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Home My WebLink About2024 Thomson Oil Pool Hilcorp Alaska PTU Annual Reservoir Surveillance Report 2024 Page 1 Annual Reservoir Surveillance Report – 2024 Thomson Oil Pool Point Thomson Unit Introduction This annual reservoir surveillance report is submitted to the Alaska Oil and Gas Conservation Commission by Hilcorp Alaska, LLC., Point Thomson Unit (PTU) operator, in accordance with Rule 8 of Area Injection Order No. 38 dated August 25, 2015, and Rule 5 of Conservation Order No. 719 dated November 9, 2015, for the Thomson Oil Pool within the PTU. The report covers calendar year 2024 for the Initial Production System (IPS) facility operations. Enhanced Recovery Project and Reservoir Management – Rule 8(a) & 5(a)(v),(vi) The Point Thomson IPS project produces natural gas and condensate from the Thomson Oil Pool to recover liquid condensate for sale and reinject the residue gas as the enhanced recovery mechanism (gas-cycling). Condensate is transported through the Point Thomson Export Pipeline (PTEP) for delivery to the Trans-Alaska Pipeline System common carrier pipelines. The reservoir management strategy for the Thomson Sand is to reinject cycled gas to help maintain reservoir pressure for condensate recovery and conserve the gas for future development. The IPS also provides information about gas condensate production and reservoir connectivity to assist in subsequent development plans. Reservoir Voidage Balance – Rule 8(b) & 5(a)(i) Monthly production and injection volumes and the reservoir voidage balance for the Thomson reservoir by month and cumulative through December 2023 are summarized in Table 1. Voidage replacement ratio in 2023 was 0.84. The Annual Report of Injection Project, Form 10-413, is included as Table 2. Reservoir Pressure Surveys – Rule 8(c) & 5(a)(ii) Reservoir pressure monitoring is performed in accordance with Conservation Order No. 719, Rule 3. Static bottom-hole pressure measurements were collected from permanent downhole gauges and corrected to Thomson reservoir pressure datum of -12,700’ TVDSS (true vertical depth subsea). Bottom-hole pressures were taken during well drilling prior to initial production or injection, and subsequently during extended well shut in periods. In PTU-15 and PTU-16 initial reservoir pressure was recorded using wireline MDT during initial drilling in 2010. Correcting to datum, the reservoir pressure measured in both wells was ~10,100 Hilcorp Alaska PTU Annual Reservoir Surveillance Report 2024 Page 2 psi. PTU-17 initial reservoir pressure data collected while drilling on December 29, 2015 was 10,107 psi at datum. A summary of static bottom-hole pressures is shown in Table 3, Form 10-412 Reservoir Pressure Report. Table 4 is the Form 10-428 Annual Reservoir Properties Report required by 20 AAC 25.270(e). Average properties are quoted, noting that ranges for porosity, permeability and water saturation are relatively wide. Thomson Oil Pool can be characterized as a retrograde condensate reservoir which helps to explain the reported properties. A reservoir pressure map is shown in Figure 1. Analysis of pressure surveys indicates limited reservoir pressure decline. The variation from initial recorded pressure and between wells is within the expected range given temperature corrections and fluid gradient variations. Production & Injection Log Surveys – Rule 8(d) & 5(a)(iii) No production or injection log surveys were run during the reporting period. Fracture Propagation into Adjacent Confining Intervals – Rule 8(e) Downhole and surface wellhead gas injection pressures and rates for PTU-15 and PTU-16 are shown in Figures 2 and 3, respectively. In accordance with Area Injection Order No. 38, Rule 4, gas injection pressures were maintained below 11,500 psi at the reservoir sand face. Mechanical Integrity Test (MIT) Results – Rule 8(f) Injection wells PTU-15 and PTU-16 performed and passed casing/tubing mechanical integrity tests, witnessed by