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Home My WebLink About2016 Thomson Oil PoolP r c.,_ March 24, 2017 ER -2017 -OUT -051 Ms. Cathy Foerster, Chair Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue, Suite 100 Anchorage, Alaska 99501-3572 Jam . u _ `yin _ E�onMobft Re: Point Thomson Unit 2016 Annual Reservoir Surveillance Report Dear Commissioner Foerster, RECEIVED MAR 2 9 p017 AOGCC 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 Order No. 719 dated November 9, 2015. The Mechanical Integrity Test results for PTU -15 & 16 are summarized in this report. Detailed reports were previously provided on October 27, 2016. 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 Luke Motteram at (907) 564-3697. Sincerely, JML/Im/mlv CC: Attachment: Annual Reservoir Surveillance Report (2 copies) Pressure Reservoir Report (form 10-412) (2 copies) Annual Surveillance Form (form 10-413) (2 copies) A Division of Exxon Mobil Corporation E*(OnMoblml Annual Reservoir Surveillance Report — 2016 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 2016 from the Initial Production System (IPS) facility start-up on April 2 through December 31, 2016. 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. Start-up of the IPS facility occurred April 2, 2016 with gas and condensate production from the PTU -15 well on Central Pad. Gas reinjection into the Thomson reservoir via the PTU -16 well on Central Pad commenced April 16, 2016. In May 2016, the PTU -15 production well was converted to gas injection service. Gas and condensate production from the PTU -17 well located on West Pad commenced May 28, 2016. First gas reinjection into PTU -15 occurred June 5, 2016. 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 2016 are summarized in Table 1. Voidage replacement was affected in 2016 due to extended commissioning of the two gas reinjection compressor trains. The Annual Report of Injection Project, Form 10-413, is included as Table 2. PTU Annual Reservoir Surveillance Report 2016 Page 1 ExxonMobil Reservoir Pressure Surveys -Rule 8(c) & 5(a)(ii) Reservoir pressure monitol sng iS pe1 formed 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 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. A reservoir pressure map is shown in Figure 1. Analysis of pressure surveys indicates limited reservoir pressure decline. The variation from initial recorded pressure is within the expected range given temperature corrections and fluid gradient variations. Interference during initial production from PTU -17 in late -May 2016 was observed at the downhole pressure gauge in PTU -15. A response at the downhole pressure gauge in PTU -16 was also observed in July 2016 during initial injection into PTU -15. This is indicative of good connectivity across the reservoir. 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. Maximum injection pressures and rates for both wells were observed in late 2016, after design rates were achieved. For PTU -15, at a maximum sustained rate of 110MMscf/d (million standard cubic feet), injection pressures were 9,410 psi at the wellhead and 10,190 psi at the downhole gauge. Equivalent maximum reservoir sand face pressure was 10,520 psi with an injected gas gradient. In PTU -16, surface injection and downhole gauge pressures of 9,445 psi and 10,380 psi, respectively, were