0.753 40 502 0 406 0 97,159 88,858 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 4/1/2022 36 -8 240 0 394 0 -127 5/1/2022 31 -2 222 0 398 0 -147 6/1/2022 51 14 413 0 401 0 77 7/1/2022 46 8 503 0 447 0 110 8/1/2022 49 25 657 0 265 0 466 9/1/2022 42 14 629 0 376 0 309 10/1/2022 37 5 480 0 410 0 112 11/1/2022 51 10 355 0 407 0 9 12/1/2022 48 11 477 0 404 0 132 1/1/2023 39 14 455 0 370 0 139 2/1/2023 37 11 498 0 344 0 202 3/1/2023 40 12 507 0 410 0 150 Table 2 - Niakuk Monthly Voidage Balance Monthly Production GPMA Page 11 ASR for Apr ’22 –Mar ‘23 Table 3 –2022-2023 Pressure Survey Data Table 3 -Niakuk Pressure data April 1, 2022 to March 31, 2023 Well Name Survey Date Pressure (psi) (Datum = 9200' SS) No pressure surveys obtained in Niakuk Oil Pool for the period. GPMA Page 12 ASR for Apr ’22 –Mar ‘23 Prudhoe Bay Unit Pt.McIntyre Oil Pool 2023 Annual Reservoir Surveillance Report This Annual Reservoir Report for the period ending March 31, 2023 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, 2022 and March 31, 2023. A.Reservoir Management 1.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 water injection and/or miscible gas injection, supporting 14 patterns (two patterns have two injectors). The P1-16 injector was offline for the period for integrity and a plan is being worked to restore it to operability. 2.Progress of Enhanced Recovery Project Implementation and Reservoir Management Summary (Rule 15 a) During the 12 month period from April 2022 –March 2023, a total of 23.3 BCF of MI (miscible injectant) was injected into Point McIntyre patterns. 3.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 ’22 –Mar ‘23 4.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. No pressure surveys were obtained during the reporting period after nine were obtained in the prior period (not including one pressure survey obtained in P1-09, which is completed in the Sag River Undefined Oil Pool).One pressure survey has been obtained (in P1-13) so far in 2023 (in May). The proposed number of Pt McIntyre reservoir pressure surveys to be obtained in the coming plan year April 1,2023 to March 31, 2024 is three total. Two reservoir pressure surveys are proposed for the waterflood/MI pattern dominated parts of the field and one pressure survey is proposed for the Gravity Drainage / Gravity Drainage Water Flood Interaction (GD/GDWFI) dominated part of the field. 5.Results and Analysis of Production & Injection Logging Surveys (Rule 15 d) No production profiles were obtained in the Point McIntyre Oil Pool in the reporting period. 6.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. Three sidetracks and add-laterals were drilled in the reporting period targeting unswept or stranded oil in the Pt. McIntyre Oil Pool utilizing idle or underperforming wells. P1-06A sidetrack targeted unswept oil in the GDWFI area of the field beneath the expanded gas cap. P1-20L1 and P1-23L1 targeted stranded oil on the western periphery of the field on the flanks of the existing waterflood patterns. All three wells were successful in increasing oil production rate. 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 ’22 –Mar ‘23 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. 3.Future Development Plans (rule 15 f) Permanent production facilities at Pt. McIntyre were commissioned in 1993. There have been 98 development wells including sidetracks 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. The Commission will be copied when the 2023 update of the Pt. McIntyre Plan of Development is filed with the division. GPMA Page 15 ASR for Apr ’22 –Mar ‘23 Tables and Figures Gas Inject Water Inject MI Inject Oil NGL Gas Water Monthly Monthly Monthly Oil Gas Date mstbo mstbo mmscf mbw mmscf mbw mmscf mstb mstb 4/1/2022 390 39.931 4,318 4,220 5,899 4,785 2112.592 491,135 1,703,662 5/1/2022 445 41.95 5,626 4,839 5,495 4,644 2000.556 491,580 1,709,288 6/1/2022 381 33.865 4,746 4,244 5,589 4,036 1567.493 491,961 1,714,034 7/1/2022 436 40.106 5,372 4,657 5,238 4,446 1400.685 492,396 1,719,406 8/1/2022 456 43.185 5,794 4,941 5,189 5,177 1331.418 492,852 1,725,201 9/1/2022 450 41.331 5,335 4,499 5,216 5,153 1966.155 493,302 1,730,536 10/1/2022 469 47.962 6,127 4,890 5,993 5,350 2181.625 493,771 1,736,663 11/1/2022 425 43.968 5,473 4,306 5,838 4,858 2059.733 494,196 1,742,136 12/1/2022 445 47.726 6,800 4,952 6,208 4,725 2121.711 494,641 1,748,936 1/1/2023 456 54.089 6,562 4,800 5,852 4,546 2001.046 495,097 1,755,497 2/1/2023 400 43.568 5,496 4,433 5,678 4,267 2166.813 495,498 1,760,994 3/1/2023 441 53.073 6,582 4,662 6,262 4,789 2434.794 495,939 1,767,576 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 4/1/2022 542 2,744 4,283 4,025 4,857 1309.81 -2,623 5/1/2022 619 3,608 4,912 3,750 4,714 1240.34 -565 6/1/2022 529 3,041 4,308 3,814 4,096 