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2008 Greater Kuparuk Area
Conoc i billips RSCPjVfF® APR 0Q AkskeOi2009 l R, Gns Cuns Comrnistinn Greater Kuparuk Area Annual Surveillance Reports Kuparuk, Meltwater, Tabasco, Tarn, and West Sak Oil Pools V`lopondrn© Period January it .- Docemberr 319 2008 2008 GKA Annual Surveillance Reports Table of Contents KUPARUK RIVER OIL POOL REPORT SUMMARY OF EOR PROJECT,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,, ATTACHMENT I A,Iap of EOR Program Staters Plot ofIncrementarl EOR Oil Rate Plot PRODUCED FLUID VOLUMES,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,, ATTACHMENT 2 INJECTED FLUID VOLUMES,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,, ATTACHMENT 3 RESERVOIR PRESSURE SURVEYS........................................................... ATTACHMENT 4 Per f intervals & corresponding sands ATTACHMENT 3 Proposed Pressure Survey Plan 4 INJECTION SURVEY DATA,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,, ATTACHMENT S Proposed Injection Profile Survey Plan PRODUCTION SURVEY DATA,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,, ATTACHMENT 6 MISCIBLE INJECTANT COMPOSITION..................................................... ATTACHMENT 7 CPF1 MI Composition CPF2 MI Composition ATTACHMENT 7 KUPARUK LSEOR DEVELOPMENT PLAN,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,ATTACHMENT 8 GKA 365 -DAY SHUT-IN WELL REPORT ............................................... ATTACHMENT 9 MELTWATER OIL POOL REPORT SUMMARY OF FOR PROJECT AND RESERVOIR MANAGEMENT,,,,,,,,,,,, ATTACHMENT I Meltwater Arel Pay Map PRODUCED FLUID VOLUMES................................................................. ATTACHMENT 2 INJECTED FLUID VOLUMES, .................................................................... ATTACHMENT 3 RESERVOIR PRESSURE SURVEYS...........................................................ATTACHMENT 4 Per f intervals & corresponding sands Proposed Pressure Survey Plan PRODUCTION/SPECIAL SURVEYS. ........................................................... ATTACHMENT 5 WELL ALLOCATION & SHALLOW GAS SPECIAL MONITORING ............ ATTACHMENT 6 2007 Meltwater Elevated OA Pressures MELTWATER DEVELOPMENT PLAN AND OPERATIONAL REVIEW ......... ATTACHMENT 7 TABASCO OIL POOL REPORT SUN IMARY OF EOR PROJECTATTACHMENT I PRODUCED FLUID VOLUMES.................................................................ATTACHMENT 2 INJECTED FLUID VOLUMESATTACHMENT 3 RESERVOIR PRESSURE SURVEYSATTACHMENT 4 Per f intervals & corresponding sands Proposed Pressure Survey Plan PRODUCTION LOGS AND SPECIAL SURVEYS,,,, TTACHMENT 5 WELL ALLOCATION AND TEST EVALUATION SUMMARY,,,,,,,,,,,,,,,,,,,,, ATTACHMENT 6 FUTURE DEVELOPMENT PLANSATTACHMENT 7 TARN OIL POOL REPORT SUMMARY OF EOR PROJECTATTACHMENT I PRODUCED FLUID VOLUMES ATTACHMENT 2 INJECTED FLUID VOLUMES ATTACHMENT 3 RESERVOIR PRESSURE SURVEYSATTACHMENT 4 Per f intervals & corresponding sands Proposed Pressure Survey Plan PRODUCTION LOGS AND SPECIAL SURVEYSATTACHMENT 5 PRODUCTION ALLOCATION FACTORSATTACHMENT 6 TARN DEVELOPMENT PLAN AND OPERATIONAL REVIEWATTACHMENT 7 WEST SAK OIL POOL REPORT SUMMARY OF EOR PROJECT ATTACHMENT I PRODUCED FLUID VOLUMES ATTACHMENT 2 INJECTED FLUID VOLUMESATTACHMENT 3 RESERVOIR PRESSURE SURVEYS ATTACHMENT 4 Perf intervals & corresponding sands Proposed Pressure Survey Plan INJECTION SURVEY DATA..................................................................... ATTACHMENT S PRODUCTION SURVEY DATA ATTACHMENT 6 GEOCHEMICAL OIL PRODUCTION SPLITS ATTACHMENT 7 PRODUCTION ALLOCATION FACTORS ATTACHMENT 8 FUTURE DEVELOPMENT PLANS ATTACHMENT 9 ii KUPARUK GAS OFFTAKE TABLE OF MONTHLY GAS OFFTAKE......................................................ATTACHMENT 1 Plot of monthly offtake iii ConocoPhillips March 31, 2009 Mr. Dan Seamount, Commissioner Alaska Oil and Gas Conservation Commission 333 West 7h Ave. Suite #100 Anchorage, Alaska 99501-3539 Re: 2008 KRU Annual Reservoir Surveillance Report Dear Mr. Seamount, James T. Rodgers Manager - GKA Light Oil Greater Kuparuk Area ConocoPhillips Alaska Inc. ATO -1220 PO Box 100360 Anchorage AK 99510-0360 Phone (907)263-4027 Fax: (907)265-6133 In compliance with Rule 3, Conservation Order No. 1988, ConocoPhillips Alaska, Inc., operator of the Kuparuk River Unit, is hereby submitting the annual surveillance report on the Kuparuk River Oil Pool. This report documents the required information pertinent to the field development and enhanced recovery operations from January through December 2008. The following is an outline of the information provided: a. A summary of the enhanced recovery project (Attachment 1). b. Voidage balance, by month, for produced and injected fluids, including low molecular weight hydrocarbons (Attachment 20). c. Analysis of reservoir pressure surveys taken in 2008 (Attachment 4). d. A tabulation of both injection (Attachment 5) and production (Attachment 6) logs and surveys analyzed during 2008 from wells in the Kuparuk permit area. e. Composition of enriched gas injected during 2008 and estimate of MMP (Attachment 7). f. Kuparuk LSEOR development plan (Attachment 8). g. 365+ days shut in well report (Attachment 9) If you have any questions concerning this data, please contact Mark Kovar at 265-6097. Sincerely, L.JeV2" James T. Rodgers Manager- GKA Light Oil Greater Kuparuk Area bcc: Central Files ATO -3 Attachment 1 Kuparuk River Unit Kuparuk River Oil Pool 2008 Annual Reservoir Surveillance Report Summary of the Enhanced Recovery Project Enhanced Recovery Miscible water -alternating -gas (MWAG) continues to serve as the main enhanced oil recovery process for the Kuparuk field. The total number of MWAG drill sites that service the Kuparuk reservoir is 33 with 274 available EOR patterns. Many of these patterns are now mature in that they have received the originally designated volume of miscible gas injection. These mature patterns generally no longer receive miscible injectant (MI) but are available for use as lean gas injection wells when plant upsets occur. The field continues to manufacture miscible injectant at two of its Central Processing Facilities (CPF's). MI manufacture occurs by blending together produced lean gas and natural gas liquids (NGLs). The NGLs originate from two sources: (1) the Kuparuk field itself (known as indigenous NGLs), and (2) those NGLs imported from the Prudhoe Bay Field Central Gas Facility. Importation from Prudhoe Bay is utilized to fill any shortfall between the total NGL requirement and the available indigenous NGL production. From a flood management perspective, the majority of available lean gas after fuel use is blended with these two NGL streams to maximize the daily volume of MI generated in the field. During 2008, the MWAG project operated in full MI production mode for most of the 33 MWAG drillsites. Three mature MWAG drillsites (drillsites 2U, 2V and 2W) continued to conduct lean gas chase tests. Lean gas, alternating with water has been injected at an average daily rate of 28.5 MMSCFD into these three drillsites. The purpose of this lean gas injection is to collect data to evaluate post-MWAG options. Drillsites 2U, 2V and 2W were under MWAG until April 2007. Drillsite 1D started MI injection in October of 2008 upon completion of an EOR expansion project. MI injection rate on drillsite 1D increased as more injectors went on line. In December of 2008, drillsite 1D MI injection rate reached 26.5 MMSCFPD. During the year 2008, Kuparuk imported an average of 21,093 barrels per day of Prudhoe NGLs. Import NGLs and indigenous NGLs blended with available lean gas generated an average of 220 MMSCFD of MI. The annual average MI injection rate into the Kuparuk Field was 156 MMSCFD. The remaining was utilized for Greater Kuparuk Area satellite fields, including 48 MMSCFD as injection and 14 MMSCFD as lift gas in Tarn and Meltwater. A small amount of MI (-2MMSCFD) is used as lift gas in drillsite 3S. The estimated incremental oil sales in calendar year 2008 from the ongoing Kuparuk MWAG project was 35.0 MBO/day, The priority for gas management at the Kuparuk field during 2008 was continuing to balance solvent injection between the A -Sand and C -Sand. This maximizes total EOR and returned NGL rates while avoiding excessive gas production rates which would cause production impacts due to gas handling limitations. Total GKA annual average gas production rate in 2008 was 294 MMSCFD, compared to 312 MMSCFD during 2007. MWAG Small Scale EOR (SSEOR and SSEORX) Drill Sites 1A, 1Y, and 2Z continued MWAG during 2008. The 2008 average MI injection rate was 12 MMSCFD. Large Scale EOR (LSEOR) The original LSEOR Drill Sites include: 1F, 1G, 1Q, 1R, 2A, 2B, 2C, 2D, 2F, 2G, 2H, 2K, 2M, 2T, 2U, 2V, 2W, 2X and 3F. The total MI injection rate into these drill sites averaged 67 MMSCFD in 2008. EOR Expansions Expansions to the original LSEOR occurred over multiple phases and now include Drill Sites 1B, 1C, 1D, 1E, 1L, 313, 3G, 3H, 30, 3Q and 3S. During 2008, the average MI injection rate into these expansion drill sites was 77 MMSCFD. I WAG During 2008 operations, the Kuparuk EOR project continued to maximize the volume of available MI by blending a majority of available lean gas with Kuparuk-sourced and imported NGL. IWAG operations were continued in Drillsites 2U, 2V and 2W to evaluate future post-MWAG options. 