observed at a maximum sustained injection rate of 95MMscf/d, corresponding to a maximum injection pressure of 10,790 psi at the sand face. The well surveillance pressure data confirm that injection pressures have been maintained below 11,500 psi at the reservoir sand face in accordance with Area Injection Order No. 38, Rule 4. PTU Annual Reservoir Surveillance Report 2016 Page 2 ExxonMobil Mechanical Integrity Test (MIT) Results —Rule 8(f) In accordance with Area Injection Order No. 38, Rule 6, a mechanical integrity test (MIT) of the tubing / casing annulus was performed on gas injection wells PTU -15 and PTU -16 after injection commenced and conditions had stabilized. PTU -15 and PTU -16 MIT pre-tests were undertaken August 13-14, 2016 in preparation for planned AOGCC-witnessed test on August 15, 2016. Testing was deferred due to an unscheduled facility shutdown August 14, 2016. Pre-tests were repeated on October 25, 2016, and MIT testing was witnessed by AOGCC on October 26, 2016. Results are summarized in Table 4 and Figures 4 and 5. 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 6 to 8. 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 well from the Thomson reservoir. Between start-up on April 2 and May 6, 2016, all production was from PTU -15 until sundry 316-151 was submitted and approved to convert PTU -15 to gas injection. Commencing May 28, 2016, all production is through the PTU -17 well. 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. PTU Annual Reservoir Surveillance Report 2016 Page 3 ExxonMobil 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 Pians — Rule 80) & 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. At this time, no change has been made in development plans described in prior submittals. 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: MIT Results Summary (Form 10-426).......................................................................... 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 Mechanical Integrity Test..............................................................................12 Figure 5: PTU -16 Mechanical Integrity Test..............................................................................13 Figure 6: PTU -15 Annulus Monitoring.......................................................................................14 Figure 7: PTU -16 Annulus Monitoring.......................................................................................15 Figure 8: PTU -17 Annulus Monitoring.......................................................................................16 PTU Annual Reservoir Surveillance Report 2016 Page 4 ExxonMobil 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) 04/2016 471972 508 8801382 1017081 0.10 05/2016 06/2016 77403 211276 101 181 1097893 3427691 0 441561 0.00 0.12 07/2016 327893 295 612, 686 5107310 0.75 08/2016 38,144 459 7311037 6711149 0.83 09/2016 935 0 427917 0 0.00 10/2016 527339 572 120307007 7221459 0.63 11/2016 561838 680 1,118, 005 170467093 0.85 12/2016 213.845 2 849 a nc;7 r.19 o I*Q r-0 „ o-7 TOTAL 4713645 51645 819259129 79009,175 0.71 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 PTU Annual Reservoir Surveillance Report 2016 Page 5 ExxonMobil Table 2: Annual Report of Injection Project (Form 10-413) STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION ANNUAL REPORT OF INJECTION PROJECT FOR THE YEAR: 2016 gn AAr. 9.r; a:19 (9� Name of Operator Address ExxonMobil Alaska Production Inc. PO Box 196601 Anchorage, AK 99519-6601 Unit or Lease Name Field and Pool Point Thomson Unit Point Thomson Field, Thomson Oil Pool Type of Injection Project Name of Injection Project Number of Inj./Conservation Order Authorizing Project Enhanced Recovery (Gas -Cycling) Initial Production System (IPS) AIO # 38 and CO # 719 1. WATER INJECTION DATA As of Jan. 1, active water inj. Water inj. wells added or As of Dec. 31, active water Annual volume w ater inj. Cumulative water inj. to date w ells subtracted inj. Wells 0 0 0 0 0 0 2. GAS INJECTION DATA As of Jan. 1, active gas inj. Gas inj. wells added or As of Dec. 31, active gas inj. Annual volume gas inj. Cumulative gas inj. to date w ells subtracted Wells 0 2 0 2 1 7,009,175 1 7,009,175 3. LPG INJECTION DATA As of Jan. 1, active LPG inj. LPG inj. wells added or As of Dec. 31, Active LPG inj. Annual volume LPG inj. Cumulative LPG inj. to date w ells subtracted w ells 0 0 0 0 0 0 4. PRODUCTION DATA As of Jan. 1, Total oil w ells Oil w ells added or As of Dec. 31, Total oil wells Annual volume oil and/or Cumulative oil and/or subtracted condensate produced condensate to date 0 1 0 1 471,645 471,645 As of Jan. 1, Total gas wells Gas wells added or subtraCtE As of Dec. 31, Total gas wells Annual volume gas produced Cumulative gas to date 0 0 0 0 (see above) 8,925,129 1 8,925,129 5. INJECTION VOLUMES (Reservoir Barrels) Annual Volume Cumulative since project start Water (surface bbls.=reservoir bbls.) (A) 0 0 LPG (Surface bbls.=reservoir bbls.) Indicate type of LPG, Butane, Propane or other. (B) 0 0 Standard CFXvol ume factor v. where v= Z (Compressibilty factor) X Tr (reservoir temperature, OF absolute) X 14.65 Gas 5.615 cf(bbl. X Pr. (reservoir pressure, psia) X520 (absolute equivalent at 60oF) (C) 3,363,622 3,363,622 TOTAL FLUIDS INJECTED (reservoir bbls.) (A)+(B)+(C) 1 3,363,622 3,363,622 6. PRODUCED VOLUMES (Reservoir Barrels) Oil (Stock tank Bbls. X formation volume factor) (D) 471,173 471,173 Free Total gas produced in standard cubic feet less solution gas Gas produced (Stock tank Ms. Oil produced X solution gas al ratio) X volume factor v calculated for produced gas (E) 4,283,066 4283066.082 Water (surface bbls.=reservoir bbls.) (F) 5,645 5,645 TOTAL PRODUCED VOLUMES (reservoir barrels) (D)+(E)+(F) 4,759,884 4759884 NET INJECTED (+) OR PRODUCED (-) VOLUMES (5.)-(6.) -1,396,262 -1,396,262 Year end reservoir pressure Datum feet psia Subsea 10,093 -12,700 I hereby certif y that the foregoing is true and correct to the best of know edge. Signature: Luke Motteram Date: 10 -Feb -16 Printed Name: Luke Motteram Title: Production Engineer PTU Annual Reservoir Surveillance Report 2016 Page 6 ExxonMobil Table 3: Reservoir Pressure Report (Form 10-412) STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION RESERVOIR PRESSURE REPORT 1. Operator: 2. Address: ExxonMobll Alaska Production Inc. PO Box 196601 Anchorage, AK 99519-6601 3, Unit or Lease Name: l4. Field and Pool: 5. Datum Reference: 16. Oil Gravity: 7. Gas Gravity: Point Thomson Unit Point Thomson Field, Thomson Oil Pool -12,700' TVDSS 37 API 10.7 8. Well Name and 9. API Number 10. Type 11. AOGCC 12. Zone 13. Perforated 14. Final Test 15. Shut -In 16. Press. 