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Home My WebLink About2017 Thomson Oil PoolJP i %! 4.i ia; 3> $ i „t4• � i?.;G i-n`iM?'`bY ,� Ae'i', et §Alan =a:.de 907 !-564 5331 E*(onMobil. March 19, 2018 ER -2018 -OUT -060 Mr. Hollis S. French, Chair Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue, Suite 100 Anchorage, Alaska 99501-3572 Re: Point Thomson Unit 2017 Annual Reservoir Surveillance Report Dear Commissioner French, MAR 2 3 2018 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 Luke Motteram at (907) 564-3697. Sincerely, Jamie Long For and On Behalf of ExxonMobil Alaska Production Inc. CC: I m 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 Annual Reservoir Surveillance Report — 2017 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 2017 for the Initial Production System (IPS) facility. 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 2017 are summarized in Table 1. Voidage replacement ratio in 2017 was 0.87 compared to 0.71 in field startup year 2016. 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. PTU Annual Reservoir Surveillance Report 2017 Page 1 ExxonMobil 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. 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 111 MMscf/d (million standard cubic feet), injection pressure of 10,245 psi was recorded at the downhole gauge October 9, 2017. Equivalent maximum reservoir sand face pressure was 10,575 psi with an injected gas gradient. At PTU -16, a downhole injection gauge pressure of 10,672 psi was reached November 11, 2017 at an injection rate of 102MMscf/d. The corresponding maximum sand face injection pressure is 11,082 psi using 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. Declining PTU -16 injectivity was observed in May 2017, believed to be caused by plugging of the gravel pack completion. Flowback cleanup of the well was effective in restoring injection capacity with no reoccurrence of the issue observed. Mechanical Integrity Test (MIT) Results —Rule 8(fl No mechanical integrity tests were performed during the reporting period. PTU Annual Reservoir Surveillance Report 2017 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 ;,^,pith Area Injection Order No. 33, Rule 5, and Conservation Order No. 719, Rule 7. Digital continl Inl m nrP_CCI IrA mnnif'nrinn is incfnllorl r%M r,�r%k •�r,r,o .I. .,-r r)--1 n-ri i A n r..■ vvvv.. v ...tl...LVI 11 ly IV 11 1,)LLA11Vu %ii I cat.JI I Q� 11 JUJU) LJ r- I V I J, Piu-iuand 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. PTU Annual Reservoir Surveillance Report 2017 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 PTU Annual Reservoir Surveillance Report 2017 Page 4 ExxonMobil Table 1: Monthly Production, Injection and Voidage Balance Summary Month Condensate (STB) water (STB) Dry Gas Production (MSCF) Dry Gas Injection i (MSCF) 01/2017 236,667 3,202 4,458,103 4 330 263 V2/2V 1 I 20, 7 5 7 249 3991550 3371753 03/2017 1957395 27574 31714,478 3,5787412 04/2017 192,487 21209 35602,139 37482,618 05/2017 929795 11305 177247885 116455352 06/2017 81400 103 155,883 129,879 07/2017 53,903 671 9817229 922,416 08/2017 2111248 27586 318987251 31766,855 09/2017 50,092 574 891,894 828.113 10/2017 2321249 31032 4,3071306 41179,198 11/2017 2871261 31634 574467402 51295,588 12/2017 1657047 21171 37086,881 279897877 TOTAL 11746,301 22,310 32,666,999 31,486,325 