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Home My WebLink About2018 Thomson Oil PoolE;�,ronMobil March 20, 2019 ER -2019 -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 2018 Annual Reservoir Surveillance Report Dear Commissioner Chmielowski, RECEIVED MAR 2 6 2019 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. 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, Jamie Long 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) Exxon Mobil Annual Reservoir Surveillance Report — 2018 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 2018 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)(1) 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 2018 was 0.86 compared to 0.87 in 2017. 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 PTU Annual Reservoir Surveillance Report 2018 Page 1 ExxonMobil 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 115MMscf/d (million standard cubic feet), injection pressure of 10,257 psi was recorded at the downhole gauge December 28, 2018. Equivalent maximum reservoir sand face pressure was 10,565 psi with an injected gas gradient. At PTU -16, a downhole injection gauge pressure of 10,759 psi was measured December 3, 2018 at an injection rate of 1001VIMscf/d. The corresponding maximum sand face injection pressure is 11,143 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. PTU Annual Reservoir Surveillance Report 2018 Page 2 ExxonMobil 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 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. Expansion plans are described in the PTU Plan of Development (POD) dated July 1, 2017, submitted to the Alaska Department of Natural Resources as conditioned by the Point Thomson Unit Letter Agreement, dated September 10, 2018. r i u Hnnuai Keservoir Surveillance Report 2018 Page 3 ExxonMobil 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 r i u Hnnuai Keservoir tiurveillance Report 2018 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) 01/2018 53,216 774 930,821 864,684 0.83 02/2018 156,578 2050 2,837,037 2,755,483 0.87 03/2018 128,702 1682 2,319,999 2,241,474 0.86 04/2018 95,245 1245 1,706,738 1,637,903 0.86 05/2018 177,763 2595 3,257,605 3,164,466 0.87 06/2018 37,257 771 683,955 630,008 0.83 07/2018 2,234 27 34,468 0 0.00 08/2018 2,988 3.1 44,021 0 0.00 09/2018 2,790 0.1 42,359 0 0.00 10/2018 158,999 1977 2,902,769 2,811,141 0.87 11/2018 298,479 3837 5,563,689 5,429,734 0.88 12/2018 332,473 4245 6,180,603 6,023,483 0.88 TOTAL 1,446,724 19,205 26,504,065 25,558,376 0.86 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 2018 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 h1EYEAR'2018 gn e e r a aoo r�r PTU Annual Reservoir Surveillance Report 2018 Page 6 .,- lv Name of Operator Address ExxonMobil Alaska Production Inc. PO Box 196601 Anchorabe, AK 99519-6601 Unit or Lease Name Fold and Pool Point Thomson Unit