17. B. H. 18. Depth 19. Final 20. Datum 21. Pressure 22. Pressure at Number. 50 See Pool Code Intervals Date Time, Hours Sur v. Type Temp. Tool -R/DSS Observed TVDSS (input) 'Gradient, psi/ft. Datum (cal) NO DASHES Instructions Top - Bottom (see Pressure at TVDSS instructions Tool Depth for codes Thomson PTU -15 50089200300000 GI 668150 Sand 12622-12804 10/9/2016 918 SBHP 178 10420 9755 Thomson 12700 0.15 10093 PTU -17 50089200330000 O 668150 Sand 12619-12823 10/8/2016 271 SBHP 186 10571 9737 12700 0.16 10089 23. All tests reported herein were made in accordance with the applicable rules, regulations and instructions of the Alaska Oil and Gas Conservation Con riission. I hereby certify that the foregoing is true and correct to the best of my knowledge. Signature Luke Motteram Title Production Engineer Printed Name Luke Motteram Date February 10, 2016 N I U Annual Reservoir Surveillance Report 2016 Page 7 ExxonMobil Table 4: MIT Results Summary (Form 10-426) STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION Mechanical integrity Test Submit to: °im.regga(-7alaska.gov, AOGCC.Inspectorsna alaska.gov phoebe.brooks(a-alaska.gov chris.wallace(a-alaska.gov OPERATOR: ExxonMobil Alaska Production Inc. FIELD / UNIT / PAD: Point Thomson Unit, Central Pad DATE: 10/26/16 OPERATOR REP: Luke Motteram AOGCC REP: Matt Herrera TYPE INJ Codes D = Drilling Waste G = Gas I = Industrial Wastewater N = Not Injecting W = Water TYPE TEST Codes M = Annulus Monitoring P = Standard Pressure Test R = Internal Radioactive Tracer Survey A = Temperature Anomaly Survey D = Differential Temperature Test INTERVAL Codes I = Initial Test 4 = Four Year Cycle V = Required by Variance 0 = Other (describe in notes) PTU Annual Reservoir Surveillance Report 2016 Page 8 Packer Depth Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. Well PTU -15 Type Inj. G TVD 12,425' Tubing 8,565 8,565 8,565 8,565 Interval P.T.D. 2090140 Type test P Test psi 3106 Casing 737 3,757 3,708 3,694 P/F P Notes: 7.5bbls to pressure up IA OAJ 0 OA is intermediate annulus, OOAconstantOpsi 11 114 114 Well PTU -16 Type Inj. G TVD 12,577' Tubing 8,575 8,580 8,58G 8,580 Interval I P.T.D. 2090150 Type test P Test psi 3144 Casing 1,232 3,606 37480 3,434 P/F P Notes: 4.6bbls to pressure up IA OA 856 11330 OAis intermediate annulus, OOAconstantOpsi 11320 1309 Well Type Inj. TVD Tubing Interval P.T.D. Type test Test psi Casing P/F Notes: OA Well Type Inj. TVD Tubing Interval P.T.D. Type test Test psi Casing P/F Notes: OA Well Type Inj. TVD Tubing Interval P.T.D. Type test Test psi Casing P/F Notes: I OA TYPE INJ Codes D = Drilling Waste G = Gas I = Industrial Wastewater N = Not Injecting W = Water TYPE TEST Codes M = Annulus Monitoring P = Standard Pressure Test R = Internal Radioactive Tracer Survey A = Temperature Anomaly Survey D = Differential Temperature Test INTERVAL Codes I = Initial Test 4 = Four Year Cycle V = Required by Variance 0 = Other (describe in notes) PTU Annual Reservoir Surveillance Report 2016 Page 8 ExxonMobil Figure 1: Thomson Reservoir Pressure Map 408000 416000 424000 432000 440000 448000 4-559000 minn A,7,,)nnn AIZAAAA A*,*At%A A rL-ft A,%^ d. Ph Aft,%,ft — I — — fb - — — — — — — --WW -T f -'T %f VII 1111*kiwww '"�QUWU %Z*UUU TUU 4120UU 480000 488000 496000 504000 S12000 PTU Annual Reservoir Surveillance Report 2016 Page 9 1 ExxonMobil Figure 2: PTU -15 Injection Pressure and Rate 12600 10000 7500 $A CL 0- 5000 2500 0 PTU -15 Injection Pressure & Rate 260000 200000 150000 100000 50000 1 l/Ju nil 0 21011 u nf 1 a 11 M u 1/10 261.1 u Ill 0 1 OlAu g/l 6 26.?Augfl6 01P/Sep1l6 2-kfSepl1(5 0910 ct/l 6 24.00 ctel 0 0 8! N ov,? 