2L, 2N (Tarn) 2P (MW) 2008 EOR Program Status 3R I r3Q F-30 i I 3M 0 SSEOR and SSEORX 3N ' 0 LSEOR and LSEORX 31 3K 3H 3J EORX1 Expansion in 2001 3A 3C EORX1 Expansion in 2002 - 4 Wells 3S 3B 1R GKA Satellites 1998-2002 3G 3F 1Q 2W 1G 1H EORX1 Expansion in 2003 2T zu win r w" 1C WSak EOR Pilot 2003 2X" 1A 1B 1C 2v zz 0 1 D EOR Expansion in 2008 2A 2C 1F 1E 1D 2B 20 GKA Active EOR Patterns 2M 2H 2F 1L W SAK • 27 I KR 7 _j— 2G G `t 11[\ll zE • 17 Tarn 2K • 7 Meltwater 0 IL 0 m 2004-2008 Kuparuk EOR + NGL Sales Production 45000 35000 30000 15000 10000 5000 BDSiA BDS1B 13DSlC ODSlD BDS1E E3DS1F BDS1G oDS1H ■DS1L 13DS10 [3DS1R ODS1Y B DS2A 9DS2B ■DS2C MOM BDS2F 13DS2G 13DS2H ❑DS2K O DS2M 13DS2T O DS2U 13DS2V 0DS2W 0DS2X O DS2Z ODS3A ODS3B EI DS3C O DS3F ODS3G ■DS3H 8DS3J ■DS3K ■DS30 B DS3Q 9DS3R ■ DS3S 0 ,INYIS¢ZAP.0.1..: %F.:.$I!].eV :^? Tu'.NF.!:%Ya'M1SM.-^M1V...AI'.f.4u^S'��....s�-..�nm)'&:$4'.'I.W.xnK..+e'SM.G]R!PLTMIN4'.RSPof➢'Slti rt. nn. gy .^Ht"HC1_ -ms:KlT1M�:A'.!V It T It 'IT LO LO LO LO CD W CD (D 1\ r 1` 00 CC) CC) 00 m 0 0 O O O O O 0 0 0 0 O O O 0 O 0 O O O 0 I 1 1 1 1 1 I 1 1 I 1 1 I 1 I Attachment 2 Kuparuk River Oil Pool 2008 Annual Reservoir Surveillance Report Produced Fluid Volumes Cumulatives at Dec 31, 2007 2,110,808 1,553,391 3,048,687 Produced Fluid Volumes (Reservoir Units) OIL GAS WATER CUM OIL CUM GAS CUM WATER MO YR MSTB MMSCF MSTB MSTB MMSCF MSTB 1 2008 3,548 8,615 15,588 2,114,356 1,562,006 3,064,275 2 2008 3,334 7,794 14,451 2,117,690 1,569,800 3,078,725 3 2008 3,526 8,413 15,432 2,121,216 1,578,213 3,094,157 4 2008 3,323 7,794 14,698 2,124,540 1,586,007 3,108,855 5 2008 3,390 7,623 15,205 2,127,930 1,593,630 3,124,060 6 2008 3,096 6,121 13,472 2,131,026 1,599,750 3,137,532 7 2008 2,846 7,237 12,745 2,133,872 1,606,988 3,150,277 8 2008 2,686 7,080 12,332 2,136,557 1,614,067 3,162,608 9 2008 2,957 7,225 12,829 2,139,514 1,621,292 3,175,438 10 2008 3,650 8,653 15,178 2,143,164 1,629,945 3,190,616 11 2008 3,473 8,050 14,902 2,146,637 1,637,996 3,205,517 12 2008 3,434 7,922 15,396 2,150,072 1,645,918 3,220,913 2008 TOTAL 39,264 92,527 172,226 Cumulatives at Dec 31, 2007 2,110,808 1,553,391 3,048,687 Produced Fluid Volumes (Reservoir Units) Cumulatives at Dec 31, 2007 2,596,636 1,681,532 3,103,125 OIL GAS WATER CUM OIL CUM GAS CUM WATER MO YR MRVB MRVB MRVB MRVB MRVB MRVB 1 2008 4,379 6,145 15,899 2,601,015 1,687,677 3,119,024 2 2008 4,114 5,506 14,740 2,605,129 1,693,183 3,133,764 3 2008 4,351 5,975 15,740 2,609,480 1,699,158 3,149,505 4 2008 4,101 5,511 14,992 2,613,581 1,704,668 3,164,497 5 2008 4,184 5,330 15,509 2,617,765 1,709,998 3,180,006 6 2008 3,820 4,120 13,741 2,621,585 1,714,119 3,193,747 7 2008 3,512 5,219 13,000 2,625,097 1,719,338 3,206,747 8 2008 3,314 5,148 12,578 2,628,411 1,724,486 3,219,325 9 2008 3,649 5,161 13,086 2,632,060 1,729,647 3,232,411 10 2008 4,504 6,136 15,482 2,636,564 1,735,782 3,247,893 11 2008 4,286 5,675 15,200 2,640,850 1,741,457 3,263,092 12 2008 4,238 5,577 15,704 2,645,088 1,747,034 3,278,796 2008 TOTAL 48,452 65,502 175,671 Cumulatives at Dec 31, 2007 2,596,636 1,681,532 3,103,125 Attachment 3 Kuparuk River Oil Pool 2008 Annual Reservoir Surveillance Report Injected Fluid Volumes Cumulatives at Dec 31, 2007 5,268,689 1,106,627 1,017,310 Injected Fluid Volumes (Reservoir Units) WATER GAS MI CUM WATER CUM GAS CUM MI MO YR MSTB MMSCF MMSCF MSTB MMSCF MMSCF 1 2008 17,470 1,324 5,141 5,286,159 1,107,951 1,022,451 2 2008 16,159 1,632 4,700 5,302,318 1,109,584 1,027,151 3 2008 17,152 1,198 5,513 5,319,470 1,110,782 1,032,665 4 2008 16,579 1,003 5,195 5,336,049 1,111,785 1,037,859 5 2008 17,258 584 5,034 5,353,307 1,112,370 1,042,894 6 2008 15,337 496 4,112 5,368,644 1,112,865 1,047,006 7 2008 13,911 3,161 2,690 5,382,555 1,116,026 1,049,696 8 2008 12,265 1,175 3,899 5,394,820 1,117,201 1,053,595 9 2008 12,492 691 4,817 5,407,312 1,117,892 1,058,412 10 2008 16,068 1,073 5,660 5,423,381 1,118,965 1,064,072 11 2008 16,355 1,027 4,892 5,439,736 1,119,992 1,068,964 12 2008 16,988 698 5,125 5,456,724 1,120,690 1,074,089 2008 TOTAL 188,035 14,063 56,779 Cumulatives at Dec 31, 2007 5,268,689 1,106,627 1,017,310 Injected Fluid Volumes (Reservoir Units) Cumulatives at Dec 31, 2007 5,361,839 972,263 763,877 WATER GAS MI CUM WATER CUM GAS CUM MI MO YR MRVB MRVB MRVB MRVB MRVB MRVB 1 2008 17,819 1,177 3,892 5,379,658 973,440 767,769 2 2008 16,482 1,451 3,558 5,396,141 974,892 771,327 3 2008 17,495 1,065 4,174 5,413,636 975,957 775,501 4 2008 16,911 892 3,932 5,430,547 976,849 779,433 5 2008 17,603 520 3,811 5,448,149 977,368 783,244 6 2008 15,644 441 3,113 5,463,793 977,809 786,357 7 2008 14,189 2,810 2,036 5,477,982 980,619 788,393 8 2008 12,510 1,044 2,952 5,490,493 981,664 791,345 9 2008 12,742 614 3,647 5,503,235 982,278 794,991 10 2008 16,390 954 4,285 5,519,624 983,232 799,276 11 2008 16,682 913 3,704 5,536,306 984,145 802,980 12 2008 17,328 620 3,879 5,553,635 984,765 806,859 2008 TOTAL 191,795 12,502 42,982 Cumulatives at Dec 31, 2007 5,361,839 972,263 763,877 Attachment 4 Kuparuk River Oil Pool 2008 Annual Reservoir Surveillance Report Reservoir Pressure Surveys & Stratigraphic codes for perf intervals STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION RESERVOIR PRESSURE REPORT 1. Operator. ConocoPhillips Alaska Inc. 2. Address: P. O. Box 100360, Anchorage, AK 99510-0360 3. Unit or Lease Name: Kuparuk River Unit 4. Field and Pool: Kupamk River Oil Pool 5. Datum Reference: -6200'SS 6. Oil Gravity: 0.91(water=1.00.71 7. Gas Gravity: S. Well Name and Number. 9. API Number 50� NO DASHES 10. Type See Instructions 11. AOGCC Pool Code 12. Zone 13. Perforated Intervals Top - Bottom TVDSS 14. Final Test Date 15. Shut -In Time. Hours 16. Press. Sum. Type (see instructions for codes) 17. B.H. Temp. 18. Depth Tool TVDSS 19. Final Observed Pressure at Tool Depth 20. Datum TVDSS (input) 21. Pressure Gradient, psi/ft. 22. Pressure at Datum (cal) 1A -04A 029-20621-01 WAG 490100 A 07/22/2008 384 SBHP 142 6347.77 4142 6200 0.35 4090 1A-16RD 029-20713-01 WAG 490100 A 01/19/2008 2112 SBHP 130 6102.38 3003 6200 0.35 3037 1A-16RD 029-20713-01 O 490100 IC 03/02/2008 3144 ISBHP 134 15937.81 2155 6200 0.35 12247 1A-23 029-22131-00 0 490100 A 08/222008 76 SBHP 160 6106.36 2150 6200 0.35 2183 1A-26 029-22115-00 O 490100 A 08/222008 72 SBHP 161 60892 1535 6200 0.35 1574 18-17 029-22461-00 O 490100 C 11/16/2008 96 SBHP 156 6448.72 1983 6200 0.42 1879 18-19 029-22475-00 0 490100 AC 03/132008 155 SBHP 159 6247.19 2467 6200 0.35 2450 1C-05 029-20550-00 WAG 490100 C 06/01/20081056 SSHP 135 6358.87 2653 6200 0.498 2574 1C-07 029-20569-00 O 1490100 C 1 0424/2008 160 SBHP 160 6426.66 2990 6200 0.413 2896 1C-10 029-20865-00 WAG 490100 C 04/282008 75.3 EXRT1 155 6405.18 2913 6200 0.35 2841 1C-11 029-22714-00 O 490100 C 01/192008 912 SBHP 161 6437.24 3039 6200 0.32 2963 1C-11 029-22714-00 O 490100 C 05/01/2008 1704 SBHP 69 2576.56 1841 6200 0.411 3330 1C -14A 029-22861-01 WAG 490100 C 05/1012008 504 SBHP 135 6084.87 3750 6200 0.439 3801 1C -14A 029-22861-01 WAG 490100 C 09/052008 3240 SBHP 135 16084.87 3242 16200 0.439 13293 1C-15 029-22932-00 WAG 490100 C 06/06/20081200 SBHP 142 6252.95 3301 6200 0.26 3287 1C-18 029-22939-00 WAG 490100 C 05/10/2008 504 SBHP 135 6305.27 2923 6200 0.464 2874 1C-20 029-23273.00 WAG 490100 C 06/0520081176 SBHP 141 6384.01 2856 6200 0.463 2771 1C-20 029-23273-00 WAG 490100 C 09/062008 3240 SBHP 151 6384,01 2719 6200 0.429 2640 1C-21 029-23253-00 O 490100 C 0412412008168 SBHP 155 6347.56 2406 6200 0.407 2346 1C-23 029-22942-00 O 490100 C 07/122008 3800 SBHP 160 6435.74 2619 6200 0.3 2548 1C-25 029-22941-00 0 490100 C 10/272008 2568 SBHP 148 6312.92 3130 6200 0.264 3100 1C-26 029-2294440 WAG 490100 C 10115/2008 4512 SBHP 147 6336.64 2863 6200 0.469 2799 1C-27 029-22943.00 WAG 490100 C 06/07/2008 1224 SBHP 149 6274.88 3229 6200 0,476 3193 1C-27 029-2294300 0 490100 C 09/04/2008 3240 SBHP 156 6274.88 2906 6200 0.456 2872 1D-04 029-20416-00 O 490100 C 04/052008 75 SBHP 159 6401.48 2917 6200 0.44 2828 1D-12 029-22948-00 O 490100 C 06/11/2008 64 SBHP 158 6457.41 3013 6200 0.426 2903 Form 10-012 Rev. 12/2008 INSTRUCTIONS ON REVERSE SIDE Submit in Duplicate STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION RESERVOIR PRESSURE REPORT 1. Operator. ConocoPhillips Alaska Inc. 2. Address: P. O. Box 100360, Anchorage, AK 99510-0360 3. Unit or Lease Name: 4. Field and Pool: S. Datum Reference: 6. Oil Gravity: 7. Gas Gravity: Kuparuk River Unit Kuparuk River Oil Pool -6200' SS 0.91 (water= 1.0) 0.71 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 Tool 19. Final 20. Datum 21. Pressure 22. Pressure at Number. 