Point Thomson Field Point Thomson Oil Pool Type of Injection Project Name of Injectsm Project Number of Inj./Conservation Order Authorizing Project 1AI0 Enhanced Recovery(Gas-Cycling)Point T homson Initial Product ion System (IPS) #38 and CO#719 1. WATER INJECTION DATA As W Jan. 1, active water inj. Water iwells addetl or As of Dec. 31, active water Annual volume water inj. Cumulatbe water inj. to date wefts 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 volurne gas inj. Cumulative gas inj. to date wells subtracted Wells 2 0 0 2 25,558.376 64,053,876 3. LFG rVJECTION DATA As of Jan. 1, active LPG inj. LFG inj. w e8s added or As of Dec. 31, Active LPG inj. Annual volume LPG inj. subtracted wells =LPGwells 0 0 000 4. PROWCTION DATA As of Jan. 1, Total 08 w ells Oil w! I's addeEor As of Dec. 31, Tofal oil wells Annual volurre oil and/or Cumulative oil and/or subtracted condensate produced condensate to date I As of Jan. 1, Total gas wells 0 Gas wells addct 1 As of Dec. 31, Total wells 1,446,724 Annual 3,664,670 gas volume gas produced Cumulative gas to date 0 0 0 26,504,065 68,096,193 5. INJECTION VOLUMES (Resevoir Barrels) Annual Volume OrrruW6vesince to ISte Water (surface bbls.=reservoir WIS.) (A) 0 0 LPG (Surface bbls.=reservoir bbls.) Indleatetwe of LPG. Butane, Pmpane orothei (B) 0 0 Sbv�k Z(cm�aessldMtauz)rr (rye 'roar v.wZe w. t X 14M Ga 5— d. %q. (rmbwr paaiv¢, rsial %$2a (alcdda �dvyea a1 @F) (C) 12,283,411 30,767,435 TOTAL FLUIDS INJECTED(reservoir bbls.) (A)+(B)+(C) 12,283,411 6. PRODUCED VOLUMES(Resevoir Barrels) 30,767,435 Oil (Stock tank Bbls. X formation volume factor) (D) 1,445,277 3,661,005 Free Trial m, txvd A 1t,..1d cutic!¢d Imz sdVmn gas Gas P°a=m (smd w, eus. oil Pmmea %zdwm ms dl rstio)%wime !aria v aNdm turPmuxi gas (E) 12,737,912 32,708,365 Water (surface bbls =reservoir bbls.) (F) 19,205 47,160 TOTAL PRODUCED VOLUIvFS(reservoir barrels) (D)+(E)+(F) 14,202,394 36,416,530 NET T)JECTED(+) OR PRODUCED -)VOLUMES -1,918,982 -5,649,094 Year end reservoir pressure Datum feet Pais Subsea 10085 12 700 I hereb certif that the for of is true and correct to the best of know led e. Signature: Kenley Searle Date: �rFasl/6J 2262019 Printed Name: Kenley Scarlett TTllle: P roduc[ion Enydneer PTU Annual Reservoir Surveillance Report 2018 Page 6 ExxonMobil Table 3: Reservoir Pressure Report (Form 10-412) PTU Annual Reservoir Surveillance Report 2018 Page 7 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION 1, Opemb6 RESERVOIR PRESSURE REPORT EmM4abil atilsissFotluctian Inc. , adem5s 3. Unilor Lease Name. eN POBo8198601 Mdnamge, PH 8951&0601 S. stalMmais Unii B. Wellmbee, g. MlNumber Number: 50> q3( NO DPSHES PTU.15 50008200300000 PTU -15 50089200300000 PTU -1050089200310000 PTU -16 50008200310000 PTU -17 50DH9200330000 PTU -17 50088300J30000 l - T1-10 bee InSWctiona a GI GI GI O O PoOI Cod ICod 888150 688150 660150 668156 668150 068150 L Field and PoaL S.Dan— R¢lererce: Pai-TMm¢en F1.W,Tpem¢enW Paul-12jo0'TDSS 1228ne f3,PeRmaletl 14.Finalieal 15. Sh.