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Home My WebLink About2020 Thomson Oil Pool March 30th, 2021 ER-2021-OUT-071 Mr. Jeremy Price, Chair Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue, Suite 100 Anchorage, Alaska 99501-3572 Re: Point Thomson Unit 2020 Annual Reservoir Surveillance Report Dear Commissioner Price, ExxonMobil Alaska Production Inc. hereby submits an Annual Reservoir Surveillance Report for the Thomson Oil Pool within the Point Thomson Unit in accordance with Rule 8 of Area Injection Order No. 38 dated August 25, 2015 and Rule 5 of the Conservation Or der No. 719 dated November 9, 2015. A technical review will be scheduled with representatives from AOGCC to review the annual reservoir surveillance report in accordance with Rule 5(b) of the Conservation Order No. 719. If you have any questions or require additional information, please contact Claire Mayfield at (907) 564-3651. Sincerely, Todd Griffith For and On Behalf of ExxonMobil Alaska Production Inc. CC: cm Attachment: Annual Reservoir Surveillance Report (2 copies) Pressure Reservoir Report (form 10-412) (2 copies) Annual Surveillance Form (form 10-413) (2 copies) Annual Reservoir Properties Report (form 10-428) (2 copies) ExxonMobil Alaska Production Inc. P. O. Box 196601 Anchorage, Alaska 99519-6601 907 564 3607 Telephone Todd Griffith Asset Manager DocuSign Envelope ID: 3B9210D1-93A4-416C-A587-435044173DAF ExxonMobil PTU Annual Reservoir Surveillance Report 2020 Page 1 Annual Reservoir Surveillance Report – 2020 Thomson Oil Pool Point Thomson Unit Introduction This annual reservoir surveillance report is submitted to the Alaska Oil and Gas Conservation Commission by ExxonMobil Alaska Production Inc., 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 2020 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 2020 are summarized in Table 1. Voidage replacement ratio in 2020 was 0.87, no change from 2019. 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 ExxonMobil PTU Annual Reservoir Surveillance Report 2020 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. For PTU-15, at an injection rate of 129MMscf/d (million standard cubic feet), injection pressure of 10,439 psi was recorded at the downhole gauge April 20, 2020. Equivalent maximum reservoir sand face pressure was 10,755 psi with an injected gas gradient. At PTU-16, a downhole injection gauge pressure of 10,920 psi was measured December 14, 2020 at an injection rate of 67MMscf/d. The corresponding maximum sand face injection pressure is 11,292 psi with an injected gas gradient. 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 18, 2020. 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 October of 2016. 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. ExxonMobil PTU Annual Reservoir Surveillance Report 2020 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 2021. 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. Future plans are described in the PTU Plan of Development (POD) dated October 2, 2019, submitted to the Alaska Department of Natural Resources as conditioned by the Point Thomson Unit Letter Agreement, dated September 10, 2018. ExxonMobil PTU Annual Reservoir Surveillance Report 2020 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 ExxonMobil PTU Annual Reservoir Surveillance Report 2020 Page 5 Table 1: Monthly Production, Injection and Voidage Balance Summary Month Condensate (STB) Water (STB) Dry Gas Production (MSCF) Dry Gas Injection (MSCF) VRR (RB/RB) Jan-20 164,048 2,071 2,991,829 2,893,749 0.87 Feb-20 167,441 2,150 3,098,481 3,004,947 0.87 Mar-20 235,620 3,038 4,365,633 4,253,822 0.87 Apr-20 278,330 3,564 5,202,776 5,075,341 0.88 May-20 