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 VRR (RB/RB) 0.87 �� O A I 1111168YA 0.86 0.75 0.84 0.87 n wi we A W O A 0.87 PTU Annual Reservoir Surveillance Report 2017 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: 2017 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) Initial Production System (IP S) AIO # 38 and CO # 719 1. WATER INJECTION DATA As of Jan. 1, active w ater inj. Water inj. w ells added or As of Dec. 31, active water Annual volume water inj. Cumulative w ater 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 2 0 0 2 1 31,486,325 1 38,495,500 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 wells Oil wells added or As of Dec. 31, Total oil wells Annual volume oil and/or Cumulative oil and/or subtracted condensate produced condensate to date 1 0 0 1 1,746,301 2,217,946 As of Jan. 1, Total gas wells Gas wells added or s ubtractE As of Dec. 31, Total gas wells Annual volume gas produced Cumulative gas to date 0 0 0 1 0 (see above) 32,666,999 41,592,128 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 CFXvolume factor v where � Z (Compressibilty factor) X Tr (reserwir temperature, OF absolute) X 14.65 Gas 5.615 cf/bbl. X Pr. (reservoir pressure, psia) X520 (absolute equiwlent at 60-F) (C) 15,120,402 18,484,024 TOTAL FLUIDS INJECTED (reservoir bbls.) (A)+(B)+(C) 15,120,402 18,484,024 6. PRODUCED VOLUMES (Reservoir Barrels) Oil (Stock tank Bbls. X formation volume factor) (D) 1,744,555 2,215,728 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) 1 15,687,3 87 19,9701453 Water (surface bbis.=reservoir bbls.) (F) 22,310 27,955 TOTAL PRODUCED VOLUMES (reservoir barrels) (D)+(E)+(F) 17,454,252 22,214,136 NET INJECTED (+) OR PRODUCED (-) VOLUMES (5.)-(6.) -2,333,849 -3,730,111 Year end reservoir pressure Datum feet psia Subsea 10,085 -12,700 I hereby certify that the foregoing is true and correct to the best of know edge. Signature: Luke Motteram Date: 16 -Feb -18 Printed Name: Luke Motteram Title: Production Engineer PTU Annual Reservoir Surveillance Report 2017 Page 6 ExxonMobil Table 3: Reservoir Pressure Report (Form 10-412) PTU Annual Reservoir Surveillance Report 2017 Page 7 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION RESERVOIR PRESSURE REPORT 1. Operator: 2. Address - Alaska Production Inc. PO PO Box 196601 Anchorage, AK 99519-6601 3. Unit or Lease Name: 4. Field and Pool: 5. Datum Reference: 6. Oil Gravity: 7. Gas Gravity: Point Thomson Unit Point Thomson Feld, Thomson Oil Pool -12,700' TVDSS 37 API 0.7 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 Number: 50XXXXXXXXXXXX NO DASHES See Pbol Code Intervals Date Time, Hours Surv. Type Term. Tool TVDSS Observed TVDSS (input) Gradient, psi/ft. at Datum (cal) Instructions Top - Bottom (see Pressure at TVDSS instructions Tool Depth for codes) Morrison PTU -15 50089200300000 GI 668150 Sand 12622-12804 7/18/2017 1056 SBHP 177 10420 9767 oms-on 12700 0.14 10083 PTU -15 50089200300000 GI 668150 Sand 12622-12804 9/24/2017 424 SBHP 176 10420 9769 Morrison 12700 0.14 10085 PTU -16 50089200310000 GI 668150 Sand 12763-12908 7/18/2017 1056 SBHP 171 10022 9722 omson 12700 0.14 10094 PTU -16 50089200310000 GI 668150 Sand 12763-12908 9/24/2017 424 SBHP 171 10022 9722 omson 12700 0.14 10095 PTU -17 50089200330000 0 668150 Sand 12619-12823 7/18/2017 155 SBHP 199 10571 9734 Morrison 12700 0.16 10084 PTU -17 50089200330000 0 668150 Sand 