-In 1. Fie. 1]$H, iB.DepN I9. Fine l /annals Data Time,ours Su,,Tpe Temp. ioa1 TVDSS Cbseeuetl Top Tend (stt Press. at MS6 insit ns Tool Depth Mm¢on for as a)) Sam 12622-12804 10/1/1018 2608 SBHP 1]] 10420 0053 al Sand au 12622-12001 1011MG10 195 SBNP - 10120 8]58 Sand au 12]6'J-12908 gQI/2016 2852 SDNP 1)0 10022 9]14 Sand so 1276112000 fOIIWO18 33 SBHP 170 10022 9125 bend BO 12619-12823 10114618 2890 SBHP 311 1.5710]30 bend rainson 12611)-12623 101132018 BB SBHP 214 10571 9733 6. at GasWy 3T IPI 2D. Datum 14DSS (input) 12]00 f2]aB 12]00 12700 12]00 12700 7, Cas GmNly 021, Pre¢sum Bmtlian0 p5iM. 014 o14 014 0.14 0,16 0.18 22 Pre¢sureat Datum lnl) 10089 iBDT4 10068 10087 10085 10084 2 ,Mama, repoded herein were made in acmrdancewim Ne applicable Mies, regulation¢ and malmc8ons ofOro Ne ab Client Gas Conseredon Commission. I llanbyceltifygat Wekrepoiy is Sue em wneclb Me beslof myknowledge. Si9namse P 4&..au. TrYe RneroirEyincer PnMetl Name Jennifer AJnew Dale February20,2019 PTU Annual Reservoir Surveillance Report 2018 Page 7 ExxonMobil Table 4: Annual Reservoir Properties Report (Form 10-428) ,Gpwamr . . STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION ANNUAL RESERVOIR PROPERTIES REPORT aem AIUW RO NonYi¢, 3. Fetl mE Pool O. WOI Nv�e °' flnl lMurem i PNemmce dlmnlll NL\SS) B. TerrpraWe 1°F) 2.AMe¢a: W Bon 16 1Amhwp AK WSI1 WD1 ]. Po�wilY 8. ibrrwlpN 9 S4i 1%1 iD, QI tt. pl 12..vm 13 Wbbb 19. dnenl 15.OY 18. Gac ,). Gwa ,B. NN Por %) Intl) Vi¢cwilr� Vu¢wilY@ Roawe Pohl br Re¢ervob f?avilV Specfc MY l,ll (IO prynal NWrapm (pail Cew1 nl Reaaure ('qRl GeavilY (q'vCmpea¢aSN Rbaawe Rpawe lcp) Re¢¢ure IWi) „D (W) (Pai) 19 pgnal Fw�reton VOLnv F-.la&5181 IF&SIB) 20. B�Wb Nwn1 2,. Gea 22 R Faimtim 9^al 23. W,,. WR13CF5iB)GGR(3fF51B1 YcAme Feclnr Faclo ( 2) 888150 lbwrmon Cl4Ed .121W 230 15 1W 62 1.81 1.81 101W 10100 1WB5 37 07 23 235 00029 0 15 20.W0 1&339 MrMy p�Wy Pal the lcrwpiq iv bue antl �cw—1 blb b¢Idam�/Fro�wl>eEpa� 5$iulive Kwu.r sce,lm MLu��wLf.�U rnW Rpa,awnr 96..e. Ringo rare Kanbv sparbB ab Fab—v M. z01e PTU Annual Reservoir Surveillance Report 2018 Page 8 ExxonMobil Figure 1: Thomson Reservoir Pressure Map c 406000 416000 42:000 432000 44nnnn 44nnnn eccnnn .,,,,,, .. 4 PTU_1 10074 VJSTN_1 AK C1 O Producer A Injector 0 10085 Shut-in Bottomhole Pressure psia S '{ H CNAL ISL 1 1 o 0 4 �.l � AK F1 N ---- 10084 n Pzt1-4 _77 i PTU -2 4 PTU_1 10074 VJSTN_1 AK C1 O Producer A Injector 0 10085 Shut-in Bottomhole Pressure psia S '{ )97 .uowV raoVVU J04000 5120 K_G2 >F AK Al N 57NS_1RD A STNS -1 SOUR -2 raouuu 456000 504000 512000 PTU Annual Reservoir Surveillance Report 2018 Page 9 0 1 2 3 4 5miles 406000 416000 424000 432000 44nnnn ---- )97 .uowV raoVVU J04000 5120 K_G2 >F AK Al N 57NS_1RD A STNS -1 SOUR -2 raouuu 456000 