50� See Pool Cotle 029-20849-01 Intervals Dale Time, Hours Surv. Type Temp. TVDSS Observetl TVDSS (input) GratlienL psiMt. Datum (Cal) 6200 NO DASHES Instructions 1G -10A 029-21003-01 Top - Bottom 490100 AC (see 10/06/2008124 Pressure at 153 6238.91 1927 6200 0.33 1914 IG -11 029-21008-00 TVDSS 490100 AC instructions for 10/05/2008 105 Tool Depth 159 6389.43 2340 6200 0,35 2274 l G-13 029-21016-00 O 490100 AC modes) 10/04/2008 84 SBHP 153 6093.8 2030 D-12 00 F-12 02/1 04/24/2008 IF -18A 029-22654-01 0 490100 JAC JAC 1 08/08/2008 102 ISSHP 155 15863.53 12356 6200 0.35 12474 1 G-03 029-20824-00 O 490100 AC 490100 07/05/2008 33012 SBHP 131 6186.2 2622 6200 0.35 2627 1 G -08A 029-20849-01 0 490100 AC 10/05/2008 99 SBHP 168 6464.54 2075 6200 0.35 1982 1G -10A 029-21003-01 0 490100 AC 10/06/2008124 SBHP 153 6238.91 1927 6200 0.33 1914 IG -11 029-21008-00 O 490100 AC 10/05/2008 105 SBHP 159 6389.43 2340 6200 0,35 2274 l G-13 029-21016-00 O 490100 AC 10/04/2008 84 SBHP 153 6093.8 2030 6200 0.35 2067 1G-14 029-21017-00 O 490100 AC 03108120081168 SBHP 143 6327.99 2720 6200 0.35 2675 1 L-04 179-00 10 1490100 IA I I 04!11/200811296 1L-22 029-22114-00 IWAG 1490100 JAC 1 1 11/13120081271 ISBHP 1130 15900.72 12788 162GO 10.444 12921 1L -25A 029-22174-01 O 490100 C 1 1 07/2512008111520 SBHP 149 5758,5 3186 6200 0.433 3377 Forth 10-012 Rev, 12/2008 INSTRUCTIONS ON REVERSE SIDE Submit in Duplicate ALASKA OIL AND GAS CONSERVATION COMMISSION RESERVOIR PRESSURE REPORT 1. Operator: ConocoPhillips Alaska Inc. 2. Address: P. O. Box 100360, Anchorage, AK 99510-0360 3. Unit or Lease Name: Kupawk River Unit 4. Field and Pool; Kupamk River Oil Pool 5. Datum Reference: -6200'SS 6. Oil Gravity: 0.91(water=1.00.71 7. Gas Gravity: B. Well Name and 1 Number. 9. API Number 50xxxxxxxxxxxx NO DASHES 10. Type See Instructions 11. AOGCC Pool Code 12. Zone 13. Perforated Intervals Top - Bottom TVDSS 14. Final Test Date 15. Shut -In Time, Hours 16. Press. Surv. Type (see instructions for codes) 17. B.H. Temp. 18. Depth Tooll TVDSS 19. Final Observed Pressure at Tool Depth 20. Datum TVDSS (input) 21. Pressure Gradient. psiJft. 22. Pressure at Datum (cap 1L -26A 029-22173-01 O 490100 C 06/10/2008 3528 SBHP 150 5790.32 2990 6200 0.378 3145 1L-28 029-22951-00 0 490100 AC 03/08/2008 288 SBHP 143 5744.83 2493 6200 0.44 2693 10-06 029-21224-00 O 490100 AC 12/11/2008 96 SBHP 154 6151.77 2056 6200 0.41 12076 10-14 029-21307-00 WAG 490100 A 11/16/2008 2087 SBHP 129 6180.79 3648 6200 0.32 3654 10-15 029-21308-00 0 490100 AC 07/23/2008 12528 SBHP 152 6264.81 3643 6200 0.35 3620 1R-018 029-21404-02 O 490100 A 05/10/2008 2030 SBHP 124 5176.34 2535 6200 0.438 2983 1R-02 029-21405-00 0 490100 A 03/21/2008 804 SBHP 158 6501.78 1702 6200 0.357 1594 1R-04 029-21407-00 WAG 490100 A 02/19/2008 5200 SBHP 131 6276.08 2711 6200 0.35 2684 1R-09 029-21350-00 WAG 490100 A 05/30/200814688 SBHP 119 6452.43 3596 6200 0.415 3491 1R-11 029-21352-00 0 490100 AC 09/25/2008 153 SBHP 154 6404.31 2457 6200 0.25 2406 1R-14 029-21386-00 0 490100 C 04/04/2008 1160 SBHP 156 6556.89 3048 6200 0.36 2920 1R-14 029-21386-00 O 490100 A 04/05/2008 1186 SBHP 160 6587.06 2914 6200 0.35 2779 1R-16 029-21388-00 0 490100 C 03/31/2008 984 SBHP 153 6385.58 2664 6200 0.346 2600 1R-16 029-21388-00 0 490100 A 04/01/2008 984 SBHP 157 6483.75 2608 6200 0.35 2509 1R-21 029-22211-00 O 490100 AC 04/08/2008 1258 SBHP 157 6400.58 3297 6200 0.382 3220 1R -22A 029-22206-01 O 490100 AC 09/26/2008173 SBHP 154 6454.43 2438 6200 0.4 2336 1R-35 029-23050-00 0 490100 AC 10/14/2008137 SBHP 160 6661.16 2797 6200 0.42 12603 1R-36 029-23057-00 WAG 490100 AC 02/05/200813680 SBHP 138 6540.58 2922 6200 0.44 2772 1Y -06A 029-20958-01 O 490100 AC 09/27/2008182 SBHP 155 5964.36 2331 6200 0.35 2413 1Y -15A 029-20919-01 0 490100 AC 09/26/2008 5976 SBHP 153 5903.1 2404 6200 0.35 2508 1Y-17 029-22368-00 O 490100 A 09/23/2008 103 SBHP 155 6048.26 2074 6200 0.35 2127 1Y-19 029-22391410 O 490100 A 09/24/2008 127 SBHP 156 6084.79 2471 6200 0.35 2511 1Y-22 029-22369-00 0 490100 A 09/24/2008 135 SBHP 154 6017.65 1628 6200 0.35 1692 1Y-23 029-22370-00 O 490100 C 09/27/2008 205 SBHP 151 5868.92 2387 6200 0.35 2503 1Y -24A 029-22371-01 O 490100 A 09/25/2008 162 SBHP 147 5651.11 2266 6200 0.35 2458 1Y -26A 029-21853-01 O 490100 AC 04/21/2008 89 SBHP 152 5786.1 2309 6200 0.35 2454 Form 10.412 Rev. 12/2008 INSTRUCTIONS ON REVERSE SIDE Submit in Duplicate OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION RESERVOIR PRESSURE REPORT 1. Operator. ConocoPhillips Alaska Inc. 2. Address, P. O. Box 100360, Anchorage, AK 99510-0360 3. Unit or Lease Name: Kupamk River Unit 4. Field and Pool: Kupamk River Oil Pool 5. Datum Reference: -6200' SS 6. Oil Gravity: 0.91 (water= 1.0) 7. Gas Gravity: 0.71 S. Well Name and Number. 9. API Number 50xxxxxxxxxxxx NO DASHES 10. Type See Instructions 11. AOGCC Pool Code 12. Zone 13. Perforated Intervals Top - Bottom TVDSS 14. Final Test Date 15. Shut -In Tune, Hours 16. Press. Surv. Type (see instructions for codes) 17. B.H. Temp, 18. Depth Tool TVDSS 19. Final Observed Pressure at Tool Depth 20. Datum TVDSS (input) 21. Pressure Gradient, psi/ft. 22. Pressure at Datum (cal) tY-29 029-21852-00 O 490100 AC 09/25/2008 156 SBHP 151 $982.47 2161 6200 0.35 2237 1Y30 029-21851-00 O 490100 A 09/24/2008110 SBHP 155 6075.54 2272 6200 0.35 2316 1Y31 029-22381-00 O 490100 IC1 1 04/29/2008 296 ISBHP 157 6055.65 2345 6200 0.35 12396 1Y-32 029-2185400 0 490100 AC 09/26/2008 184 SBHP 157 6049.21 2919 6200 0.35 2972 1Y-34 029-22382-00 0 490100 A 09/2512008 151 SBHP 154 6030.15 1376 6200 0.35 1435 2A-03 103-20025-00 O 490100 AC 04/13/2008 72 SBHP 138 56MOS 3556 6200 0.35 3735 2A-05 103-20030-00 490100 AC 04/14/2008 720 SBHP 148 5714.02 2677 6200 0.35 2847 2A-09 103-20059-00 0 490100 AC 06130/2008108 SBHP 158 5862.01 2792 6200 0.35 2910 2A-24 103-20195-00 O 490100 AC 06/30/2008 108 SBHP 156 5766.89 2765 6200 0.35 2917 28-02 029-2115400 0 490100 AC 07/04/2008 168 SBHP 158 5925.71 2730 6200 0.35 2826 213-03A 029-21151-01 O 490100 AC 07/04/2008166 SBHP 159 5896.81 2979 6200 0.35 3085 213-08 029-21079-00 O 490100 AC 06/27/2008 34 SBHP 128 5967.99 4295 6200 0.35 4376 2C-10 029-21230-00 O 490100 AC 01/08/2008 72 SBHP 159 5900.26 2392 6200 0.35 2497 2C-11 029-21231-00 O 490100 AC 01/06/2008 48 SBHP 158 5870.17 2025 6200 0.35 2140 2C-12 02941222-00 O 490100 AC 02/01/2008 648 SBHP 159 5847.08 2946 6200 0.35 13070 2C-14 029-21226-00 O 490100 AC 01/06/2008 52 SBHP 155 5828.01 2137 6200 0.35 2267 2D-01 029-2119400 0 490100 A 06/29/2008 60 SBHP 158 5854.3 2272 6200 0.35 2393 20.05 029-21157-00 O 490100 AC 11/25/2008 720 SBHP 134 5649.42 4120 6200 0.35 4313 213-06131.1 029-21168-60 O 490100 A 06/08/2008 5000 SBHP 119 2464 6200 0.35 20-08 029-21158-00 O 490100 AC 06/28/2008 81 SBHP 157 5954.57 2340 6200 0.35 2426 2D-14 029-21183-00 O 490100 AC 1 10/022008 72000 SBHP 127 5801.6 3497 6200 0.35 3636 2E-10 029-21246-00 O 490100 A 06/282008 81 SBHP 149 5897.78 1573 6200 0.35 1679 2E-12 029-21227-00 O 490100 A 08/212008 444 SBHP 108 5913.05 3161 6200 0.35 3261 2E-13 029-21213-00 O 490100 A 08/31/2008 18288 SBHP 120 5985.58 3335 6200 0.35 3410 2E-14 029-21214-00 0 490100 A 08/31/2008 18288 SBHP 83 3645.93 2512 6200 0.35 3406 2E-16 029-21207-00 O 490100 A 07/03/2008 144 SBHP 161 5900.4 2493 6200 10.35 2598 Form 10412 Rev. 1212008 INSTRUCTIONS ON REVERSE SIDE Submit in Duplicate STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION RESERVOIR PRESSURE REPORT 1. Operator: ConocoPhillips Alaska Inc. I 2. Address: P. 0, Box 100360, Anchorage, AK 995100360 3. Unit or Lease Name: Kuparuk River Unit 4. Field and Pool: Kupamk River Oil Pool 5. Datum Reference: -6200' SS 6. Oil Gravity: 0.91 (water= 1.0) 7. Gas Gravity: 0.71 S. Well Name and Number. 9. API Number 50xxxxxxxxxxxx NO DASHES 10. Type See Instructions 11. AOGCC Pool Code 12. Zone 13. Perforated Intervals Top - Bottom TVDSS 14. Final Test Date 15. Shut -In Time, Hours 16, Press. Sum. Type (see instructions for codes) 17. B.H. Temp. 18. Depth Tool TVDSS 19. Final Observed Pressure at Tool Depth 20. Datum TVDSS (input) 21. Pressure Gradient, Pstlft. 