12619-12823 9/24/2017 184 SBHP 197 10571 9732 12700 0.16 10083 23. All tests reported herein w ere made in accordance w ith 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 know ledge. Signature Luke Nbtteram Title Production Engineer Printed Name Luke Nbtteram Date February 16, 2018 PTU Annual Reservoir Surveillance Report 2017 Page 7 ExxonMobil Table 4: Annual Reservoir Properties Report (Form 10-428) STATE OF ALASKA - ALASKA OIL AND GAS CONSERVATION COMMISSION ANNUAL RESERVOIR PROPERTIES REPORT 1. Operator: 2. Address: — ExxonMabil Alaska Production Inc. PO Box 196601 Anchorage, AK 99519-6601 3. Feld and Fool 4. Fool Name 5. Reference 6, 7, Porosity 8. Permeability 9. Swi (%} 10. Oil 11. Oil 12, Original 13. Bubble 14. Current 15. Oil 16. Gas 17. Gross 18. Net Pay Code: Datum (ft Temperature M (md) Viscosity @ Viscosity @ Pressure Point or Reservoir Gravity Specific Pay 19. Original 20. Bubble Point 21. Gas 22. Original 23. Current (ft) (ft) TV DSS) (°F) Original Saturation (psi) Dew Point Pressure ('A P) Gravity Formation Formation Compressibility GOR (SCF/STB) GOR (SCF/STB) (Air Pressure Pressure (cp) Pressure (psi) Volume Volume Factor Factor (Z) = 1.0) m oFFon (cp) (psi) Factor (RB/STB) (RB/STB) 668150 Thomson Oil Pool -12,700 230 15 100 42 1.81 1.81 10100 10100 10085 37 0.7 235 235 0.0029 0 1.5 20,000 20,000 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 27, 2018 PTU Annual Reservoir Surveillance Report 2017 Page 8 ExxonMobil Figure 1: Thomson Reservoir Pressure Map 408000 416000 4244000 43-200-0 440000 44v --C-0 50 -CO g 464000 472001 48000 �0 00 504-000 5120W c :�( �sAyu3Ts.srfYr hi .imA..3 iIIsssDv.. �.dL.vihv�rK#sHrvsi r,R.fii.)r 3.i.sY svp�.iAv.Y3r%A�.iH ssa g i�.,�e,' �-rA�uYav� .mCv�i✓.�AurY�„sA�.r� �� vhtY�isvYiv �iyA.vcD3ss3ui�.ArvAirsiuA,�Miac�� A� 'elF d s ... C> C, L n z AL Injector 'lo- 3 4 Smiles r .. 4=111.10 160-00 444000 433200-0, 4 COCC- 44800-0 4560,0, 46400-0 47200-0 4 O-0 0 488000 496000O-4 0 2`00 PTU Annual Reservoir Surveillance Report 2017 Page 9 ExxonMobil Figure 2: PTU -15 Injection Pressure and Rate 10000 7500 CL CL 5000 2500 0 PTU -15 Injection Pressure & Rate 250000 200000 150000 ,4- .M It 100000 50000 U zvj a nri t enii i 1Jfrv1arf17 06,%pr/17 30/Ap r,;'l 7 24/May/17 171Jun/17 l 1 IJ u Ill 7 OWAugf17 28.(Augil7 2lfSepl17 1510 ctf, 17 OWN ov,01 7 02fDec/17 216/Dec/17 Start Time: 0 1 IJ a n/l 7, 12:00:00 AM Span: 52.142857142857146 We0s End Time: 01.0anf1B 12:00:00 AM * ptP1785001 Ol.PV Description Current Value Units Min Max Scale Ag g re g ate Tolerance * ptl`1561001 — 02.PV Well #15 Sub Surface Casing 9762. 10 PSIG 0 12500 Left Fits 5 PTU 15 Wellhead Prs 8175.11 PSIG 0 12500 Left Fits 5 * ptF156100106.13V PTU 15 Inj Well 0 MSCFD 0 250000 Right Ave ra g e 5 PTU Annual Reservoir Surveillance Report 2017 Page 10 ExxonMobil Figure 3: PTU -16 Injection Pressure and Rate 12500 10000 7500 CL 5000 2500 0 PTU -16 Injection Pressure & Rate '150000 200000 150000 Cr 100000 50000 z -+w a w" i t 'wft e fill 13frular.07 0 15,fA p rf 17 30/Apr.?l7 24fMay/17 17/Juni,17 1 VJ u Ill 7 041Aug/17 281.Augfl7 21/Sepfl7 l5!OoVl7 08/Nov,,'17 02fDec/17 1.15IDeell'o Start Time: Ol/Janfl7 12:00:00 AM Span: 52.142857142857146- We elks End Time: 01 Qanfl8 12:00:00 AM Description Current Value Units Min M ax Scale -Aggregate Tolerance * ptP 178500102. PV Well #115 Sub Surface Casing 9720.20 PSIO 0 12588 Left