504000 512000 PTU Annual Reservoir Surveillance Report 2018 Page 9 ExxonMobil Figure 2: PTU -15 Injection Pressure and Rate 250C 1250[ xHQ Trend 1 03:00:00 AM 03:00:00 AM 04:00:00 AM 04:00:00 AM 04:00:00 AM 04:00:00 AM 04:00 00AM 0400:00 AM 04:00:00 AM 04:00:00 AM 0390 00 AM 03 00'.00 AM 03 00 00 AM Start Time: 01JJun/18 12:00:00 AM Span: 52.142854142857148 Weelrs Scooter Time: 191Febf18 11:20:02 Ph1 Description End Time: 0lJJanf1812:00:00 AIA • ptP1785001 01.PV Scooter Value Current Value Units Min MaxScale A Aggregate Tolerance(%) Well Mi5 Sub Surface Caring( 084051 10230.7 PSIG 8800 ID600 Left ■ ptP1561001 02.PV PTU 15 Wellhead Prs 8572.29 8512.50 PSIG Fits 5 • ptF1581001 OB.PV 151nj Well (IASCFD) 0 12500 Left Fits 5PTU 51304.5 114128 HSCF/D 0 250000 Right Fits 5 PTU Annual Reservoir Surveillance Report 2018 Page 10 ExxonMobil Figure 3: PTU -16 Injection Pressure and Rate 2001 2501 0 8500 28fJa.119 7FI[n4119 fr XHQ Trend 250000 03:00:00 AM 03:0000 AM 04:00:00 AM 04:00:00 AM 04:00:00 AM 04:00 00 AM 04:00 001AM 0400:00 AM 04:00 00 AM 04 00 00 AM 03 00.00 AM 0300:00 AM 03 00 00 AM Stall Time: 01fJanl18 12:00:00 AM Span: 52.142867142857145 Weeks Scooter Time: 044an.118 10:24:20 AM Description End Time:O/ganflB 1200:00 AM ■ ptP1585001 02.PV Well 018 Sub Surface Casing Scooter Value Cuuent Value Units Min Max Scale q BBreBate Tolerance (X) ■ 552001OB.PV 0( 9119.1] 10875.3 PSIG 9500 12000 Lek Fits 5 _ PTU 181nj Gas To Inj Well 825102 8852.18 PSIG 0 PV1 • tF1552001_OB.PV PTU 10 Inj Well (b1SCFD) 12500 Left Fits 5 0 87001.8 kSCFfD 0 250000 Right His 5 PTU Annual Reservoir Surveillance Report 2018 Page 11 ExxonMobil Figure 4: PTU -15 Annulus Monitoring 000 500 Doo 500 Jan 25. 18 Feb 19 18 Aon. to ra n — XHQ Trend 03:00 03:00 - - - -• --' - 04:00 0400 04:00 04:00 -- • ^ •- u nug ia, 10 aeP U/, 1U Oc102. 18 Oct 27, 18 Nw21, 18 Dec 10. 18 04:00 0400 04:00 04:00 0400 04:00 03:00 03:00 Start Time: O1/Jarv18 12:0090 AM Span: 52.142857142857140 Weed¢ Scooter Time: O11Jan/18 09:22;41AM Description End Time: 011Jann9 12:00:00 AM • ptP15PV 10011 PTU 15 Inner Annulusrs P Scooter Value Current Value Units Min Mar Scale Aggregate Tolerance(%) 61001 R, ■ ptP15PV PTU 15 Intermediate Annulus P 0 1300.34 PSIG 0 2500 Left Fin 5 • PtP1501001_18.PV PTU 15 Outer Annulus Prs 0 403.417 PSIG 0 2500 Lek Fit 50 PSIG 0 2500 Lek Fit 5 PTU Annual Reservoir Surveillance Report 2018 Page 12 ExxonMobil Figure 5: PTU -16 Annulus Monitoring 009 500 ]00 013 Ian 9fi to C.n to 1. —. .a m XHQ Trend 03:00 03:00 04:00 04:00 04:00 .,,-1. lo am In. to Aug 13. 18 Sep 07, 18 Oct 02. 18 Oct 27, 18 Na, 21. 