22. Pressure at Datum (cal) 2F -05X 029-2273000 0 490100 A 07103/2008168 SBHP 163 5854.18 3548 6200 0.35 3669 2F-08 029-21077-00 O 490100 AC 07/01/2008132 SBHP 163 5674.13 3026 6200 0.35 3210 2F-12 029-21097-00 O 490100 IA 1 07/012008 132 ISBHP 167 5870.97 2750 6200 0.35 2865 2F-20 029-22739-00 0 490100 D 04/172008 87600 SBHP 165 6119.67 3152 6200 0.35 3180 2G-02 029-21153-00 O 490100 A 01/17/2008 288 SBHP 157 5955.55 3685 6200 0.35 3771 2G-15 029-21162-00 0 490100 A 07/03/2008 144 SBHP 158 5994.97 4015 6200 0.35 4087 2H-05 103-20043-00 O 490100 A 06/30/2008108 SBHP 159 5984.51 2423 6200 0.35 2498 2H-10 103-20051-00 O 490100 A 07/01/2008 160 SBHP 162 5925.19 2424 6200 0.35 2520 2H-11 103-20052-00 0 490100 AC 06/222008 108 SBHP 160 5975.34 2835 6200 0.35 2914 2H-12 103-20053-00 O 490100 A 06/30/2008 108 SBHP 160 5989.58 2871 6200 0.35 2945 2H-13 103-20037-00 O 490100 AC 10/13/2008 2340 SSHP 125 5927.89 3966 6200 0.35 4061 2K-02 103.20101-00 O 490100 AC 071012008 132 SBHP 159 5993.86 1996 6200 0.35 2068 2K-06 103-20110-00 0 490100 AC 10/022008168 SBHP 120 6003.09 4544 6200 0.35 4613 2K-09 103-20108-00 0 490100 A 07/02/2008 132 SBHP 159 6050.83 1982 6200 0.35 2034 2K-19 103-20118-00 0 490100 A 11/12/2008 1032 SBHP 162 6142.4 3428 6200 0.35 3448 2K-22 103-20119-00 O 490100 A 11/232008 21216 SBHP 164 6183.75 3745 6200 0.35 3751 2K-26 103-20126-00 0 490100 A 07/03/2008 144 SSHP 156 6012.18 1916 6200 0.35 1982 2K-27 103-20388.00 O 490100 A 07/012008 144 SBHP 160 4742.28 2213 6200 0.35 2723 21YI-06 103-20176-00 O 490100 A 05/292008 6500 SBHP 125 5819.62 3822 6200 0.35 3955 2110-08 103-20184-00 O 490100 A 06/30/2008108 SBHP 161 5970.52 2703 6200 0.35 2783 2M-09 103-20177-00 0 490100 A 0529/2008 6500 SBHP 120 4581.09 3666 6200 0.35 4233 2M -09A 103-20177-01 WAG 490100 A 02/182008 6500 SBHP 120 5921.08 3666 6200 0.35 3764 2M-10 103-20157-00 O 490100 AC 06/21/2008 72 PBU 157 5770.73 2895 6200 0.35 3045 2T-12 103-20066-00 0 490100 C 10/16/2008 7600 SBHP 112 4135,99 2682 6200 0.35 3404 2T-12 103-20066-00 O 490100 A 10/17/2008 7000 SBHP 160 5644.38 3702 6200 0.35 3896 2T -12A 103-20066-01 0 490100 C 10/162008 7600 SBHP 112 4138.1 2682 6200 0.35 3404 Form 10-412 Rev. 12/2008 INSTRUCTIONS ON REVERSE SIDE Submit in Duplicate 1. Operator: ConocoPhillips Alaska h 3. Unit or Lease Name: Number. 5 50XXXXXXXXXXXX I See NO DASHES Instructions 103-20229-01 99-00 Farm 10-012 Rev. 12/2008 11. AOGC( Pool Code 00 AC STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION RESERVOIR PRESSURE REPORT 06/30/20081108 INSTRUCTIONS ON REVERSE SIDE 57 160 11 39 Datum Reference: 2. Address: P. 0. Box 100360. Anchorage, 7. Gas Gravity: d. Field and Pool: Kupamk River Oil Pool . Zone 13. Perrorsted 114. Final Test 15. Shut -In 16. Press. 17. B.H. TVDSS Intervals Date Time, Hours Sum. Type Temp. Pressure at Top - Bottom (see Tool Depth TVDSS instructions for codes) 06/30/20081108 INSTRUCTIONS ON REVERSE SIDE 57 160 11 39 Datum Reference: S. Oil Gravity: 7. Gas Gravity: 200' SS 0.91 (water= 1.0) 0.71 1. Depth Tool 19. Final 20. Datum 21. Pressure 22. Pressure at TVDSS Observed TVDSS (input) Gradient, psi/X. Datum (cal) Pressure at Tool Depth in Duplicate STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION RESERVOIR PRESSURE REPORT 1. Operator. ConocoPhillips Alaska Inc. 2. Address: P. O. Box 100360, Anchorage, AK 99510-0360 3. Unit or Lease Name: Kuparuk River Unit 4, Field and Pool: Kuparuk River Oil Pool 5. Datum Reference: -6200' SS 6. Oil Gravity: 0.91 (water= 1.0) 7. Gas Gravity: 0.71 8. Well Name and 1 Number. 9. API Number 50xxxxxxxxxxxx NO DASHES 10, Type See Instructions 11. AOGCC Pool Code 12. Zone 13. Perforated Intervals Top - Bottom TVDSS 14. Final Test Date 15. Shut -In Time, Hours 16. Press. Surv. Type (see instructions for codes) 17. B.H. Temp. 18. Depth Tool TVDSS 19, Final Observed Pressure at Tool Depth 20. Datum TVDSS (input) 21, Pressure Gradient, psi/ft. 22. Pressure at Datum (cal) 2X-19 029.22618-00 O 490100 C 06/27/2008 5900 SBHP 152 5709.6 2812 6200 0.35 2984 2Z -01A 029-20953-01 O 490100 A 04/30/2008 108 SBHP 155 5930.8 1774 6200 0.35 1868 2Z-05 029-20956-00 0 490100 IA 1 07/17/200810244 ISEMP 154 5953.85 2405 6200 0.35 12491 2Z-10 029-21378-00 O 490100 AC 04/29/2008 240 SSHP 152 5727.84 2289 6200 0.35 2454 2Z-13 029.21360-00 O 490100 AC 11/04/2008 1990 SBHP 153 5702.95 2804 6200 0.35 2978 2Z -13A 029-21360-01 0 490100 A 02/11/2008 1265 SBHP 155 5702.95 2638 6200 0.35 2812 2Z -13A 029-21360-01 O 490100 AC 05/11/2008 3408 SBHP 152 5731.91 2886 6200 0.37 3059 2Z -13A 029-21360-01 O 490100 AC 11/04/2008 2016 SBHP 140 5702.95 2777 6200 0.38 2966 ZZ -18 029-21884-00 0 490100 AC 04/30/2008 264 SBHP 155 6994.93 2362 6200 0.35 2084 2Z-20 029-21876-00 O 490100 AC 04/302008 264 SSHP 155 5626.38 2310 6200 0.35 2511 2Z-20 029-21876-00 O 490100 AC 12/13/2008 72 SBHP 152 5725.58 2314 6200 0.4 2504 2Z-21 029-21877.00 O 490100 AC 04/302008 108 SBHP 150 5868.08 2217 6200 0.35 2333 3A -03B 029-21432-02 O 490100 A 07/19/2008 75 SBHP 159 6091.37 3246 6200 0.4 3289 3A-06 029-21443-00 WI 490100 A 03/11/2008 94 SBHP 160 5965.83 3788 6200 0.442 3892 3A-06 029-21443-00 WI 490100 C 03/12/2008 98 SBHP 160 5895.3 3450 6200 0.442 3585 3A-06 029-21443-00 WI 490100 AC 08/032008 487 SBHP 99 6058.44 3431 6200 0.436 3493 3A-06 029-21443-00 WI 490100 A 08/11/2008 675 SBHP 99 6058.44 3567 6200 0.54 3643 3A-06 029-21443-00 WI 490100 C 08/12/2008 675 SBHP 77 5895.3 3301 6200 0.58 3478 3A-15 029-21491-00 WI 490100 A 10/08/2008 3479 SBHP 105 6087.26 4048 6200 0.46 4100 3A-17 029-22691-00 0 490100 AC 07/232008166 SBHP 153 5974.01 3166 6200 0.35 3245 38-01 029-21318-00 O 490100 A 08/02/2008 400 SBHP 120 6039.44 4000 6200 0.35 4056 3B-01 029-21318-00 O 490100 C 08103/2008 404 SBHP 125 5977.99 4004 6200 0.43 4099 38-05 029-21335-00 WAG 490100 C 08/15/2008 716 SBHP 122 6006.01 3429 6200 0.35 3497 3B-05 029-21335-00 WAG 490100 A 08/162008 716 SBHP 118 6093.92 3928 6200 0.35 3965 38-06 029-21336-00 O 490100 AC 07/212008112 SBHP 150 5987.92 2119 6200 0.35 2193 3B-08 029-21343-00 10 490100 A 10/11/2008 106 SBHP 152 6132.96 2144 6200 0.35 2167 Form 10412 Rev. 12/2008 INSTRUCTIONS ON REVERSE SIDE Submit in Duplicate Operator. 2. Address: P. O. Box 100360, Anchorage, nocoPhillips Alaska Inc. 4. Field and Pool: Unit or Lease Name: Kuparuk River Oil Pool paruk River Unit 13. Perforated Well Name and9. API Number 10. Type 11. AOGC( Number: 50xxxxxxxxxxxx See I Pool Code Surv. Type NO DASHES Instructions Top - Bottom 0 354-00 00 00 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION RESERVOIR PRESSURE REPORT 15240 18 47 124 ,K 99510-0360 Datum Reference: 2. Address: P. O. Box 100360, Anchorage, 7. Gas Gravity: 4. Field and Pool: Kuparuk River Oil Pool . Zone 13. Perforated 14. Final Test 15. Shut -In 1 16. Press, 17. B.H. TVDSS Intervals Date Time, Hours Surv. Type Temp. Pressure at Top - Bottom (see Tool Depth TVDSS Instructions I codes) 15240 18 47 124 ,K 99510-0360 Datum Reference: 6. Oil Gravity: 7. Gas Gravity: 200' SS 0.91 (water = 1.0) 0.71 i. Depth Tool 19. Final 20. Datum 21. Pressure 1 22. Pressure at TVDSS Observed TVDSS (input) Gradient, psV(t. Datum (cal) Pressure at Tool Depth 19 17 962 Forth 10-412 Rev. 1212008 INSTRUCTIONS ON REVERSE SIDE Submit in Duplicate STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION RESERVOIR PRESSURE REPORT 1. Operator: ConocoPhillips Alaska Inc. 2. Address, P. 0. Box 100360, Anchorage, AK 99510-0360 3. Unk or Lease Name: Kuparuk River Unit 4. Field and Pool: Kupamk River Oil Pool S. Datum Reference: -6200'SS 6. Oil Gravity: 0.91(water=1.00.71 7. Gas Gravity: S. Well Name and 1 Number. 9. API Number 50XXXXXXXXXXXX NO DASHES 10. Type See Instructions 11. AOGCC Pool Code 12. Zone 13. Perforated Intervals Top - Bottom TVDSS 14. Final Test Date 15. Shut -In Time, Hours 16. Press. Surv. Type (see instructions for codes) 17. B.H. Temp. 18. Depth Tool TVDSS 19, Final Observed Pressure at Tool Depth 20. Datum TVDSS (input) 21, Pressure Gradient, psint. 