10 23INovilO 08IDecIlO 23fDeol1O 0 Start Time: 281M ayll a 02:48:00 AM Span: 31.0 Weelos E n d Time: 0 VJ a nil 7 03:00:00 AM Description Current Value Units Min Max Scale Aggregate Tolerance * ptP1786001-0i.PV Well #15 Sub Surface Casing 9769.36 PSIG 0 12600 Left Fits 5 * PtPI561001-02.PV PTU 15 Wellhead Prs 0.79347 PSIG 0 12600 Left Fits 5 * ptF156100106.10V PTU 15 Inj Well 9.15463 MSCFD 0 250000 Right Ave ra g e 5 PTU Annual Reservoir Surveillance Report 2016 Page 10 ExxonMobil Figure 3: PTU -16 Injection Pressure and Rate ]ZOW '10000 7500 rR A CL a_ 6000 2500 0 Start Time: 281M ay,(l 0 02:48:00 AM • ptP1786001-02.PV • ptPI662001-08.Pry ptFI552001—OO.PV PTU -16 Injection Pressure & Rate 250000 200000 160000 100000 50000 i imunno ".Ofi u nil a 1 lijulfle 261.1 u lil 6 10/Aug116 25,fAugi16 09!3ep1l6 24'S e pil (5 NfOctfld 2A?Oct?16 OBINovAO 23/Nov/16 0811) e of 10 23YDeol1a w Desoription Well #115 Sub Surface Casing PTU 16 Inj Gas To Inj Well PTU 10 Inj Well Span: 31.15 Weeks E n d Time: 0 l.?J a nil 7 03:00:00 AM Current Value Units Min Max Scale Aggregate Tolerance ('%) 9723.37 PSIG 0 12500 Left Fits 6 8189.79 PSIG 0 12500 Left Fits 6 0 MSCFD 0 250000 Right Average 5 PTU Annual Reservoir Surveillance Report 2016 Page 11 ExxonMobil Figure 4: PTU -15 Mechanical Integrity Test 10000 8000 0000 CL 4000 2000 0 ww 1w 4Q;wQV,110 Zoluoult) ". U 10 c t(l 5 26f0 ot?l 0 2010 ot(l 0 2010 ctil 6 2010 otill 0 215f0 cVl 0 26f0cV10 2010 otel 0 215f0ote1O 00:00:00 PM 06:10:00 PM 06:20:00 PIVI 00:30:00 PM 00:40:00 PM 06:50:00 P M 07:00:00 PM 07:10:00 PIVI 07:20:00 PM 07:30:00 P141 07:40:00 PM 07:50:00 P ful PTU -15 MIT 2610 otfl 6 08:00:00 P ryl Start Time: 42-610 ctil 6 06:00:00 PM Span: 2.0 Hours End Time: 2610cV16 08:00:00 PM Description CurrentValue Units Min Max Scale Aggregate Tolerance (%) • ptPI561001 18.PV — PTU 16 Inner Annulus Prs 0 PSIG 0 10000 Left Fits 5 • PtP156100102.13V PTU 15 Wellhead Prs 8661.22 PSIG 0 10000 Left F its 5 V, PtPI661001-17.PV PTU 15 Intermediate Annulus P 0 PSIG 0 10000 Left Fits 5 N ptPI561001-18.PV PTU 15 Outer Annulus Prs 0 PSIG 0 10000 Left Fits 5 PTU Annual Reservoir Surveillance Report 2016 Page 12 ExxonMobil Figure 5: PTU -16 Mechanical Integrity Test 10000 8000 0000 4000 01000 PTU -16 MIT 0 2610 otfl 0 2t3fOctJ1(3 2010c x'1 0 2010cV16 2010 ct(l 0 2010 otil 8 2610ct/10 2010 cV1 0 26focti"18 2'31OcVT1t5 "A 20fo CV1 a 'refootila 2610 00 0 02:30:00 PM 02:40:00 PM 02:50:00 PM 03:00:00 PM 03:10:00 PM 03:20:00 PM 03:30:00 PM 03:40:00 P 141 03:50:00 PM 04:00:00 PIVI 04:10:00 PM 04:20:00 PM 04:30:00 P rut Start T i m e:2f .6/0 ctil 6 02:30:00 PM Span: 2.0 Hours End Time: 261OcV16 04:30:00 PIVI Description Current Value Units Min Max Scale Aggregate Tolerance (%) • ptPI552001-10.PV PTU 10 Inner Annulus Prs 3.50958 PSIG 0 10000 Left Fits 5 • ptPI5i5200'1-08.PV PTU 16 Inj Gas To Inj Well 8564.90 PSIG 0 10000 Left Fits 5 • ptPI652001-17.PV PTU 16 Intermediate Annulus P 0 PSIG 0 10000 Left Fits 5 ® ptPI552001-18.PV PTU 10 Outer Annulus Prs 0 PSIG 0 '10000 Left Fits 5 PTU Annual Reservoir Surveillance Report 2016 Page 13 ExxonMobil Figure 6: PTU -15 Annulus Monitoring 6( -moo 3000 2000 1000 1 '7 iA .