the AOGCC, on September 6, 2024. The MIT’s were scheduled as required once every four years after injection is commenced and stabilized by Rule 6 of Area Injection Order No. 38. The previous PTU-15 and PTU-16 MIT’s were conducted in September of 2020. MIT passing criteria requires the inner annulus pressure to hold a minimum of 1,500 psi or 0.25 psi/ft multiplied by the packer TVD for 30 minutes with less than 10% decline and a stabilizing pressure trend. Table 5 summarizes PTU-15 and PTU-16 2020 MIT data and results. The next MIT pressure tests on PTU-15 and PTU-16 will be due in 2028. Hilcorp Alaska PTU Annual Reservoir Surveillance Report 2024 Page 3 Inner and Outer Annulus Monitoring – Rule 8(g) Casing annulus pressures of production and injection wells completed in the Thomson reservoir are monitored in accordance with Area Injection Order No. 38, Rule 5, and Conservation Order No. 719, Rule 7. Digital continuous pressure monitoring is installed on each annulus of PTU-15, PTU-16 and PTU- 17. Control room alarms are in place to notify operations of high pressure for initiation of manual bleed down intervention. An annotated summary of annulus pressure monitoring is shown in Figures 4 to 6. Special Monitoring – Rule 8(h) & 5(a)(iii) No special monitoring was undertaken during the reporting period. Pool Production Allocation – Rule 5(a)(iv) Point Thomson production is wholly allocated back to the sole producing PTU-17 well from the Thomson reservoir. Condensate liquids are metered at the custody transfer meter on Point Thomson Central Pad. Total produced gas from PTU-17 is calculated as the sum of injected gas into PTU-15 and PTU-16, lease fuel, pilot/purge and flare gas. Reservoir Surveillance Plans – Rule 8(i) Reservoir surveillance plans for next year include the collection of surface wellhead and downhole pressure and temperature data, which will be used to monitor reservoir pressure, well productivity and injectivity. Casing annulus pressures will continue to be recorded to monitor integrity of the wells. Pressure and temperature data will be complemented by well production and injection rates, together with metered condensate, gas and water volumes. The information will be used to calculate gas-condensate ratio, water cut and voidage replacement for the field. No production or injection log surveys are planned for 2025. Development Plans – Rule 8(j) & 5(a) As noted above, IPS operations will provide data and information regarding production, well and reservoir performance, and IPS facility performance to assist in evaluation of development plans. Hilcorp Alaska is currently evaluating the economic feasibility of development at the Point Thomson Unit. Hilcorp Alaska PTU Annual Reservoir Surveillance Report 2024 Page 4 ATTACHMENTS Table 1: Monthly Production, Injection and Voidage Balance Summary ..................................................... 5 Table 2: Annual Report of Injection Project (Form 10-413) .......................................................................... 6 Table 3: Reservoir Pressure Report (Form 10-412) ...................................................................................... 7 Table 4: Annual Reservoir Properties Report (Form 10-428) ....................................................................... 8 Table 5: PTU-15 and PTU-16 Mechanical Integrity Test Report (Form 10-426) ........................................... 9 Figure 1: Thomson Reservoir Pressure Map ............................................................................................... 10 Figure 2: PTU-15 Injection Pressure and Rate ............................................................................................ 11 Figure 3: PTU-16 Injection Pressure and Rate ............................................................................................ 12 Figure 4: PTU-15 Annulus Monitoring ........................................................................................................ 