18 Dec 18, 18 0400 04:00 04:00 04:00 04:00 04:00 04:00 03:00 03:00 Start Time: U1fJanfl8 12:00:00 AM $Pan: 52.142857142857148 Weal¢ Scooter Time: OlfJaV 18 12:90:00 AM Description End Time: 01/Jan/19 12:00:00 AM IN ptP1552001_15.PV PTU 18 lnner Annulus Pis Scooter Value Count Value Units Min Max Scale A Aggregate Tolerance (Y) ■ ptP1552001 17.PV PTU 10 Intermediate Annulus P 0 1541.31 PSIG 0 2590 Left Fie 5 • ptP155200118.PV PTU 16 Outer Annulus Pi, 0 782.9+10 10 2500 Left F 5 ks 0 0 PSIG 9 2500 Left Fits 5 PTU Annual Reservoir Surveillance Report 2018 Page 13 ExxonMobil Figure 6: PTU -17 Annulus Monitoring xHo Trentl rUuu. sono B0o0 4000 !000 0 1 1 Jan 25. 18 F.419, 18 Mar 16, 18 Apr 10. 18 Mav05 18 ...un m . w:uu 43:00 04:000400 04:00 04:00 04:00 04:00 V ^V0400'a 'e04:001a 0 0027. No0v21.30016 De0310018 04:0018 04:0018 Start Time: 01fJao118 1200:00 AM Span: 52.14285714285, 146 Weal¢ Scooter Time:OlJJan/18 06:40:,, pM Description End Time: U 12:0000 ■ PtP1561051_17.PV Prod Well Inner Annulus Per Scooter Value Current Value Units Idin hia. Scale Aggregate ce ate Talennce (X) • RtP1581051 17.PV — Prod Well Outer Annulus Pm 672.422 1600.98 PSIG D 10000 Lett Fite Fib 5 0 PSIG 0 10000 Left Fit 5 PTU Annual Reservoir Surveillance Report 2018 Page 14 1. Operator: Exxon Mobil Alaska Production Inc. 3. Unit or Lease Name: Point Thomson Unit 8. Well Name and 9. API Number 10. Type Number: SOXXXXXXXXXXXX See NO DASHES Instructions 11. AOGCC PoolCade STATE ALASKA OIL AND GAS RESERVOIR PRESSURE 12. Zone 13. Perforated 14.Final Test Intervals Date Top-Bottom(see OF ALASKA CONSERVATION COMMISSION REPORT 2. Address: PO Box 196601 Anchorage, 4. Field and Pool: Point Thomson Field, Thomson Oil Pool 15. Shut-In i6.Press. 17. B.H. Time, Hours Sul. Type Temp. instructions forool AK 99519-6601 e: 6. Oil Gravity: 37 API 7. Gas Gravity: 07 j,00'TVDSS 19. Final Observed ressure atTVDSS Depthodes)ThomsonPTU-15 20. Datum21Pressure TVDSS (input) Gradient, psi/ft. 22. Pressure at Datum (cal) PTU-15 PTU-16 PTU-16 50089200300000 50089200300000 50089200310000 50089200310000 50089200330000 50089200330000 GI GI GI GI O O 668150 668150 6fi8150 668150 668150 668150 Sand Thomson Sand homson Sand Thomson Sand Sand Sand 12622-1280410/1/2018 12622-12804 12763-12908 12763-12908 12619-12823 12619-12823 10/18/2018 9/24/2018 10/13/2018 10/1/2018 10/13/2019 2698 195tSB 2652170 33170 2698211 99214 SBHP 177 175 53 12700 0.14 10069 10420 10022 9758 9714 12700 12]00 0.14 0.14 10074 10086 10022 9725 12700 014 0097omsonFTU-P 10571Thomson 9734 12700PTU-17 10571 9]33 12700 0.16 10084 23. All tests reported herein were made in accordance with the applicable rules, regulations andinstructions 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 ,yua,,.,. Title Reservoir Engineer Printed Name Jennifer Agnew Date February 20, 2019 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: 2018 20 nnr 7c n Submit Original and One Copy 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 Eield, Point Thomson Oil Pool Type of Injection Project Injection Project Number of Inj./Conservation Order AuthorizingProjectEnhanced TNamef Recovery (Gas -Cycling) omson 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 