22. Pressure at Datum (cal) 3F-04 029-21449-00 O 490100 C 07/21/2008 120 SBHP 135 5787.07 2849 6200 0.44 3031 3F-04 029-21449-00 0 490100 A 07/22/2008 136 SBHP 131 5892.09 3871 6200 0.35 3979 3F-04 029-21449-00 WAG 490100 C I 09/16120081487 lSBHP 130 15787.07 2747 6200 0.35 12892 3F-04 029-21449-00 WAG 490100 A 09/17/2008 1487 SBHP 130 6010.04 3720 6200 0.35 3786 3F-09 029-21480-00 0 490100 C 07/21/2008 119 SBHP 163 5797.59 2673 6200 0.43 3046 3F-12 029-21483-00 O 490100 A 07/30/2008 326 SBHP 139 5767.14 3366 6200 0.35 3518 317-12 029-21483-00 O 490100 C 07/31/2008 352 SBHP 131 5666.99 3036 6200 0.33 3212 3F -13A 029-21499-01 O 490100 AC 07/282008 21109 SBHP 164 5977.83 3993 6200 0.35 4071 3F-15 029-21501-00 WAG 490100 C 08/262008 975 SBHP 129 5687.86 3000 6200 0.44 3225 3F-15 029-21501-00 WAG 490100 A 08/27/2008 997 SBHP 131 5820.92 3121 6200 0.44 3288 3F-17 029-22685-00 O 490100 A 08/18/2008 798 SBHP 162 5943.77 1714 6200 0.33 1799 3F-18 029-22684-00 0 490100 AC 0521/2008 960 SBHP 158 5825.82 2863 6200 0.344 2992 3F-20 029-22947-00 0 490100 A 07/222008 135 SBHP 130 6023.44 4632 6200 0.44 4710 3F-21 029-22991-00 O 490100 A 07/22/2008144 SBHP 129 6057.49 4632 6200 0.44 4695 3G-03 103-20245-00 O 490100 AC 09/12/2008 456 SBHP 151 5576.13 2098 6200 0.35 2316 3G-06 103-20130-00 0 490100 A 09/022008 597 SBHP 155 5762.84 2644 6200 0.3 2775 3G-10 103-20134-00 0 490100 C 07/312008 374 SBHP 130 5748.5 3345 6200 0.35 3503 3G-10 103-20134-00 0 490100 A 08/01/2008 381 SBHP 128 5808.04 3629 6200 0.35 3766 3G-15 103-20139-00 WAG 490100 AC 09101/20081136 SBHP 117 5765.48 4120 6200 0.44 4311 3G-17 103-20140-00 0 490100 AC 07/202008 95 SBHP 154 5721.12 3198 6200 0.43 3404 3G-20 103-20141-00 O 490100 AC 07/252008 227 SBHP 127 5800.52 4080 6200 0.44 4256 3G-22 103-20147-00 0 490100 AC 07/2012008100 SBHP 157 5794.28 3312 6200 0.34 3450 3G-24 103-20145-00 O 490100 A 07/26/2008 249 SSHP 120 5763.16 4177 6200 0.35 4330 3G-26 103-20303-00 0 490100 A 10/05/2008 1387 SBHP 156 5851.27 3196 6200 0.42 3342 3H-07 103.20079-00 WAG 490100 AC 11/01200811416 SBHP 94 5863.72 3540 6200 0.43 3685 31-1-108 103-20087-02 0 490100 A 0724/2008 171 SBHP 153 5983.37 2122 6200 1.13 2367 Form 10-012 Rev. 12/2008 INSTRUCTIONS ON REVERSE SIDE Submit in Duplicate ALASKA OIL AND GAS CONSERVATION COMMISSION RESERVOIR PRESSURE REPORT 1. Operator: ConocoPhillips Alaska Inc. 2, Address: P. O. Box 100360, Anchorage, AK 99510-0360 3. Unit or Lease Name: Kuparuk River Unit 4. Field and Pool: Kupawk River Oil Pool 5. Datum Reference: -6209 SS 6. Oil Gravity: 0.91 (water= 1.0) 7. Gas Gravity: 0.71 8. Well Name and Number. 9. API Number 50xxxxxxxxxxxx NO DASHES 10. Type See Instructions 11. AOGCC Pool Code 12. Zone 13. Perforated Intervals Top - Bottom TVDSS 14. Final Test Date 15. Shut -In Time, Hours 16. Press. Surv. Type (see instructions for codes) 17. B.H. Temp. 16. Depth Tool TVDSS 19. Final Observed Pressure at Tool Depth 20. Datum TVDSS (input) 21. Pressure Gradient, psVtt. 22. Pressure at Datum (cal) 3H-11 103.20091-00 O 490100 C 04/05/2008 126 SBHP 156 5996.03 3389 6200 0.35 3460 311-1413 103-20092-02 O 490100 AC 0725/2008 201 SBHP 155 5948.45 2968 6200 0.44 3079 311-16A 10320096-01 O 490100 A 01117/2008 9999 SBHP 133 5848.01 4013 6200 0.35 14136 311-28A 103-2023601 0 490100 AC 11/292008 1188 SBHP 155 5858.11 3427 6200 0.41 3567 31-09 029-21561-00 WI 490100 A 08/25/200812670 SBHP 110 6194.47 4239 6200 0.35 4241 31-09 029-21561-00 WI 490100 A 11/18/2008 14704 SBHP 120 6194.47 4162 6200 0.4 4164 31-11 029-21932-00 O 490100 A 07/20/2008 82 SBHP 160 6207.15 3096 6200 0.4 3093 31-13 0292192300 WI 490100 A 10/10/2008 315 SBHP 113 6167.87 4721 6200 0.42 4734 3J-05 029-2143600 WI 490100 C 09/032008 1942 SBHP 140 6096.02 3480 6200 0.45 3527 3J-05 02921436-00 WI 490100 A 09/04/20081958 PFO 115 6138,73 3475 6200 0.45 3503 3J -07A 029-21438-01 0 490100 A 0720/2008 81 SBHP 157 6243.29 2990 6200 0.4 2973 3J-10 029-21467-00 O 490100 AC 07/202008 78 SBHP 156 6180.72 3367 6200 0.461 3376 3J-14 029-21496A0 O 490100 A 07/08/2008 95 SBHP 160 6196.89 3336 6200 0.35 3337 3J-15 029-21497-00 0 490100 C 0721/2008 98 SBHP 159 6235.78 2385 6200 0.34 2373 3J-15 029-21497-00 O 490100 A 07/222008101 SBHP 154 6306.99 2086 6200 0.35 2049 3J-17 02922700-00 O 490100 AC 0720/2008 79 SBHP 153 6148.14 2965 6200 0.43 2987 3K-03 029-21602-00 0 490100 A 02/172008 2136 SBHP 158 6596.21 3048 6200 0.35 2909 3K-04 02921603-00 wl 490100 A 02/18/2008 6648 SBHP 160 6569.92 5026 6200 0.442 4862 3K-05 029-21618-00 WI 490100 A 08/05/2008 10913 SBHP 136 6663.05 3936 6200 0.442 3731 3K-06 029-2161900 0 490100 A 08/062008 484 SBHP 161 6569.96 1762 6200 0.35 1633 3K -09A 02921656-01 O 490100 A 03/06/2008 696 SBHP 160 6633.55 1479 6200 0.35 1327 3K -09A 02921656-01 O 490100 A 08/15/2008 693 SBHP 161 6630.99 1727 6200 0.35 1576 3K-10 029-21653-00 0 490100 A 06/30/2008 20159 SBHP 162 6676.99 2981 6200 0,35 2814 3K-14 02921631-00 O 490100 A 12/052008 3384 SBHP 163 6624.71 4176 6200 0.39 4010 3K-17 029-21642-00 O 490100 AC 03/29/2008 480 SBHP 160 5161.38 2535 6200 0.35 2899 3K-18 02921641-00 WI 490100 A 08/04/2008 6611 SBHP 132 6627.4 3591 6200 0.442 3402 Form 10-412 Rev. 1212008 INSTRUCTIONS ON REVERSE SIDE Submit in Duplicate STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION RESERVOIR PRESSURE REPORT 1. Operator. ConocoPhillips Alaska Inc. 2. Address: P. O. Box 100360, Anchorage, AK 99510-0360 3. Unit or Lease Name: Kuparuk River Unit 4, Field and Pool: Kuparuk River Oil Pool 5. Datum Reference: -6200' SS 6. Oil Gravity: 0.91 (water=l.0 7. Gas Gravity: 0.71 8. Well Name and Number: 9. API Number SOXXXXXXX)W W( NO DASHES 10. Type See Instructions 11. AOGCC Pool Code 12. Zone 13. Perforated Intervals Top -Bottom TVDSS 14, Final Test Date 15. Shut -In Time, Hours 16. Press. Surv, Type (see instructions for codes) 17. B.H. Temp. 18. Depth Tool TVDSS 19. Final Observed Pressure at Tool Depth 20. Datum TVDSS (input) 21. Pressure Gradient. psUft. 22. Pressure at Datum (cal) 3K-224 029-22759-01 WI 490100 A 02/17/2008 7632 SBHP 152 6531.01 2552 6200 0.44 2406 3K-23 029-22771-00 0 490100 A 08/04/2008 436 SBHP 158 6449.36 2500 6200 0.43 2393 3K-24 029-22935-00 10 490100 A 10/26/2008 95 ISBHP 159 6513.68 2360 6200 0.43 2225 3K-25 029-22881-00 WI 490100 A 10/08/2008 8326 SBHP 141 6569.75 2615 6200 0.46 2445 3K-27 029-22751-00 O 490100 A 08/04/2008 442 SSHP 159 6626,6 3682 6200 0.35 3533 3K30 029-22777-00 WI 490100 A 07/01/2008 12223 SBHP 141 6636.31 2870 6200 0.442 2677 3K-32 029-22763-00 O 490100 A 09/30/2008 2544 SBHP 160 6584.69 4117 6200 0.368 3975 31K35 029-22775-00 O 490100 A 11/25/20081136 SBHP 156 6363.09 4192 6200 0.47 4115 3M-03 029-2169640 O 490100 AC 07/21/2008 49968 ISBHP 157 6185.54 4752 6200 0.47 4759 3M-03 029-21696-00 O 490100 AC 11/05/2008 52501 SBHP 153 6184.83 4291 6200 0.44 4298 310-06 029-21707-00 O 490100 AC 09/30/20081873 SBHP 83 6162 4678 6200 0.35 4691 3M-07 029-21708-00 0 490100 AC 09/30/20081879 SBHP 95 6250.78 4117 6200 0.37 4098 3M-08 029-21709-00 0 490100 AC 07/21/2008106 SBHP 156 6048.68 2953 6200 0.35 3006 3M-09 029-21710-00 O 490100 AC 07/2112008102 SBHP 154 6112.67 2010 6200 0.36 2041 3M-14 029-21726-00 0 490100 A 07/21/2008 16982 SBHP 153 6176.79 4422 6200 0.39 4431 3M-15 029-21727-00 WI 490100 A 12/23/2008 2399 SBHP 113 6197.97 4269 6200 0.35 4270 WAS 029-21728-00 WI 490100 AC 10/01/20081899 SBHP 113 6185.79 4466 6200 0,52 4473 3M-22 029-21740-00 0 490100 AC 08120/2008 822 SBHP 157 6175.94 3348 6200 0.43 3358 3M-26 029-22431-00 O 490100 A 08/20/2008 62736 SBHP 135 6244.93 4549 6200 0.38 4532 3M-28 029-2244240 O 490100 A 07121/2008110 SBHP 156 6007,78 2085 6200 0.35 2152 314-01 029-21519-00 0 1490100 A 07/22/2008 120 SBHP 164 6298.73 2854 6200 0.49 2806 3N -02A 029-21527-01 O 490100 A 01/04/2008 964 SBHP 155 6343.92 3209 6200 0.35 3159 3N -02A 029-21527-01 0 490100 A 08120/20081816 SBHP 151 6067.96 3243 6200 0.5 3309 3N-03 029.21528-00 O 490100 A 05/162008194 SBHP 99 6260.57 5010 6200 0.35 4989 3N-03 029-21528-00 WI 490100 A 06/042008 623.8 EXRT1 155 6260.57 4698 6200 0.35 4677 3N-03 029-21528-00 WI 490100 A 06/19/2008 984.5 EXRT1 155 6260.57 4567 6200 0.35 4546 Form 10312 Rev. 12/2008 INSTRUCTIONS ON REVERSE SIDE Submit in Duplicate STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION RESERVOIR PRESSURE REPORT 1. Operator: ConocoPhillips Alaska Inc. 2, Address: P. O. Box 100360, Anchorage, AK 99510-0360 3. Unit or Lease Name: Kuparuk River Unit 4. Field and Pool: Kupawk River Oil Pool 5. Datum Reference: 3200' SS 6. Oil Gravity: 0.91 (water= 1.0 7. Gas Gravity: 0.71 8. Well Name and 1 Number: 9. API Number 50� NO DASHES 10. Type See Instructions 11. AOGCC Pool Code 12. Zone 13. Perforated Intervals Top - Bottom TVDSS 14. Final Test Date 15. Shut -In Time, Hours Surv. (s instruct cod 16. P1112 17. B.H. Temp. 18. Depth Tool TVDSS 19. Final Observed Pressure at Tool Deplh 20. Datum TVOSS (input) 21. Pressure Gradient, psilft. 