971.846 -1,003 7/1/2022 606 3,439 4,727 3,574 4,513 868.425 -183 8/1/2022 634 3,718 5,015 3,540 5,254 825.479 -254 9/1/2022 626 3,407 4,566 3,559 5,231 1219.02 -1,409 10/1/2022 652 3,938 4,963 4,089 5,431 1352.61 -1,320 11/1/2022 591 3,514 4,371 3,984 4,931 1277.03 -1,715 12/1/2022 618 4,409 5,026 4,236 4,795 1315.46 -293 1/1/2023 635 4,241 4,872 3,993 4,614 1240.65 -100 2/1/2023 557 3,543 4,500 3,874 4,331 1343.42 -949 3/1/2023 614 4,262 4,732 4,273 4,861 1509.57 -1,035 Table 2 - Pt McIntyre Monthly Voidage Balance Monthly Production GPMA Page 16 ASR for Apr ’22 –Mar ‘23 Table 3 –Point McInytre Pressure data April 1, 2022 to March 31, 2023 Well Name Survey Date Pressure (psi) (Datum = 8,800' SS) No pressure surveys obtained in Point McIntyre Oil Pool for the period. GPMA Page 17 ASR for Apr ’22 –Mar ‘23 Figure 1 Pt. McIntyre Well Location Map Unit Boundary GPMA Page 18 ASR for Apr ’22 –Mar ‘23 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 19 ASR for Apr ’22 –Mar ‘23 Prudhoe Bay Unit Raven Oil Pool and Sag River Undefined Oil Pool 2023 Annual Reservoir Surveillance Report This Annual Reservoir Report for the period ending March 31,2023 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 1,2022 and March 31,2023. 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 and has been a full-time producer since that time. GPMA Page 20 ASR for Apr ’22 –Mar ‘23 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 Sag and Ivishak rich gas. In December of 2021,the NK-65A was converted to production service and has produced a cumulative 264 MSTBO to-date from the Ivishak and Sag 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 the Ivishak in NK-38B was taken in February 2021 and reservoir pressure was 4,252 psi (datum).Two reservoir pressures in the Sag River were taken in the reporting period in NK-14B and NK-08B. The proposed number of Raven reservoir pressure surveys to be obtained in the coming plan year April 1,2023 to March 31, 2024 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 21 ASR for Apr ’22 –Mar ‘23 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 being 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 10th, 2022,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. The well is currently shut in. 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 2022 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 2023 update of the Raven Plan of Development is filed with the division. GPMA Page 22 ASR for Apr ’22 –Mar ‘23 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 0.96-1.05. Daily allocation data and daily test data are being retained. Month Year LPC Allocation Factor April 2022 0.97 May 2022 0.98 June 2022 1.05 July 2022 1.01 August 2022 1.02 September 2022 1.00 October 2022 0.96 November 2022 0.98 December 2022 1.01 January 2023 0.98 February 2023 1.00 March 2023 1.00 GPMA Page 23 ASR for Apr ’22 –Mar ‘23 Tables and Figures Note:Monthly Production/Injection/Voidage for the Ivishak and Sag River. Gas Inject Water Inject MI Inject Oil + NGL Oil NGL Gas Water Monthly Monthly Monthly Oil Gas Date mstbo mstbo mstbo mmscf mbw mmscf mbw mmscf mstb mstb 4/1/2022 53 47.98 4.847 866 72 0 0 0 5,837 36,049 5/1/2022 38 34.953 2.926 630 55 0 0 0 5,872 36,679 6/1/2022 48 44.317 3.719 730 42 0 0 0 5,916 37,409 7/1/2022 42 40.014 1.98 813 63 0 0 0 5,956 38,222 8/1/2022 38 35.814 2.329 692 63 0 0 0 5,992 38,914 9/1/2022 35 33.001 2.464 618 34 0 0 0 6,025 39,531 10/1/2022 47 42.872 3.739 782 18 0 0 0 6,068 40,314 11/1/2022 48 43.78 4.134 768 80 0 0 0 6,112 41,082 12/1/2022 40 39.446 0.977 955 126 0 0 0 6,151 42,037 1/1/2023 32 31.227 1.165 689 78 0 0 0 6,182 42,725 2/1/2023 27 26.46 0.681 600 83 0 0 0 6,209 43,325 3/1/2023 37 35.038 2.023 705 87 0 0 0 6,244 44,030 Table 1 - Raven Monthly Production & Injection Volumes CumulativeMonthly Production Gas InjectWater Inject MI Inject Net Res. Oil Gas Water Monthly Monthly Monthly Voidage Date mrvb mrvb mrvb mrvb mrvb mrvb mvrb 4/1/2022 74 622 73 0 0 0 768 5/1/2022 54 452 55 0 0 0 561 6/1/2022 68 521 42 0 0 0 632 7/1/2022 62 587 64 0 0 0 713 8/1/2022 55 499 64 0 0 0 618 9/1/2022 51 444 34 0 0 0 529 10/1/2022 66 562 19 0 0 0 646 11/1/2022 67 550 81 0 0 0 699 12/1/2022 61 696 127 0 0 0 883 1/1/2023 48 500 78 0 0 0 626 2/1/2023 41 436 84 0 0 0 560 3/1/2023 54 509 88 0 0 0 651 Table 2 - Raven Monthly Voidage Balance Monthly Production GPMA Page 24 ASR for Apr ’22 –Mar ‘23 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 25 ASR for Apr ’22 –Mar ‘23 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 NK-08B 10/27/22 SBHP - Sag 9850 1856 NK-14B 12/24/22 SBHP – Sag 9850 1883 GPMA Page 26 ASR for Apr ’22 –Mar ‘23 GPMA Page 27 ASR for Apr ’22 –Mar ‘23 GPMA Page 28 ASR for Apr ’22 –Mar ‘23 GPMA Page 29 ASR for Apr ’22 –Mar ‘23 GPMA Page 30 ASR for Apr ’22 –Mar ‘23