13 Figure 5: PTU-16 Annulus Monitoring ........................................................................................................ 14 Figure 6: PTU-17 Annulus Monitoring ........................................................................................................ 15 Hilcorp Alaska PTU Annual Reservoir Surveillance Report 2024 Page 5 Table 1: Monthly Production, Injection and Voidage Balance Summary Note: Bc = 0.999 RB / STB Bg = 0.480 RB / MSCF Bw = 1.000 RB / STB Bc = condensate formation volume factor Bg = dry gas formation volume factor Bw = water formation volume factor MSCF = thousand standard cubic feet RB = reservoir barrels STB = stock tank barrels VRR = voidage replacement ratio Table 1: Monthly Production, Injection and Voidage Balance Summary Water VRR (STB) (RB/RB) Jan-24 55,482 779 978,754 917,390 0.84 Feb-24 0 13 39,889 0 0.00 Mar-24 156 103 202,531 148,701 0.73 Apr-24 1,779 20 47,001 901 0.02 May-24 63,377 766 1,071,723 998,111 0.83 Jun-24 123,555 1,339 2,031,891 1,950,609 0.85 Jul-24 130,682 1,586 2,165,335 2,084,659 0.85 Aug-24 131,071 1,715 2,133,141 2,050,029 0.85 Sep-24 140,351 1,733 2,098,232 2,017,424 0.84 Oct-24 143,651 1,706 2,161,322 2,072,861 0.84 Nov-24 130,250 1,665 2,091,471 2,003,597 0.85 Dec-24 133,040 1,737 2,127,319 2,040,752 0.85 TOTAL 1,053,394 13,161 17,148,609 16,285,034 0.84 Month Condensate (STB)Dry Gas Production (MSCF) Dry Gas Injection (MSCF) Hilcorp Alaska PTU Annual Reservoir Surveillance Report 2024 Page 6 Table 2: Annual Report of Injection Project (Form 10-413) 2024 Address Field and Pool +0 -0 +0 -0 +0 -0 +0 -0 + 0 - 0 (A) (B) (C) (A)+(B)+(C) (D) (E) (F) (D)+(E)+(F) (5.)-(6.) psia -12700 Subsea Signature: Date: Printed Name: Title: 2. GAS INJECTION DATA As of Dec. 31, active water inj. Wells 0 Number of Inj./Conservation Order Authorizing Project Annual volume water inj. Name of Injection Project AIO #38 and CO #719Point Thomson Initial Production System (IPS) As of Jan. 1, Total oil wells STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION ANNUAL REPORT OF INJECTION PROJECT 20 AAC 25.432 (2) Hilcorp Alaska, LLC Point Thomson Unit 3800 Centerpoint Dr Suite 1400, Anchorage AK 99503 Point Thomson Field, Point Thomson Oil Pool Type of Injection Project Annual volume oil and/or condensate produced 1,052,414 Annual volume gas produced Cumulative gas to dateGas wells added or subtracted Oil wells added or subtracted As of Jan. 1, Total gas wells 0 NET INJECTED (+) OR PRODUCED (-) VOLUMES -1482307 0 17,148,609 4. PRODUCTION DATA 5. INJECTION VOLUMES (Resevoir Barrels) Annual Volume Unit or Lease Name 3. LPG INJECTION DATA As of Dec. 31, active gas inj. Wells 2 Annual volume gas inj. 16,285,035 311,727,813 Cumulative water inj. to date Enhanced Recovery (Gas Cycling) 1. WATER INJECTION DATA Gas inj. wells added or subtracted Water inj. wells added or subtracted 0 17,922,614 Annual volume LPG inj. Cumulative LPG inj. to dateLPG inj. wells added or subtracted As of Dec. 31, Total gas wells Cumulative since project start 2 0 As of Jan. 1, active water inj. wells As of Jan. 1, active gas inj. wells 1 323,409,012 Cumulative oil and/or condensate to date As of Dec. 31, Total oil wells 1 As of Dec. 31, Active LPG inj. wells FOR THE YEAR: Water (surface bbls.=reservoir bbls.) LPG (Surface bbls.=reservoir bbls.) Indicate type of LPG, Butane, Propane or other. Cumulative gas inj. to date 0 123554590 0 0 Name of Operator As of Jan. 1, active LPG inj. wells 6. PRODUCED VOLUMES (Resevoir Barrels) TOTAL FLUIDS INJECTED (reservoir bbls.) 0 0 0 123554590 0 7882115 7882115 128411085 227428 1051362Oil (Stock tank Bbls. X formation volume factor) 8300093 TOTAL PRODUCED VOLUMES (reservoir barrels)146543204 Water (surface bbls.=reservoir bbls.)12967 10014 Year end reservoir pressure Datum feet -22988614 I hereby certify that the foregoing is true and correct to the best of my knowledge. 