@M 95! e% 11 it 9 PTU -15 Annulus Pressure F r-% F if Iv %J_w M a Y, IV 2 11 imi dr i6 u -row u wi 6 2wi u nn v 1 11jullid 28iJul/10 14fAug/10 311.Augi16 171Sep/16 04IOoVlB 21fOcV16 07,(I4 ov/10 2-1/No' AiB 11fDeo/10 281Deof18 Start Time: 0144,pri16 12:00:00 AM Span: 3!9.2G) Weeks End Time: 31/Dec110 11:43:12 PM Description CurrentValue Units Min tol ax Scale Aggregate Tolerance * ptPI661001_,16.PV PTU 16 Inner Annulus Prs 0 PSIG 0 5000 Left Fits 5 * ptPI561001-17.PV PTU 15 Intermediate Annulus P 0 PSIG 0 6000 Left Fits 6 * PtPI561001-18.PV PTU 15 Outer Annulus Prs 0 PSIG 0 5000 Left Fits 6 1. Initial production 3. MIT pre-test 5. AOGCC MIT 2. Transmitter calibration 4. MIT pre-test 6. Gas injection PTU Annual Reservoir Surveillance Report 2016 Page 14 ExxonMobil Figure 7: PTU -16 Annulus Monitoring 6000 4000 3000 2000 1000 0 PTU -16 Annulus Pressure iii^pvig u--h-maytio �'Ilrviayfllj U71JW16 2i4Jun/18 1 11JuI/18 28iJ u 1/1 (3 14,fAug/10 31/.Auglia 17/Sep/18 0"V0000 21/0oV16 07fNow/10 24/Novila 11IDecI16 28/Dec/10 Start Time: 011,Apr116 12:00:00 ANI Span: 39.2L4 Weeks End Time: 31/Dec116 11:43:12 PM Description Current Value Units Min Max Scale Aggregate Tolerance • ptPI552001 10.PV _ PTU 10 Inner Annulus Prs 0 PSIG 0 5000 Left Fits 5 • ptPI652001 — 17.PV PTU 10 Intermediate Annulus P 0 PSIG 0 5000 Left Fits 5 IN ptPI552001 18. PV PTU 16 Outer Annulus Prs 0 PSIG 0 5000 Left Fits 5 1. Initial gas injection 3. Refill annulus for MIT 5. AOGCC MIT 2. Transmitter calibration 4. MIT pre-test 6. Gas injection PTU Annual Reservoir Surveillance Report 2016 Page 15 1 ExxonMobil Figure 8: PTU -17 Annulus Monitoring 0000 -4000 3000 2000 1000 0 Start Time: 0l/Aprfl@ 12;00:00 AM • ptP158105111B.PV • PtPI501061_17.PV 1. Transmitter calibration 2. Condensate production PTU -17 Annulus Pressure 1ffr-%F1f1w w-wivids-Y11w 4mmidriia ufijuniio z4ijunno 1 lfJul/16 281J u Ill a 14/Aug/16 31/AugflO 17fSep/16 0410cV10 2110ct(16 07!Novi1O 24INovilO 11IDec/16 28/DeellO Description Prod Well Inner Annulus Prs Prod Well Outer Annulus Prs Span: 39.0 Weeks End Time: 3lfDeoll(3 11:43:1.1. PM Current Value Units tul i n Max Scale Aggregate Tolerance 308.843 P S I O 0 5000 Left F its 5 0 P S I O 0 5000 Left F its 5 PTU Annual Reservoir Surveillance Report 2016 Page 16 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION RESERVOIR PRESSURE REPORT 1. Operator: 2. Address: ExxonMobil Alaska Production Inc. PO Box 196601 Anchorage, AK 99519-6601 3. Unit or Lease Name: Point Thomson Unit 4. Field and Pool: 5. Datum Reference: 6. Oil Grav4y: 7. Gas Gravity: Y 8. Well Name and 9. API Number 10. Type 11. AOGCC 12. Zone 13. Perforated 14, Final Test Point Thomson Field, Thomson Oil Pool -12,700' TVDSS 15. Shut -In 16. Press. 