22. Pressure at Datum (cal) 3N-03 029-21528-00 WI 490100 A 07/03/2008 1318 EXRT1155 6260.57 4548 6200 0.35 4527 3N-03 029-21528-00 WI 490100 A 07/15/2008 1608 EXRT1155 6260.57 4498 6200 0.35 4477 3N-03 029-21528-00 WI 490100 A 08/26/2008 2640 SBHP121 6259.78 4446 6200 0.4 4422 3N-04 029-21529-00 WI 490100 AC 07/23/2008 216 SBHP116 6238.06 3877 6200 0.5 3858 3N-05 029-21537-00 WI 490100 A 08/03/2008 480 SBHP 6150.07 5437 6200 0.35 5454 3N-06 029-21538-00 O 490100 A 07/31/2008 10848 SSHP 158 6371.03 4094 6200 0.46 4015 3N-080 029-21540-01 WI 490100 AC 08/01/2008 432 SBHP 103 6324.86 4956 6200 0.42 4904 3N-09 029-21541-00 0 490100 AC 08/01/2008 360 SBHP 163 6315.65 2935 6200 0.44 2884 3N-10 029-21576-00 WI 490100 A 08/01/2008 432 SBHP 118 6451.72 4672 6200 0.45 4559 3N-13 029-21584-00 WI 490100 AC 07/22/2008 1080 SBHP 92 6367.25 4288 6200 0.45 4213 3N-15 029-21592-00 O 490100 A 09/02/2008 1125 SBHP 155 6367.84 1052 6200 0.35 993 3N-16 029-21593-00 0 490100 A 06/16/2008130 SBHP 159 6470.05 1280 6200 0.35 1185 3N-16 029-21593-00 0 490100 C 06/17/2008 104 SBHP 157 6420.06 1576 6200 0.35 1499 3N-18 029-21595-00 O 490100 A 08/02/2008 384 SBHP 157 6428.87 1786 6200 0.37 1701 3N-19 029-23056-00 O 490100 A 06/06/2008 82 SBHP 152 6252.93 1210 6200 0.35 1191 3N-19 029-23056-00 0 490100 A 06/07/2008 96 SBHP 94 6345.83 1252 6200 0.35 1201 30-01 029-21836-00 O 490100 A 08/09/2008 552 SBHP 166 6594.15 4163 6200 0.43 3994 30-01 029-21836-00 O 490100 A 12/03/2008 3336 SBHP 164 6462.71 4513 6200 0.35 4421 30-0ZA 029-21837-01 0 490100 A 08/10/2008 581 SBHP 161 6393.86 3441 6200 0.37 3369 30-04 029-21826-00 O 490100 A 08/09/2008 558 SSHP 162 6488.47 3433 6200 0.35 3332 30-06 029-21824-00 O 490100 A 08/10/2008 574 SBHP 137 6540.61 4840 6200 0.44 4690 30-07 029-21840-00 WAG 490100 A 08/10/2008 579 SBHP 138 6647.84 4356 6200 0.43 4163 30-10 029-21823-00 WAG 490100 A 08/11/2008 600 SBHP 120 6479.08 4759 6200 0.44 4636 30-11 029-2180500 0 490100 A 07/31/2008 345 SBHP 164 6509,96 3595 6200 0.35 3487 30-12 029-21804-00 WAG 490100 A 08/13/2008 648 SBHP 126 6566.04 4450 6200 0.35 4322 30-13 029-21803-00 O 490100 A 12110/2008,144 SBHP 164 6596 2893 6200 0.35 2754 Forth 10-412 Rev. 12/2008 INSTRUCTIONS ON REVERSE SIDE Submit in Duplicate STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION RESERVOIR PRESSURE REPORT 1. Operator. ConocoPhillips Alaska Inc. 2. Address: P. 0. Box 100360, Anchorage, AK 99510-0360 3. Unit or Lease Name: Kuparuk River Unit 4. Field and Pool: Kuparuk River Oil Pool S. Datum Reference: -6200' SS S. Oil Gravity: 0.91 (water= 1.0) 7. Gas Gravity: 0.71 8. Well Name and 1 Number: 9. API Number 50XXXXXXXXXXXX NO DASHES 10. Type See Instructions 11. AOGCC Pool Code 12. Zone 13. Perforated Intervals Top - Bottom TVDSS 14. Final Test Date 15. Shut -In Time, Hours 16. Press. Sum. Type (see instructions for Codes) 17. B.H. Temp. 18. Depth Tool TVDSS 19. Final Observed Pressure at Tool Depth 20. Datum TVDSS (input) 21. Pressure Gradient, psi/ft. 22. Pressure at Datum (cal) 30-14 029-21802-00 WAG 490100 A 08/11/2008 600 SBHP 123 6579.36 4203 6200 0.44 4036 30-14 029-21802-00 WAG 490100 A 11/14/2008 26 SBHP 130 6579.36 4735 6200 0.45 4564 30-15 029-21797-00 O 490100 JA 12/11/2008168 ISSHP 154 6177.66 3155 6200 0.33 13162 30-18 029-21793-00 0 490100 AC 08/14/2008 673 SBHP 160 6507.09 3114 6200 0.15 3068 30-01 029-22220-00 WAG 490100 A 08/07/2008 647 SBHP 130 6488.9 4750 6200 0.47 4614 30-04 029-22219-00 O 490100 A 08/07/2008 506 SBHP 163 6456.95 3160 6200 0.34 3073 30-05 029-21684-00 O 490100 A 08/09/2008 550 SBHP 135 6189.14 4764 6200 0.48 4769 3Q-07 029-21682.00 0 490100 A 08/09/2008 555 SBHP 156 6205.28 2198 6200 0.05 2198 30-09 029-21674-00 O 490100 AC 1 07/26/2008 213 SBHP 160 6260.62 3207 6200 0.37 3185 30-15 029-21666-00 O 490100 A 01/16/2008 120 SBHP 83 6472.66 4673 6200 0.35 4578 30-15 029-21666-00 0 490100 A 03/09/2008 1416 SBHP 128 6638.42 4397 6200 0.35 4244 30-16 029-21667-00 O 490100 A 01/21/2008 288 SBHP 119 6571.66 4817 6200 0.35 4687 3Q-21 029-22630-00 WAG 490100 A 08/10/2008 574 SBHP 134 6440.08 4450 6200 0.48 4335 3Q-22 029-22625-00 0 490100 AC 08/10/2008 574 SBHP 155 6166.01 1719 6200 0.09 1722 3R -10A 029-22253-01 WI 490100 A 08/12/2008 12480 SBHP 138 6668.82 3856 6200 0.44 3650 3R-15 029-22258-00 WI 490100 A 08/12/2008 7392 SBHP 123 6599.86 2988 6200 0.45 2808 3R-17 029-22242-00 0 490100 A 08/12/2008 624 SBHP 169 6641.35 3944 6200 0.44 3750 3R-18 029-22249-00 O 490100 A 08/12/2008 648 SBHP 166 6567.58 2792 6200 0.4 2645 3R-19 029-22269-00 O 490100 A 08/15/2008 696 SBHP 162 6564.97 3632 6200 0.36 3501 3R-20 029-22250-00 WI 490100 A 08/152008 864 SBHP 139 6649.22 4190 6200 0.43 3997 3R-21 029-22266-00 O 490100 A 1 04/19/2008 792 SBHP 162 6635.65 4230 6200 0.35 4078 3R-22 029.22263.00 WI 490100 A 08/142008 672 SBHP 137 6635.04 4684 62000.44 4493 3R-25 029-22622-00 WI 490100 A 09/082008 1272 SBHP 136 6646.55 4083 6200 0.58 3824 3R-26 029-22626-00 O 490100 A 09/12/2008 10128 SBHP 164 6530.7 3478 6200 0.43 3336 3S -06A 103-2045401 0 490100 C 0721/2008112 SBHP 155 5826.21 3944 6200 0.411 4098 3S -08C 103.20450-03 0 490100 C 07/202008 95 SBHP 153 5690.25 1740 6200 0.35 1918 Forth 10-412 Rev. 1212008 INSTRUCTIONS ON REVERSE SIDE Submit in Duplicate Forth 10-412 Rev. 12/2008 INSTRUCTIONS ON REVERSE SIDE Submit in Duplicate STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION RESERVOIR PRESSURE REPORT 1. Operator. 2. Address: ConomPhillips Alaska Inc. P. O. Box 100360, Anchorage, AK 99510-0360 3. Unit or Lease Name: 4. Field and Pool: 5. Datum Reference: 6. Oil Gravity: 7. Gas Gravity: Kuparuk River Unit Kuparuk River Oil Pool -6200' SS 0.91 (water=l.0 0.71 S. Well Name and 1 9. API Number 10. Type 11. AOGCC 12. Zone 13. Performed 14. Final Test 15. Shut -In 16. Press. 17. B.H. 18. Depth Tool 19. Final 20, Datum 21. Pressure 22. Pressure at Number: 50xxxxxxxxxxxx See Pool Code Intervals Date Time, Hours Surv. Type Temp. TVDSS Observed TVDSS (input) Gradient, psirft. Datum (call NO DASHES Instructions Top -Bottom (see Pressureat TVOSS instructions for Tool Depth codes) 3S-15 103-2044400 O 490100 C 10/18/200815184 SBHP 143 5457.93 2709 6200 0.42 3021 3S -17A 103-20448-01 0 490100 C 07/21/2008112 EXRT1 155 5827.31 3022 6200 0.37 3160 3S-18 103-20433-00 ju 14VUlUU I C I I 07/20/2008101 165HP 1161 5824.37 2917 6200 0.43 13079 35-21 10340452-00 0 490100 C 07/21/2008 113 EXRT7 155 5794.19 2855 6200 0.414 3023 3S -24A 103-20456-M 0 490100 C 04/03/2008 108 SBHP 158 5846.13 2603 6200 0.42 2752 3S-26 103-20361-01 WAG 490100 C 08/15/2008 720 SBHP 131 5760.26 3473 6200 0.43 3662 23. All tests reported herein were made in accordance with the applicable rules, regulations and instructions of the Alaska Oil and Gas Conservation Commission. I hereby certify that the foregoin is true and cortec o 1h est of y knowledge. Signature ��% Title Printed Name �� G` -S I 1� �J`C1r fJ Date Forth 10-412 Rev. 12/2008 INSTRUCTIONS ON REVERSE SIDE Submit in Duplicate Kuparuk Perf Intervals and Stratigraphic Zones WELL NAME PERF TOP SS PERF BTM SS ZONE s WELL NAME PERF TOP SS PERF BTM SS ZONE 1A -04A -6337.77 -6347.06 A 3G-03 -5736.16 -5748.24 AC 1A -04A -6353.48 -6386.3 A -3 -5796.4 -5811.4 AC 1A-16RD -5915.25 -5962.71 C's 3G-03 -5833.86 AC 1A-16RD -5992.34 -6002.5 c 3G-06 -5733.12 -5757.88 A 1A-16RD -6105.55 -6111.88 AM- 3G-06 -5767.79, -5792.65 A 1A-16RD -6119.81 -6137.28 A M3G-10 -5730.33 -5767.85 c 1A-23 -6098.49 -6102.42 A M3G-10 -5802.34 -5812.47 A 1A-23 -6114.23 -6137.86 A �-" 3G-10 -5826.36 -5838.94 A 1A-26 -6072.56 -6077.85 A --K 3G-15 -5748.36 -5759.77 AC 1A-26 -6087.69 -6113.4 A KAC Mom 3G-15 -5759.77 -5782.65 AC 1B-17 -6323.06 -6375.74 C 3G-17 -5719.63 -5764.39 AC 1B-17 -6416.17 -6451.36 C C 3G-17 -5819.73 -5827.241AC 1B-19 -6147.91 -6181.74 3G-20 1 -5764.89 -5772.34 AC 1B-19 -6322.53 -6337.77 AC 3G-20 -5782.97 -5804.24 AC 1B-19 -6337.77 -6353.87 AC I 3G-20 -5814.87 -5836.14 AC 1C-05 -6372.29 -6431.98 8 C C 3G-22 -5773.78 -5802.21 AC 1 C-07 -6402.74 -6454 C C -0- 3G-22 -5802.21 -5822.48 AC 1C-07 -6551.85 -6565.6 9 C C 3G-24 -5748.54 -5777.89 A -6375.68 -6398.92 C RC ---�m 3G-26 -5975.38 -5987.97 A .1c-10 1c-10 -6402.5 -6434.66 C C 3G-26 -6000.62 -6014.251 A 1c-11 -6414.83 -6422.3 c 3 H -07 -5867 -5880.11 AC 1c-11 -6414.83 -6422.3 c C 3H-07 -5900.45 -5913.58 AG 1c-11 -6422.3 -6456.69 c 3H -10B -5951.47 -5969.19 A 1c-11 -6422.3 -6456.69 C 3H -10B -5978.05 -5986.91 A 1C -14A -6453.18 -6485.97 C 3H -10B -6009.99 -6018.88 A IC -14A -6453.18 -6485.97 C 3H-11 -5983.37 -6008.69 c 1C -14A -6473.59 -6453.18 C 3H -14B -6084.97 -6092.54 A 1C -14A -6473.59 -6453.18 C 3H -14B -6104.01 -6111.72 AC 1C-15 -6474.17 -6483.17- C ,,,,,.,,j3H-14B -6111.72 -6115.6 AC 1C-15 -6483.17 -6501.18 C M3H-14B -6135.2 -6143.13 AC 1c-15 -6501.18 -6514.68 C 3H -28A -5846.3 -5869.93 AC IC -18 -6300.36 -6328.49 C 31-09 -6160.48 -6169.88 A 1C-18 -6328.49 -6349.66 c 31-09 -6160.48 -6169.88 A 1C-20 -6487.31 1 -6483.1 C C Z.- 31-09 -6169.88 -6172.23 A 1C-20 -6487.31 I -6483.1 C c kc .31 -09 -6169.88 -6172.23 A 1C-20 -6494.38 -6507.19 c C 31-09 -6172.23 -6174.57 A 1C-20 -6494.38 -6507.19 C C --31-09 -6172.23 -6174.57 A 1C-20 -6512.55 -6520.27 -31-09 -6182.78 -6185.12 A 1 C-20 -6512.55 -6520.27 c . . . . . . . . . . ..... . . . . . .31-09 -6182.78 -6185.12 A 1 C-20 -6531.84 -6540.141 C -.. 