Fits 5 * ptPI552001-08.PV PTU 16 Inj Gas To Inj Well 7706.77 PSIG 0 12500 Left Fits 5 * ptFI552001—OC.PV PTU 115 Inj Well 0 MSCFD 0 250000 Right Average 5 PTU Annual Reservoir Surveillance Report 2017 Page 11 ExxonMobil Figure 4: PTU -15 Annulus Monitoring 4000 :3000 kA CL 2000 1000 0 PTU -15 Annulus Pressure -L,wj a nil i r ioir eD.C1 e i w rvgar l i 02fApr 1 7 25/,Apr.117 18fMa-i yf 17 10.0 u nil 7 03.0 u 1/17 26.0 u Ill 7 18.?Au gf 17 1 OfS e pf 17 0310 ct(l 7 26i0cV17 18fNov/17 1lfDee/17 Start Time: 01fJanf17 12:00:00 AM S p a n: 52.142857142857146 We ek's End Time: O1/Jan/18 12:00:00 AM • PtPI5151001 lL9.PV Description Current Value Units Min Max Scale Aggregate Tolerance • ptP 166 1001 17.PV PTU 15 InnerAnnulus Prs 0 PSIG 0 5000 Left Fife 5 PPTU 15 Intermediate Annulus P 0 PSIG 0 5000 Left Fits 5 PtPI58100118.13V PTU 15 Outer Annulus Prs 0 PSIG 0 5000 Left Fits 5 PTU Annual Reservoir Surveillance Report 2017 Page 12 ExxonMobil Figure 5: PTU -16 Annulus Monitoring 5000 4000 3000 rz, IA 2000 1000 0 PTU -16 Annulus Pressure .i-olodlje I 1 10)1- ears I e I U JJ1 rul a Y1 t U 2 fAk p rf 17 25.fAp rfl 7 18fIVIxy.(17 10fJun/17 03YJul/17 26M u 1/17 18,;Au gf 17 10/Sep/17 0310W1 7 2610 cV1 7 18f N ov/1 7 11fDec117 Start Time: 01fJan117 12:00:00 AM Span: 52.142857142857146 'Weeks End Time: OVJan/18 12:00:00 AM • ptPI552001_1 09.13V Description CurrentValue Units Kolin Pular Scale Aggregate Tolerance (%) PTU 16 Inner Annulus Prs 0 PSIG 0 5000 Left Fits 5 • ptPI552001-17.PV PTU 10 Intermediate Annulus P 0 PRIG 0 5000 Left Fits 5 V.w " ptP 1552001 _18. PV PTU 16 Outer Annulus Prs 0 P8G 0 5000 Left F its 5 PTU Annual Reservoir Surveillance Report 2017 Page 13 ExxonMobil Figure 6: PTU -17 Annulus Monitoring 501 4000 3000 IA CL CL 2000 1000 PTU -17 Annulus Pressure Aw--.Prsj CI Ile I e I;-,. r ewil i i 1 uk, cars. -i tr u 41 hi9k p v I 1 21 5 f)k p rf 17 18f M ayll 7 1 0,Q u nfl 7 03fJ u If 17 26fJ u Ill 7 1 81.Au g1l 7 1013epfl7 0310 ct(l 7 2610 et/17 181N ovil 7 ll/Decfl7 Start Time: 01/Jan/17 12:00:00 AM • PtPI561051 16.PV • PtPI561051-17.PV Span: 52.142E5er 1= 2857 146 Weeks Description CurrentValue Units Prod Well Inner Annulus Prs 800.488 PSIG Prod Well Outer Annulus Prs 0 PSIG Min May 0 5000 0 5000 Scale Left Left End Time: 01/JanflB 12:00:00 AM Aggregate Tolerance (%) Fits 5 Fits 5 PTU Annual Reservoir Surveillance Report 2017 Page 14 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 Gravity: 7. Gas Gravi : � 8. Well Name and 9. API Number 10. Type 11. AOGCC 12. Zone 13. Perforated 14. Final Test Point Thomson Field, Thomson Oil Pool 15. Shut -In 16. Press. -12,700' TVDSS 37 API 0.7 Number: 50 See Pool Code Intervals Date 17. B.H. Time, Hours Surv. Type Temp. 18. Depth Tool 19. Final TVDSS �?0. Datum 21. Pressure 22. Pres sure at NO DASHES Instructions Top - Bottom Observed TVDSS (input) Gradient, psi/ft. Datum (cal) (see Pressure at TVDSS instructions for Tool Depth codes) PTU -15 50089200300000 GI 668150 omson Sand 12622-12804 7/18/2017 1056 SBHP 177 10420 9767 12700 Thomson 0.14 10083 PTU -15 50089200300000 GI 668150 Sand _ms 12622-12804 9/24/2017 424 SBHP 176 10420 9769 12700 0.14 oon 10085 PTU -16 50089200310000 GI 668150 Sand 12763-12908 7/18/2017 1056 SBHP 171 10022 9722 12700 0.14 omson 10094 PTU -16 50089200310000 GI 668150 Sand 12763-12908 9/24/2017 424 SBHP 171 10022 9722 12700 0.14 omson _ 10095 PTU -17 50089200330000 O 668150 Sand 12619-12823 7/18/2017 155 SBHP 199 10571 9734 12700 0.16 Thomson 10084 PTU -17 50089200330000 O 668150 Sand 12619-12823 9/24/2017 184 SBHP 197 10571 9732 12700 0.16 10083 23. All tests reported herein were made in accordance with the applicable rules, regulation nd instructions of the Alaska Oil and Gas Conservation Commission. 