0 17904691 Gavin Dittman 3/7/2025 Reservoir Engineer 9364422 (Gas Z (Compressibilty factor) X Tr (reservoir temperature, oF absolute) X 14.65Standard CF X volume factor v. where v= 5.615 cf/bbl. X Pr. (reservoir pressure, psia) X 520 (absolute equivalent at 60oF)) Free Gas (Total gas produced in standard cubic feet less solution gas produced (Stock tank bbls. Oil produced X solution gas oil ratio) X volume factor v calculated for produced gas ) Hilcorp Alaska PTU Annual Reservoir Surveillance Report 2024 Page 7 Table 3: Reservoir Pressure Report (Form 10-412) 6. Oil Gravity: 36 API 8. Well Name and Number: 9. API Number 50XXXXXXXXXX XX 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) PTU-17 50089200330000 O 668150 Thomson Sand 12619-12823 12/27/2024 4 SBHP 10571 9687 12700 0.16 10014 PTU-15 50089200300000 GI 668150 Thomson Sand 12622-12804 5/31/2024 1800 SBHP 10420 9716 12700 0.14 10029 PTU-16 50089200310000 GI 668150 Thomson Sand 12763-12908 5/14/2024 1296 SBHP 10022 9667 12700 0.14 10035 Printed Name Gavin Dittman Date March 7, 2025 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. Signature Title Reservoir Engineer 3. Unit or Lease Name: 4. Field and Pool: 5. Datum Reference: 7. Gas Gravity: Point Thomson Unit Point Thomson Field, Thomson Oil Pool -12,700' TVDSS 0.7 Hilcorp Alaska, LLC. 3800 Centerpoint Dr., Anchorage, AK, 99524, Suite 1400 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION RESERVOIR PRESSURE REPORT 1. Operator: 2. Address: Hilcorp Alaska PTU Annual Reservoir Surveillance Report 2024 Page 8 Table 4: Annual Reservoir Properties Report (Form 10-428) 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) Point Thomson 668150 Thomson Oil Pool -12,700 230 15 100 42 1.81 1.81 10100 10100 10014 36 0.7 235 235 0.0029 0 1.5 20,000 16294 Reservoir Engineer 3/7/2025 Hilcorp Alaska, LLC 3800 Centerpoint Dr Suite 1400, Anchorage AK 99503 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION ANNUAL RESERVOIR PROPERTIES REPORT 1. Operator: 2. Address: Printed Name Gavin Dittman Date I hereby certify that the foregoing is true and correct to the best of my knowledge. Signature Title Hilcorp Alaska PTU Annual Reservoir Surveillance Report 2024 Page 9 Table 5: 2024 PTU-15 and PTU-16 Mechanical Integrity Test Report (Form 10-426) Submit to: OPERATOR: FIELD / UNIT / PAD: DATE: OPERATOR REP: AOGCC REP: Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD 2090140 Type Inj G Tubing 8514 8514 8514 8514 Type Test P Packer TVD 12425 BBL Pump 6.6 IA 1341 3680 3628 3612 Interval 4 Test psi 3106 BBL Return 6.4 OA 7 7 7 7 Result P Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD 2090150 Type Inj G Tubing 8528 8528 8528 8528 Type Test P Packer TVD 12577 BBL Pump 14.1 IA 0 3670 3561 3518 Interval 4 Test psi 3144 BBL Return 12.3 OA 0 24 24 28 Result P TYPE INJ Codes TYPE TEST Codes INTERVAL Codes Result Codes W = Water P = Pressure Test I = Initial Test P = Pass G = Gas O = Other (describe in Notes) 4 = Four Year Cycle F = Fail S = Slurry V = Required by Variance I = Inconclusive I = Industrial Wastewater O = Other (describe in notes) N = Not Injecting Hilcorp Alaska LLC Pt Thomson / PTU / Pt Thomson Kam St John Dean Devaney 09/06/24 Notes:OOA pressures: 0/0/0/0 PTU-15 PTU-16 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION Mechanical Integrity Test jim.regg@alaska.gov;AOGCC.Inspectors@alaska.gov;phoebe.brooks@alaska.gov chris.wallace@alaska.gov Notes:OOA pressures: 0/0/0/0 Hilcorp Alaska PTU Annual Reservoir Surveillance Report 2024 Page 10 Figure 1: Thomson Reservoir Pressure Map 10014 10029 10035 10014 Hilcorp Alaska PTU Annual Reservoir Surveillance Report 2024 Page 11 Figure 2: PTU-15 Injection Pressure and Rate Hilcorp Alaska PTU Annual Reservoir Surveillance Report 2024 Page 12 Figure 3: PTU-16 Injection Pressure and Rate Hilcorp Alaska PTU Annual Reservoir Surveillance Report 2024 Page 13 Figure 4: PTU-15 Annulus Monitoring Hilcorp Alaska PTU Annual Reservoir Surveillance Report 2024 Page 14 Figure 5: PTU-16 Annulus Monitoring Hilcorp Alaska PTU Annual Reservoir Surveillance Report 2024 Page 15 Figure 6: PTU-17 Annulus Monitoring