inj. Annual volume water inj. Cumulative water inj. to date wells subtracted Wells 1 0 p 0 0 0 p 2. GAS INJECTION DATA As of Jan. 1, active gas inj. wells Juas inj. wells added or As of Dec. 31, active gas inj. Annual volume gas inj. Cumulative gas inj. to date subtracted Wells 2 0 0 2 25,558,376 64,053,876 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 p 4. PRODUCTION DATA As of Jan. 1, Total oil wells it wells added or subtracted oil wells Annual volume oil and/or Cumulative oil and/or :Asof:Dec-:31,tal condensate produced condensate to date As of Jan. 1, Total gas wells 00 Gas wells added or subtracted As of Dec. 31, Total gas wells 1,446,724 Annual volume gas produced 3,664,670 Cumulative gas to date 0 0 0 0 26,504,065 68,096,193 5. INJECTION VOLUMES (Resevoir Barrels) Annual Volume Cumulative since ro'ect 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 TXvolume factor v. where v= ctor) X Tr (reservoir temperature °F absolute) X 14 65 12,2$3,411 rvoir pressure X 520 (absolute equivalent at 60°F) (D) 30,767,435 kGa ir bbls.) (A)+(B)+(C) 12,283,411 6. PRODUCED VOLUMES (Resevoir Barrels) 30,767,435 ck tank Bbls. X formation volume factor) (D) 1,445,277 3,661,005 Free Total gas produced in standard cubEpmduced Gas produced (Stock tank bbls. Oil protll ratio) X volume factor v calculat(E) 12,737,912 32,708,365 Water (surface bbls.=reservoir bbls.) (F) 19,205 47,160 TOTAL PRODUCED VOLUMES (reservoir barrels) (D)+(E)+(F) 14,202,394 36,416,530 NET INJECTED (+) OR PRODUCED (-) VOLUMES (5.)-(6.) -1,918,982 -5,649,094 Year end reservoir pressure Datum feet psia Subsea I hereb certi that the foregoino is true and correct to the best of m knowled e. 10085 -12,700 Signature: Kenley Scarlett YapL4 6 Date: Lcc b( 2/262019 Printed Name: Kenley Scarlett Title: Form 10-413 Rev 19)9nn¢ Production Engineer Submit Original and One Copy 1. Ophumtar. EmnModl Masks Pmdunam Inc. 3. Field aM Pmt •. Pool Name Cane: PoinlTMmaon W8150 TMmson OR Pool- 5, Reference B. Temmeamme ), lemmy Datum (n IT) )%) 1W53) -12,700 230 15 B. Permeaw (md) Ilp STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION ANNUAL RESERVOIR PROPERTIES REPORT z. Adarese'. fl Swi (%) IO. Oi Po 1 IOyXB01 1 Ofmge,lAK13. BUGhIe01 I<, Cunenf 15.Oi1 1B. Ges V®c gins cstY� VbcmLY® Preuure Poen or0aw Reserwlr GaMy Slzcde Original Salummon au) Poinr P, heAPI (' ) Gmdy(A = Pressure Pressure lcp) pressure (cp) (Pei) (Psi) 10) 42 181 1.01 10100101W IOO85 W 0] 1). Grwa pa X y(I 235 18. Ne[ Pa 19 O y n9mal (X) Formation Volume ent., ) RM fT0 235 00029 20. Bubble Pon121. Gas Fommibn ComptessidlXy Volume Factor Facror(Z) (FOISTS) 0 1.5 22.OrginalGOR 23. Current (SCFSTB ) GOR(3CFISTB) 20.W0 10,338 M[c�or d/blM bej�of my kmwledge. IM1¢reby caddy that the himahg m true==10"i SgNHmd Norley Scad&t /(/MA'wn VI /n ]_�" _-0" / - Title Pumumen Eng eer P. Name Henley S_,. Data Febuary28,2019