298,162 3,800 5,567,896 5,434,267 0.88 Jun-20 283,198 3,599 5,214,392 5,085,355 0.88 Jul-20 281,044 3,516 5,128,447 5,001,230 0.87 Aug-20 254,616 3,187 4,630,900 4,509,929 0.87 Sep-20 225,155 2,825 4,138,169 4,025,617 0.87 Oct-20 281,963 3,676 5,226,262 5,095,432 0.88 Nov-20 259,392 3,373 4,741,791 4,620,194 0.87 Dec-20 236,954 3,033 4,273,936 4,151,283 0.87 TOTAL 2,965,923 37,832 54,580,512 53,151,167 0.87 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 ExxonMobil PTU Annual Reservoir Surveillance Report 2020 Page 6 Table 2: Annual Report of Injection Project (Form 10-413) 2020 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: I hereby certify that the foregoing is true and correct to the best of my knowledge. 0 8796306 Claire Mayfield Claire Mayfield 3/21/2021 Production Engineer 29292263TOTAL PRODUCED VOLUMES (reservoir barrels)87060350 Water (surface bbls.=reservoir bbls.)37832 10062 Year end reservoir pressure Datum feet -12048567 78151500 112724 2962957Oil (Stock tank Bbls. X formation volume factor) 26291474 6. PRODUCED VOLUMES (Resevoir Barrels) TOTAL FLUIDS INJECTED (reservoir bbls.) 0 0 0 75011783 0 25602958 25602958 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 75011783 0 0 Name of Operator As of Jan. 1, active LPG inj. wells 2 0 As of Jan. 1, active water inj. wells As of Jan. 1, active gas inj. wells 1 162,474,638 Cumulative oil and/or condensate to date As of Dec. 31, Total oil wells 1 As of Dec. 31, Active LPG inj. wells Gas inj. wells added or subtracted Water inj. wells added or subtracted 0 8,805,112 Annual volume LPG inj. 0 Cumulative LPG inj. to dateLPG inj. wells added or subtracted As of Dec. 31, Total gas wells Cumulative since project start Unit or Lease Name 3. LPG INJECTION DATA As of Dec. 31, active gas inj. Wells 2 Annual volume gas inj. 53,151,167 155,942,611 Cumulative water inj. to date Enhanced Recovery (Gas Cycling) 1. WATER INJECTION DATA As of Jan. 1, Total gas wells 0 NET INJECTED (+) OR PRODUCED (-) VOLUMES -3689305 0 54,580,512 4. PRODUCTION DATA 5. INJECTION VOLUMES (Resevoir Barrels) Annual Volume Annual volume oil and/or condensate produced 2,965,923 Annual volume gas produced Cumulative gas to dateGas wells added or subtracted Oil wells added or subtracted 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) ExxonMobil Alaska Production Inc. Point Thomson Unit PO Box 196601 Anchorage, AK 99519-6601 Point Thomson Field, Point Thomson Oil Pool Type of Injection Project 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) (Gas Z (Compressibilty factor) X Tr (reservoir temperature, oF absolute) X 14.65 Standard 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 ) ExxonMobil PTU Annual Reservoir Surveillance Report 2020 Page 7 Table 3: Reservoir Pressure Report (Form 10-412) ExxonMobil PTU Annual Reservoir Surveillance Report 2020 Page 8 Table 4: Annual Reservoir Properties Report (Form 10-428) ExxonMobil PTU Annual Reservoir Surveillance Report 2020 Page 9 Table 5: PTU-15 and PTU-16 Mechanical Integrity Test Report (Form 10-426) ExxonMobil PTU Annual Reservoir Surveillance Report 2020 Page 10 Figure 1: Thomson Reservoir Pressure Map ExxonMobil PTU Annual Reservoir Surveillance Report 2020 Page 11 Figure 2: PTU-15 Injection Pressure and Rate ExxonMobil PTU Annual Reservoir Surveillance Report 2020 Page 12 Figure 3: PTU-16 Injection Pressure and Rate ExxonMobil PTU Annual Reservoir Surveillance Report 2020 Page 13 Figure 4: PTU-15 Annulus Monitoring MIT 9/18/2020 ExxonMobil PTU Annual Reservoir Surveillance Report 2020 Page 14 Figure 5: PTU-16 Annulus Monitoring MIT 9/18/2020 ExxonMobil PTU Annual Reservoir Surveillance Report 2020 Page 15 Figure 6: PTU-17 Annulus Monitoring