37 API 0.7 _ Number: 50XXXXX> XXXXXX See Pool Code Intervals Date Time, Hours Surv. Type 17. B. H. 18. Depth Tool 19. Final Temp. TVDSS 20. Datum 21. Pressure 22. Pressure at NO DASHES Instructions Top - Bottom ( see Observed TVDSS (input) Gradient, psi/ft. P Datum cal (cal) TVDSS instructions for Pressure at Tool Depth codes) Thomson - -- PTU -15 50089200300000 GI 668150 Sand 12622-12804 10/9/2016 918 SBHP 178 10420 9755 Thomson 12700 0.15 10093 PTU -17 50089200330000 0 668150 Sand 12619-12823 10/8/2016 271 SBHP 186 10571 9737 12700 _ 0.16 10089 23. All tests reported herein were made in accordanc with the applicable rules, regulations and instructions of the Alaska Oil and Gas Conservation Commission. I hereby certify that the foregoing is true and cor c o the est of my knowledge. Signature Luke Motteram Title Production Engineer Printed Name Luke Motteram Date February 10, 2016 Form 10-412 Rev. 04/2009 INSTRUCTIONS ON REVERSE SIDE STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION ANNUAL REPORT OF INJECTION PROJECT FOR THE YEAR: 2016 20 AAC 25.432 (2) Name of Operator Address ExxonMobil Alaska Production Inc. PO Box 196601 Anchorage, AK 99519-6601 Unit or Lease Name Field and Pool Point Thomson Unit Point Thomson Field, Thomson Oil Pool Type of Injection Project Name of Injection Project Number of Inj./Conservation Order Authorizing Project Enhanced Recovery (Gas -Cycling) 11nitial Production System (IPS) JAIO # 38 and CO # 719 1. WATER INJECTION DATA As of Jan. 1, active water inj. Water inj. wells added or As of Dec. 31, active water inj. Annual volume water inj. Cumulative water inj. to date wells subtracted Wells + _ 0 0 0 0 0 0 2. GAS INJECTION DATA As of Jan. 1, active gas inj. wells Gas inj. wells added or As of Dec. 31, active gas inj. Annual volume gas inj. Cumulative gas inj. to date subtracted Wells + _ 0 1 2 0 2 7,009,175 7,009,175 3. LPG INJECTION DATA As of Jan. 1, active LPG inj. LPG inj. wells added or As of Dec. 31, Active LPG inj. Annual volume LPG inj. Cumulative LPG inj. to date wells subtracted wells 0 0 0 0 0 0 4. PRODUCTION DATA As of Jan. 1, Total oil wells Oil wells added or subtracted As of Dec. 31, Total oil wells Annual volume oil and/or Cumulative oil and/or condensate produced condensate to date 0 1 0 1 471,645 471,645 As of Jan. 1, Total gas wells Gas wells added or subtracted As of Dec. 31, Total gas wells Annual volume gas produced Cumulative gas to date 0 1 0 0 0 (see above) 8,925,129 8,925,129 5. INJECTION VOLUMES (Reservoir Barrels) Annual Volume Cumulative since project start Water (surface bbls.=reservoir bbls.) (A} 0 0 LPG (Surface bbls.=reservoir bbls.) Indicate type of LPG, Butane, Propane or other. (B) 0 0 Standard CF X volume factor v. where v= Z (Compressibilty factor) X Tr (reservoir temperature, OF absolute) X 14.65 Gas 5.615 cf/bbl. X Pr. (reservoir pressure, psia) X 520 (absolute equivalent at 60°F) (C) 3,363,622 3,363,622 TOTAL FLUIDS INJECTED (reservoir bbls.) (A)+(B)+(C) 3,363,622 3,363,622 6. PRODUCED VOLUMES (Reservoir Barrels) Oil (Stock tank Bbls. X formation volume factor) (D) 471,173 471,173 Free Total gas produced in standard cubic feet less solution gas Gas produced (Stock tank bbls. Oil produced X solution gas oil ratio) X volume factor v calculated for produced gas (E) 4,283,066 4283066.082 Water (surface bbls.=reservoir bbls.) (F) 5,645 5,645 TOTAL PRODUCED VOLUMES (reservoir barrels) (D)+(E)+(F) 4,759,884 4759884 NET INJECTED (+) OR PRODUCED (-) VOLUMES (5.)-(6.) -1,396,262 -1,396,262 Year end reservoir pressure Datum feet psia Subsea 10,093 -12,700 I hereby certify that the foregoing is true 40 correct to the best of my knowledge. Signature: Luke Motterame�yl&n Date: 10 -Feb -16 Printed Name: Luke Motteram Title: Production Engineer Form 10-413 Rev. 12/2003 Submit Original and One Copy