31-09 -6185.12 -6187.46 A 1 C-20 -6531.84 -6540.14 C 31-09 -6185.12 -6187.46 A 1 C-21 -6429.43 -6428.16 C -31-09 -6187.46 -6194.471 A 1 C-23 -6434.47 -6455.76 C -6187.46 -6194.47 A C-25 -6342.41 -6363.99 c 31-09 -6201.48 -6202.64 A 1C-25 -6369.97 -6375.94 c 31-09 -6201.48 -6202.64 A 1 C-25 -6449.3 -6461.35 C 31-09 -6202.64 -6213.13 A 460.71 -6461.56 C 31-09 -6202.64 -6213.13 A IC -26 -6461.251 -6460.62 C = 31-09 1 -6213.13 -6224.77 A IC -26 1 -6461.411 -6462.9 C 31-09 6213.13 -6224.77 A Kuparuk Perf Intervals and Stratigraphic Zones WELL NAME PERF TOP SS PERF BTM SS ZONE WELL NAME PERF TOP SS PERF BTM SS ZONE 1C-26 -6464.09 -6462.18 C11":31-11 -6169 -6184.81 A IC -26 -6464.86 -6466.29 C J31-11 -6187.6 -6214.6 A 1C-26 -6467.41 -6466.99 C -31-11 -6222.06 -6230.46 A 1 D-04 -6353.51 -6365.9 C -31-13 -6130.13 -6140.49 A 1D-04 -6365.5 -6374.9 C 31-13 -6145.67 -6170.83 A 1D-04 -6374.5 -6437.45 -31-13 1 -6178.23 -6205.61 A 1D-12 -6419.14 -6438.85 c o 3J-05 -6186.79 -6188.18 A 1D-12 -6419.14 -6438.85 C 3J-05 -6188.18 -6188.87 A 1D-12 -6452.09 -6460.74 c 3J-05 -6188.87 -6190.26 1D-12 -6452.09 -6460.74 c. . . . . 3J-05 -6190.26 -6190.95 A 1D-12 -6460.74 -6461.41 C >a 3J-05 .......... -6190.95 -6192.34 A 1D-12 -6460.74 -6461.4 C ........ .. 3J-05 -6192.34 -6193.03 A ID -12 -6461.4 -6477.43 c 3J-05 -6193.03 -6194.42 A 1D-12 -6461.4 -6477.43 C a 3J-05 -6194.42 -6195.111 A 1D-12 -6508.71 -6510.03 c 3J-05 -6195.11 -6197.89 A 1D-12 -6508.71 -6510.03 c 3J-05 -6197.89 --6198.58 A 1D-12 -6531.88 -6538.47 C 3J-05 -6198.58 -6200.66 A 1D-12 -6531.88 -6538.47 C 3J-05 -6210.36 -6235.23 A 1E-02 -5972.93 -6054.99 AC 3J -07A -6237.15 -6248.29 1E-02 -6174.6 -6194.65 AC 3J-10 -6101.62 -6116.9 -A AC 1E-02 -6208.32 -6221.99 AC 3J-10 -6209.48 -6217.3 AC 1E-08 -6234.95 -6249.2 A 3J-10 -6217.3 -6218.081 AC 1E-08 -6256.28 -6292.76 A 3J-10 -6218.08 -6220.421 AC 1E-12 -6210.18 -6216.77 A 3J-10 -6220.42 -6221.211 AC 1E-12 -6210.18 -6216.77 AC 3J-10 -6221.21 -6225.121 AC 1E-12 -6210.18 -6216.77 A 3J-10 -6239.25 -6242.4 AC 1E-12 -6216.77 -6217.61 A 3J-10 1 -6242.4 -6243.18 AC 1E-12 -6216.77 -6217.6 A 3J-10 -6243.18 -6245.55 AC 1E-12 -6216.77 -6217.6 AC --M3J-10 -6247.12 -6258.17 AC 1E-12 -6228.33 -6230.81 A 3J-14 -6244.64 -6248.35 A 1E-12 -6228.33 -6230.81 A 3J-14 -6248.35 -6254.3 A 1E-12 -6228.33 -6230.81 AC 3J-14 -6254.3 -6261.01 A_ 1E-12 -6230.81 -6239.07 AC .......... 3J-14 -6269.23 -6302.38 A 1E-12 -6230.81 -6239.07 A ---13J-15 -6230.23 -6242.03 c 1E-12 -6230.81 -6239.07 A 3J-15 -6364.63 -6369.66 A 1E-12 -6239.07 -6244.03 A 3J-15 -6369.66 -6370.38 A 1E-12 -6239.07 -6244.03 AC nso 3J-15 -6370.38 -6374.7 A 1E-12 1E-12 -6239.07 -6244.03 -6244.03 -6247.34 A -AC 3J-15 > 3J-15 -6374.7 -6375.42 -6375.42 -6376.14 A A 1E-12 -6244.03 -6247.34 A 3J-15 -6390.58 -6417.45 A 1E-12 -6244.03 -6247.34 A = 3J-17 -6051.13 -6066.21 AC 1E-12 -6253.97 -6258.94 A3J j - 17 -6196.6 -6212.12 AC 1E-12 -6253.97 -6258.94 A - 3J-17 -6228.54 -6247.5 AC 1E-12 -6253.97 -6258.94 AC - 3K-03 -6576.07 -6583.52 A 1E-28 -6017.53 -6100.49 AC ......... 3K-03 -6583.52 -6584.26 A 1 E-28 -6237.21 -6246.79 AC 3K-03 -6584.26 -6589.48 A 1 E-28 -6263.09 -6283.24 C vGG .3K -03 -6589.48 -6590.23 A 1E-31 -5935.41 -5945.13 C 3K-03 -6590.23 -6592.47 1 E-31 -5945.131 -5220�29 c 3K-03 -6592.471 -6593.22 I A 1 E-31 - 60R _EOOE 6 66 C ..... I 3K-03 -6593.221 -6597.71 A Kuparuk Perf Intervals and Stratigraphic Zones WELL NAME PERF TOP ss PERF BTM ss ZONE WELL NAME PERF TOP SS PERF BTM SS ZONE 1E-31 -6006.66 -6008.98 C .......... 3K-03 -6605.2 -6619.49 A 1 E-31 -6008.98 -6011.17 C 3K-03 -6619.49 -6620.24 A 1 E-31 -6011.17 -6013.39 c 3K-03 -6620.24 -6627.03 A 1E-31 -6013.38 -6015.69 C 3K-03 -6627.03 -6627.78 A 1E-31 -6015.65 -6017.93 -C 3K-03 -6627.78 -6628.53 A 1E-31 -6022.13 -6024.45 c 3K-03 -6628.53 -6629.291 A 1 E-31 -6028.33 -6030.02 c 3K-03 -6629.29 -6632.31 A 1E-31 -6030.02 -6032.45 C 3K-03 -6632.31 -6633.07 A IE -31 -6032.45 -6038.83 c 3K-03 -6633.07 -6635.33 A 1E-31 -6041.15 -6048.01 C 3K-03 -6635.33 -6636.09 A 1E-34 -5929.67 -5945.48 c ........ <3K-03 -6636.09 -6644.45 A 1E-34 -5951.03 -5955.95 C 3K-03 -6644.45 -6653.62 A 1E-34 -5958.9 -5971.12 c .. 3K-03 -6653.62 -6655.92 A 1E-34 -5963.92 -5959.76 c 3K-04 1 -6524.96 -6532.791 A 1E-34 -5969.46 -5969.15 C 3K-04 -6532.79 -6536.7 A 1 F-08 -5942.43 -5954.15 A 3K-04 -6536.7 -6538.01 A 1F-08 -5968.81 -5993.77 A 3K-04 -6538.01 -6540.62 A 1F-08 -6001.12 -6004.06 A 3K-04 -6547.13 -6560.16 A 1F-12 -5807.81 -5840.241 C 3K-04 -6560.16 -6565.36 A IG -03 -6014.58 -6039.78 AC x< 3K-04 -6565.36 -6573.82 A 1G-03 -6052.36 -6071.65 AC M3K-04 -6573.821 -6575.12 A 1G-03 -6246.26 -6290.42 ACxg�' ... 1-013K-04 -6575.12 -6578.37 A 1G -08A -6298.16 -6299.74 AC 1101313 K - 0 4 -6578.37 -6584.88 A 1G -08A -6310.73 -6313.88 AC Es 3K-04 -6617.34 -6619.93 A 1G -08A -6326.45 -6328.02 AC M;*�-*' 3K-05 -6607.59 -6622.33 A IG -08A -6655.16 -6662.02 AC� -Mll� 3K-05 .......... -6622.33 -6623.03 A 1G -10A -6254.71 -6265.24 AC 3K-05 -6623.03 -6628.65 A 1G -10A -6265.24 -6274.01 AC 3K-05 -6638.47 -6639.88 A 1G -10A -6284.52 -6289.77 AC > 3K-05 1 -6639.88 -6640.581 A 1G -10A -6296.77 -6303.77 AC 3K-05 -6640.58 -6649.71 A 1G -10A -6513.89 -6540.19 AC U.. 3K-05 -6649.71 -6650.41 A 1G-11 -6256.22 -6297.91 AC 3K-05 -6650.41 -6651.11 A 1G-11 -6369.5 -6407.69 AC 3K-05 -6651.11 -6653.92 A 1G-11 -6594.5 -6598.73 AC 3K-05 -6653.92 -6657.43 A 1G-11 -6607.2 -6624.18 AC 3K-05 -6657.43 -6658.14 A IG -11 -6624.18 -6625.88 AC .......... 3K-05 -6658.14 -6659.54 A IG -13 -6039.76 -6090.14 AC 3K-05 -6660.94 -6661.651 A 1G-13 -6117.59 -6130.39 AC 3K-05 -6665.16 -6670.78 A 1G-13 -6276.64 -6318.73. AC a^« 3K-05 -6705.92 -6708.73 A 1G-14 -6178.47 -6231.37 AC 3K-05 -6711.54 -6718.57 A 1G-14 -6284.41 -6325.1 AC 3K-06 -6565.22 -6569.17 A 1G-14 -6503.75 -6513.68 AC 0-111-.N 3K-06 -6569.17 -6569.96 A 1G-14 -6513.68 -6534.91 AC 3K-06 -6569.96 -6573.12 A 1G-14 -6549.05 -6563.21 AC 3K-06 -6573.12 -6573.91 A 1G-17 -6070.7 -6079.1 AC 3K-06 1 -6573.91 -6577.071 A 1G-17 -6087.43 -6095.71 AC 3K-06 -6577.07 -6577.86 A 1G-17 -6138.78 -6143.81 AC .......... 3K-06 -6577.16 36 -6581.02 A 1G-17 -6143.81 -6144.65 AC -- 3K-06 -6581.02 -6581.81 A 1G-17 -6144.65 -6147.18 -- AC M' 3K-0 -6581.81 -6584.97 A 1-G-171 -6322.69 -6334.061 AC 3K-06 -6584.97 -6585.76 Kuparuk Perf Intervals and Stratigraphic Zones WELL NAME PERF TOP SS PERF BTM SS ZONE WELL NAME PERF TOP SS PERF BTM SS ZONE 1G-17 -6334.06 -6341.66 AC 3K-06 -6585.76 -6588.91 A 1G-17 -6341.66 -6353.09 AC 3K-06 -6588.91 -6589.7 A 1H-16 -6308.33 -6358.76 AC 3K-06 -6589.7 -6592.86 A 1H-16 -6391.53 -6408.36 AC 3K-06 -6592.86 -6593.65 A 1H-16 -6564.38 -6585.5 AC 3K-06 -6593.65 -6596.02 A 1L-04 1L-04 -5953.51 -5980.05 -5966.351 -6005.71 A A 3K-06 3K-06 -6596.021 -6596.81 -6596.81 -6599.96 A A 1L-13 -5818.86 -5821.63 c 3K-06 -6629.91 -6632.28 A 1L-13 -5821.63 -5842.37 c 3K-06 -6632.28 -6642.51 A 1L-13 -5842.37 -5863.12 c 3K -09A -6658.27 -6662.54 A 1L-13 -5863.12 -5865.89 c <> 3K -09A -6658.27 -6662.54 A IL -22 -5873.46 -5905.45 AC s 3K -09A -6662.54 -6666.8 A 1 L-22 -5909 -5915.54 AC 3K -09A -6662.54 -6666.8 A 1L-22 -6037.15 -6055.2 AC -0- 3K -09A -6666.8 -6669.351 A 1L-22 -6097.29 -6106.63 AC 3K -09A -6666.8 -6669.35 A 1L -26A -5823.78 -5825.35 c 3K -09A -6669.35 -6671.06 A 1L -26A -5873.5 -5885.67 C 3K -09A -6669.35 -6671.06 A 1L-28 -5826.88 -5849.03 AC 3K -09A -6671.06 -6673.61 A 1L-28 -5861.47 -5888.2 AC 3K -09A -6671.06 -6673.61 A 1L-28 -6027.45 -6045.78 AC 3K -09A -6684.69 -6688.95 A 1Q-06 -5946.99 -5977.53 AC .......... 3K -09A -6684.69 -6688.95 A 1Q-06 -5995.31 -6010.07 AC 013K -09A -6688.951 -6697.48 A 1Q-06 -6130.22 -6166.08 AC 3K -09A -6688.95 -6697.48 A 1Q-06 -6222.81 -6234.08 AC • 3K -09A -6697.48 -6698.33 A 1Q-14 -6150.03 -6190.75 A 3K -09A -6697.48 -6698.33 A 1Q-14 -6206.25 -6224.75 A 3K -09A -6717.09 -6720.51 A 1Q-15 -6067.76 -6085.04 -AC 3K -09A -6717.09 -6720.51 A 1Q-15 -6159.54 -6166.3 AC 3K -09A -6726.48 -6729.8911 1Q-15 -6264.81 -6312.96 AC 3K -09A -6726.48 -6729.89 A 1Q-15 -6331.04 -6334.91 AC >> 3K-10 -6642.54 -6645 A 1R-02 -6521.37 -6533.95 A 3K-10 -6645 -6645.82 A IR -02 -6543.74 -6564.69 A 3K-10 -6645.82 -6646.65 A 1R-04 -6529.65 -6543.45 A 3K-10 -6646.65 -6647.47 A 1R-04 -6552.67 -6585.01 A 3K-10 -6647.47 -6653.22 A 1 R-09 -6427.66 -6433.48 A 3K-10 -6653.22 -6654.04 1R-09 -6439.31 -6462.65 A '...'...13K-10 -6654.04 -6656.5 A 1R-09 -6485.31 -6488.97 A 3K-10 -6656.5 -6657.32 A 1R-11 -6293.91 -6310.521 AC 3K-10 -6657.32 -6658.96 A 1R-11 -6422.92 -6468.861 AC 3K-10 -6671.26 -6675.35 A 1R-11 -6504.85 -6520.34 AC 3K-10 -6675.35 -6676.17 A 1R-14 -6485.38 -6512.53 C 3K-10 -6676.17 -6681.07 A 1R-14 -6642.37 -6648.25 A 3K-10 -6681.07 -6681.89 1R-14 -6651.19 -6677.75 A t 3K-10 -6681.89 -6685.98 A 1R-14 -6731.38 -6737.37 A 3K-10 -6685.98 -6686.8 A 1R-16 -6382.06 -6403.9 C 3K-10 -6686.8 -6689.25 A 1R-16 -6516.37 -6522.05 A « 3K-10 -6689.25 -6690.06 A 1R-16 -6530.57 -6555.46 A3K -10 -6690.06 -6693.33 A -6593.96 -6608.26 A 3K-10 -6696.59 -6697.41 A 1 R-21 6449.34 -6462.19 AC 3K-10 -6699.85 6700.67 1 R-21 1 -6582.11 -6582.58 AC W 3K-10 -6703.111 -6703.93 A Kuparuk Perf Intervals and Stratigraphic Zones WELL NAME PERF TOP SS PERF BTM SS ZONE WELL NAME PERF TOP SS PERF BTM SS ZONE 1R-21 -6582.58 -6592.64 AC Ell 13K-10 -6706.37 -6707.19 A 1 R-21 -6603.83 -6610.1 AC 13K-10 -6708.81 -6712.07 A 1R-21 -6610.68 -6615.32 AC 3K-14 -6624.71 -6626.27 A IR -21 -6615.74 -6619.22 AC 3K-14 -6626.27 -6635.68 A 1 R-21 -6619.52 -6622.1 AC « 3K-14 -6635.68 -6636.47 A 1R-21 -6622.39 -6624.68 AC 3K-14 -6636.471 -6638.82 A 1R -22A -6460.52 -6468.82 AC 3K-14 -6638.82 -6641.96 A 1R -22A -6617.43 -6628.78 AC 3K-14 -6641.96 -6642.75 A 1R -22A -6632.62 -6631.98 AC 3K-14 -6642.75 -6643.54 A 1R -22A -6632.72 -6634.81 AC =>> 3K-14 -6657.71 -6662.44 A 1R -22A -6632.96 -6630.59 AC 3K-14 -6662.44 -6663.23 A 1R -22A -6637.56 -6639.1 AC 3K 4 -6663.23 -6668.76 A 1R -22A -6638.42 -6635.62 AC 3K-14 -6668.76 -6669.55 A IR -22A -6638.44 -6639.64 AC 3K-14 1 -6669.55 -6673.511 A 1 R -22A -6641.78 -6640.82 AC 3K-14 -6676.68 -6677.47 A 1 R -22A -6646.72 -6653.53 AC z 3K-14 -6680.64 -6681.44 A 1R-35 -6505.88 -6519.0 AC .......... 