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Home My WebLink About2019 Thomson Oil Pool April 27, 2020 ER-2020-OUT-064 Ms. Jessie Chmielowski, Chair Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue, Suite 100 Anchorage, Alaska 99501-3572 Re: Point Thomson Unit 2019 Annual Reservoir Surveillance Report Dear Commissioner Chmielowski, 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 Kenley Scarlett at (907) 564-3606. Sincerely, Lisa Cross For and On Behalf of ExxonMobil Alaska Production Inc. CC: ks 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 5331 Telephone Lisa M. Cross Operations Technical / OBO Asset Manager DocuSign Envelope ID: 35E5530E-1970-4494-B15C-BCCA0309AC93 ExxonMobil PTU Annual Reservoir Surveillance Report 2019 Page 1 Annual Reservoir Surveillance Report – 2019 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 2019 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 2018 are summarized in Table 1. Voidage replacement ratio in 2019 was 0.87 compared to 0.86 in 2018. 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 2019 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 117MMscf/d (million standard cubic feet), injection pressure of 10,271 psi was recorded at the downhole gauge April 21, 2019. Equivalent maximum reservoir sand face pressure was 10,587 psi with an injected gas gradient. At PTU-16, a downhole injection gauge pressure of 10,776 psi was measured November 26, 2019 at an injection rate of 73MMscf/d. The corresponding maximum sand face injection pressure is 11,148 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) No mechanical integrity tests were performed during the reporting period. ExxonMobil PTU Annual Reservoir Surveillance Report 2019 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 next year. 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 2019 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 Figure 1: Thomson Reservoir Pressure Map .............................................................................. 9 Figure 2: PTU-15 Injection Pressure and Rate ..........................................................................10 Figure 3: PTU-16 Injection Pressure and Rate ..........................................................................11 Figure 4: PTU-15 Annulus Monitoring .......................................................................................12 Figure 5: PTU-16 Annulus Monitoring .......................................................................................13 Figure 6: PTU-17 Annulus Monitoring .......................................................................................14 ExxonMobil PTU Annual Reservoir Surveillance Report 2019 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) 01/2019 294,176 3,567 5,500,558 5,365,629 0.88 02/2019 245,960 3,026 4,601,391 4,490,169 0.88 03/2019 299,898 3,830 5,608,472 5,491,632 0.88 04/2019 240,813 3,116 4,452,397 4,354,133 0.88 05/2019 206,712 2,708 3,755,592 3,666,466 0.87 06/2019 144,685 1,877 2,589,303 2,512,063 0.87 07/2019 130,225 1,679 2,306,081 2,235,492 0.87 08/2019 103,710 1,336 1,856,736 1,796,100 0.87 09/2019 151,141 2,001 2,707,355 2,627,777 0.87 10/2019 149,108 1,935 2,700,507 2,620,582 0.87 11/2019 37,879 461 645,121 591,231 0.82 12/2019 170,212 2,198 3,074,420 2,986,294 0.87 TOTAL 2,174,519 27,734 39,797,933 38,737,568 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 2019 Page 6 Table 2: Annual Report of Injection Project (Form 10-413) ExxonMobil PTU Annual Reservoir Surveillance Report 2019 Page 7 Table 3: Reservoir Pressure Report (Form 10-412) ExxonMobil PTU Annual Reservoir Surveillance Report 2019 Page 8 Table 4: Annual Reservoir Properties Report (Form 10-428) ExxonMobil PTU Annual Reservoir Surveillance Report 2019 Page 9 Figure 1: Thomson Reservoir Pressure Map ExxonMobil PTU Annual Reservoir Surveillance Report 2019 Page 10 Figure 2: PTU-15 Injection Pressure and Rate ExxonMobil PTU Annual Reservoir Surveillance Report 2019 Page 11 Figure 3: PTU-16 Injection Pressure and Rate ExxonMobil PTU Annual Reservoir Surveillance Report 2019 Page 12 Figure 4: PTU-15 Annulus Monitoring ExxonMobil PTU Annual Reservoir Surveillance Report 2019 Page 13 Figure 5: PTU-16 Annulus Monitoring ExxonMobil PTU Annual Reservoir Surveillance Report 2019 Page 14 Figure 6: PTU-17 Annulus Monitoring