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 16, 2018 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: 2017 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 Po�t � hQm„con i Tnit Point Thomson Field, `Thomson Oil Pool Type of Injection Project Name of Injection Project Number of I nj ./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 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 21 0 0 2 31,486,325 3854955500 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 10il wells added or subtracted As of Dec. 31, Total oil wells Annualvolume oil and/or Cumulative oil and/or condensate produced condensate to date 1 0 0 1 15746,301 Annual volume gas produced 212175946 Cumulative gas to date As of Jan. 1, Total gas wells Gas wells added or subtracted As of Dec. 31, Total gas wells 0 0 0 0 (see above) 1 32065999 4155925128 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) Standard CF X volume factor v. where v= Z (Compressibilty factor) X Tr (reservoir temperature, °F absolute) X 14.65 Gas 0 0 5.615 cf/bbl. X Pr. (reservoir pressure, psia) X 520 (absolute equivalent at 60°F) (C) 1551205402 18 484 024 TOTAL FLUIDS INJECTED (reservoir bbls.) (A)+(B)+(C) 155120,402 18,484,024 6. PRODUCED VOLUMES (Reservoir Barrels) Oil (Stock tank Bbls. X formation volume factor) (D) 1,744,555 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) 15,687,387 Water (surface bbis.=reservoir bbls.) (F) 22,310 TOTAL PRODUCED VOLUMES (reservoir barrels) (D)+(E)+(F) 1714541,252 NET INJECTED (+) OR PRODUCED (-) VOLUMES (5.)-(6.) -2,333,849 Year end reservoir pressure psia 10,085 I hereby cerUly that the foregoing is true an orrect to the best of my knowledge. Signature: Luke Motteram Lie Date: 16 -Feb -18 Printed Name: Luke Motteram Title: Production Engi Form 10-413 Rev. 12/2003 2,215,728 19,970,453 27,955 221214J36 -3,730,111 Datum feet Subsea -12,700 Submit Original and One Copy Form 10-428 Rev. 05/2017 INSTRUCTIONS ON REVERSE SIDE STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION 1. Operator: ANNUAL RESERVOIR PROPERTIES REPORT 2. Address: - ExxonMobil Alaska Production Inc. 3. Field and Pool 4. Pool Name 5. Reference 6. Temperature 7. Porosity 8. Permeability PO Box 196601 Anchorage, AK 99519-6601 9. Swi (%) 10. Oil 11, Oil Code: Datum (ft (°F) N (md) 12. Original 13. Bubble 14. Current 15. Oil 16. Gas 17. Gross 18. Net Pay ViscosityViscosity @ ity @ Pressure Point or Dew Reservoir 19. Original 20. Bubble Point 21. Gas 22. Original GOR 23. Current g rent TVDSS) Gravity Specific Pay (ft) (ft) Original Saturation (psi) Point Pressure ('API) Gravity (Air = Formation Formation Compressibility (SCF/STB) GOR (SCF/STB) Pressure Pressure (cp) Pressure (psi) 1.0) Volume Volume Factor Factor (Z) (cp) (psi) Factor (RB/STB) Point Thomson (RB/STB) 668150 Thomson Oil Pool -12,700 230 15 100 42 1.81 1.81 10100 10100 10085 37 0.7 235 235 0.0029 p 1.5 20,000 20,000 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 27, 2018 Form 10-428 Rev. 05/2017 INSTRUCTIONS ON REVERSE SIDE