3K-14 -6685.41 -6686.21 A 1R-35 -6656.36 -6694.75 AC 3K-14 -6690.18 -6690.98 A 1R-36 -6535.51 -6547.34 AC M.. 3K-14 -6697.36 -6705.35 A 1R-36 -6669.21 -6684.48 AC 3K-17 -6434.55 -6450.73 AC IR -36 -6684.48 -6701.45 AC . ..... 3K-17 -6586.31 -6593.5 AC 1R-36 -6721.84 -6726.94 AC 3K-17 -6593.5 -6594.22 AC 1Y -06A -5874.31 -5887.44 AC 3K-17 -6594.22 -6596.38 AC 1Y -06A -5965.65 -5972.13 AC 3K-17 -6596.38 -6597.1 AC 1Y -06A -6091.39 -6116.74 AC 3K-17 -6597.1 -6597.82 AC 1Y -06A -6135.69 -6148.291 AC . 3K-17 -6597.82 -6598.55 AC 1Y -15A -5898.79 -5905.5 AC 3K-17 -6598.55 -6599.27 AC 1Y-17 -6055.72 -6065.09 A = 3K-17 -6599.27 -6599.99 AC 1Y-17 -6076.24 -6093.04 A3K -17 -6599.991 -6600.71 AC I 1y-19 -6085.63 -6110.87 A 3K-17 -6615.211 -6616.67 AC 1Y-22 -6086.48 -6105.45 A 3K-17 -6616.67 -6617.39 AC 1Y-22 -6115.43 -6135.38 A3K-17 -.. A -6617.39 -6626.15 AC 1Y-23 -5812.31 -5887.44 C .n.,.g..13K-17 -6626.15 -6626.88 AC 1Y -26A -5790.33 -5815.73 AC M3K-17 -6626.88 -6627.61 AC 1Y -26A -5827.59 -5861.51 AC 3K-17 -6632.74 -6633.48 AC 1Y -26A -5868.3 -5881.88 AC 3K-17 -6636.41 -6637.15 AC 1Y -26A -5962.65 -5966.911 AC 3K-17 -6640.09 -6640.82 AC 1Y -26A -5973.72 -5990.74 AC AC 3K-17 -6648.94 -6653.37 AC 1Y -26A -6000.95 -6022.23 AC 3K-17 -6686.88 -6692.87 AC 1Y-29 -5959.98 -5965.6 AC 3K-18 -6598.57 -6607.49 A 1Y-29 -5969.61 -5981.66 AC �W 3K-18 -6607.49 -6608.18 A 1Y-29 -5991.32 -6026.03 3K-18 -6608.18 -6610.92 A 1Y-29 -6056.86 -6067.44 AC 3K-18 -6610.92 -6611.61 A 1Y-30 -6001.1 -6005.41 A . ...... 3K-18 -6611.61 -6612.9811 1Y-30 -6005.41 -6053.38 A ....... ..-.13K-18 -6612.98 -6613.66 A 1Y-30 -6053.38 -6068.12 A 3K-18 -6613.66 -6614.35 A 1Y-30 -6093.44 -6105.46 A .......... 3K-18 -6614.35 -6615.04 A 1Y-32 -6020.87 -6027.74 AC 3K-18 -6615.04 -6619.16 A 1Y-32 -6033.75 -6049.21 AC 3K-18 -6631.52 -6632.21 A 11Y-32 1 -6060.38 -6102.54 AC 3K-18 -6632.21 -6632.89 A Kuparuk Perf Intervals and Stratigraphic Zones WELL NAME PERF TOP SS PERF BTM SS ZONE WELL NAME PERF TOP SS PERF BTM SS ZONE 1Y-34 -6021.98 -6026.88 -6026 '8 A A M3K-18 -6632.89 -6633.58 A 1Y-34 -6026.88 -6043.29 A A 3K-18 -6633.58 -6634.27 A 2A-03 -5808.94 -5850.75 AG A .......... . . . . . . . . . . . 3K-18 -6634.27 -6637.71 A 2A-03 -5850.75 -5853.53 C............. A AC ...... . . . . . 3K-18 -6637.71 -6638.39 A 2A-03 -5898.13 -5899.52 A C AC 3K-18 -6638.39 -6641.15 A 2A-03 -5919.73 -5932.97 A C. AC . . . . . . . . . . 3K-18 -6641.151 -6641.83 A 2A-03 -5942.72 -5973.38 A AC C 3K-18 -6641.83 -6643.21 A 2A-05 -5774.44 -5799.79 AC C AC 3K-18 -6643.21 -6643.9 A 2A-05 -5821.17 -5822.51 I AC......... AC .... 3K-18 -6643.9 -6644.59 A 2A-05 -5822.51 -5830.5 5830 53 AC AC j3K-18 -6644.59 -6645.27 A 2A-05 -5830.53 5 88 5835.88 AC AC 3K-18 -6645.27 -6649.4 A 2A-05 -5843.91 525 -5845.25 AC AC �--`R 3K-18 -6649.4 -�656.29 A 2A-05 -5845.25 -5869.38 38 AC AC 3K-23 -6501.94 -6603.76 2A-05 -5869.38 -5883.49 C AC 0` ..... 3K-24 -6557.51 -6620.17 A 2A-09 -5812.21 1 -5816.25 ---- ATC- C .... -3K---25 -6535.55 -6550.19 A 2A-09 -58i-6-25- -5829 7 1 C AC 3K-25 -6558.74 -6601.64 A 2A-09 -5D807Z -5843.17 8 1 AC C 3K-27 -6623.85 -6637.62 A 2A-09 -5883.55 -5890.28 AC .... 13K-30 -6608.06 -6622.55 A 2A-09 -5903.06 -5925.271 AC 3K-30 -6634.13 -6648.61 A 2A-24 -5715.29 -5748.72 AC 3K-30 -6650.06 -6664.53 A 2A-24 -5790.86 -5818.46 AC ---z 3K-32 -6561.88 -6579.431 A 2B-02 -5816.76 -5852.19 AC :3K-32 -6595.22 -6612.761 A 2B-02 -5867.4 -5869.09 AC 3K-35 -6370.22 -6386.13 A 2B-02 -5896.14 -5972.14 ACM - 3K-35 -6398.92 -6416.61 A 2B -03A -5863.88 -5876.16 -AC 3M-03 -6157.23 -6172.81 AC 2B -03A -5974.63 -5993.03 AC3M-03 .1 -6157.23 -6172.81 AC .2B-08 -5830.53 -5860.42 AC 3M-03 -6182.71 -6191.19 AC 2B-08 -5929.98 -5935.16 AC 3M-03 -6182.71 -6191.19 AC 2B-08 -5944.65 -5964.53 -AC § B 3M-03 -6196.84 -6204.59 AC 2B-08 -5982.71 -6000.93 AC 3M-03 -6196.84 -6204.591 A 2C-10 -5755.78 -5761.29 AC 3M-03 -6204.59 -6205.3 AC 2C-10 -5845.62 -5846.28 AC 3M-03 -6204.59 -6205.3 AC 2C-10 -5846.28 -5849.59 AC 3M-03 -6205.3 -6206.71 AC 2C-10 -5849.59 -5850.26 AC ,.,.,.13M-03 -6205.3 -6206.71 AC 2C-10 -5850.26 -5852.9 AC 6.71 -6210.93 AC 2C-10 -5853.57 -5854.23 AC . .... 3M-03 -6206.71 -6210.93 AC 2C-10 -5863.48 -5864.14 -AC 3M-03 -6220.79 -6240.46 A 2C-10 -5864.14 -5867.44 AC .......... 3M-03 -6220.79 -6240.46 AC 2C-10 -5867.44 -5868.1 AC xM a3M-03 -6244.67 -6247.48 Tkc 2C-10 -5868.1 -5871.39 AC 3M-03 -6244.67 -6247.48 AC 2C-10 -5871.39 -5872.05 AC 3M-06 -6140.94 -6149.03 AC 2C-10 1 -5872.05 -5874.68 AC s 3M-06 -6159.57 -6179.85 AC 2C-10 -5874.68 -5875.34 AC 3M-06 -6184.73 -6187.98 AC 2C-10 -5875.34 -5877.97 AC 3M-07 -6157.86 -6174.02 AC 2C-10 -5877.97 -5878.63 TC- -3-M07 -6185.34 -6186.96 AC 2C-10 -5878.63 -5881.26 AC 3M-07 -6186.96 -6188.57 AC 2C-10 -5881.26 -5881.91 AC 3M-07 -6188.57 -6191 Ac 2C-10 -5881.91 -5884.54 AC 3M-07 -6191 -6191.81 AC 8��5� -5885.2 AC 3M-07 -6191.81 -6192.62 AC 12C-10 1 -5885.21 -5887.82 AC 3M-07 -6197.47 -6199.891 AC Kuparuk Perf Intervals and Stratigraphic Zones WELL NAME PERF TOP SS PERF BTM SS ZONE WELL NAME PERF TOP SS PERF BTM SS ZONE 2C-10 -5887.82 -588 48 -5888.48 AC A 3M-07 -6199.89 -6201.51 AC 2C-10 -5915.87 -5919.76 AC A C 3M-07 -6201.51 -6208.78 AC 2C-10 -5946.14 -5953.8 A C......... AC ........ ... 3M-07 -6212.82 -6215.25 AC 2C-11 -5770.07 -5786.78 C AC A 3M-07 -6219.29 -6220.9 AC 2C-11 -5844.76 -5853.21 AC A C 3M-07 -6220.9 -6221.71 AC 2C-11 -5861.68 -5890.58 C AC A 3M-07 -6221.711 -6224.13 AC 2C-12 -5737.67 -5747.06 A AC C 3M-07 -6224.13 -6237.06 AC 2C-12 2C-12 -5795.53 -5815.06 -5804.91 -5845.52 A C. AC A AC C . . . . . . . . . . . . 3M-07 3M-08 -6240.29 -6122.33 -6244.32 -M7.94 AC AC 2C-12 -5890.1 -5898.72 A C AC g;-`-= UM -08 -6147.42 -6152.43 AC 2C-14 -5689.67 -5707.66 f-58826.222 AC C AC 3M-08 -6152.43 -6154.66 AC 2C-14 -5793.89 -5802.42 AC AC 3M-08 -6154.66 -6158.55 AC 2C-14 -5810 -5837.49 AC _. 0.13M-08 -6161.34 -6166.911 AC 2C-14 -5862.13 -5873.51 AC �MM'3M-08 -6166.91 -6170.241 AC 2D-01 -5854.3 -5858.53 A 3M-08 -6170.24 -6172.47 AC 2D-01 -5858.53 -5860.22 A 3M-08 -6181.36 -6200.24 AC 2D-01 -5860.22 -5866.1�3 1 A -d-m -09 -6226.03 -6237.98 AC 2D-01 -5878.83 A 3M-09 -6243.95 -6273.82 AC 2D-01 -5882.22 -5890.7 A:3M-09 -6273.82 -6275.81 AC 2D-01 -5890.7 -5897.5 A 3M-09 -6277.8 -6279.79 AC 2D-01 -5897.5 -5899.19 A ..... -1 3M-09 -6279.791 -6305.67 AC 2D-01 -5899.19 -5901.75 A3M-09 -6305.671 -6307.66 AC 2D-01 -5901.75 -5902.6 A 3M-14 -6176.791 -6178.48 A 2D-01 -5902.6 -5910.25 A 3M-14 -6180.171 -6181.01 A 2D-01 -5910.25 -5911.96 A -13M-14 -6183.55 -6184.39 A 2D-01 -5911.96 -5912.87 A 3M-14 -6188.62 -6220.76 A 2D-05 -5823.07 -5862.14 AC S 3M-15 -6180.3 -6210.84 A 2D-05 -5951.62 -5960.63 AC z 3M-16 -6160.86 -6168.871 AC 2D-05 -5971.45 -6009.48 AC 3M-16 -6168.87 -6169.76 AC 2D-08 -5843.2 -5865.75 AC 3M-16 -6169.76 -6170.65 AC 2D-08 -5953.75 -5955.4 AC 3M-16 -6170.65 -6171.54 AC 2D-08 -5955.4 -5966.93 AC 3M-16 -6171.54 -6172.43 AC 2D-08 -5980.15 -6011.72 AC 3M-16 -6172.43 -6173.32 AC 2D-14 -5789.75 -5801.8 AC F 3M-16 -6173.32 -6174.21 AC 2D-14 -5836.62 -5850.32 AC 3M-16 -6174.21 -6175.1 AC 2D-14 -5861 -5902.431 AC 3M-16 -6175.1 -6175.991 AC 2E-10 -5906.76 -5926.71 A 3M-16 -6181.34 -6211.67 AC 2E-10 -5956.76 -5926.71 A 3M-22 -6127.4 -6139.03 AC 2E-10 -5948.65 -5956.63 A -01- 3M-22 -6158.45 -6170.11 AC 2E-10 -5948.65 -5956.63 A 3M-22 -6174 -6178.53 AC 2E-10 -5985.56 -5993.55 A 3M-22 -6178.53 -6179.17 AC 2E-10 -5985.56 -5993.55 A 3M-22 -6179.17 -6181.76 AC 2E-12 -5887.75 -5902.64 A =G 3M-22 -6181.761 -6182.41 AC 2E-12 -5920.49 -5946.46 A 3M-22 -6182.41 -6186.29 AC 2E-12 -5957.57 -5963.49 A 3M-22 -6186.29 -6186.93 AC 2E-13 -5974.9 -5993.21 A 2 -6197.26 -6210.14 AC .2E-13 -6003.89 -6028.31 A -6210.14 -6210.79 AC 14 -5897.87 -5914.05 A -6210.79 6223 AC E- 2E-14 -5924.35 -5945.68 A -6231.25 -0657.15 12E-14 1 -5953.77 -5962.61 A -5997.84 -6013.76 A Kuparuk Perf Intervals and Stratigraphic Zones WELL NAME PERF TOP SS PERF BTM SS ZONE WELL NAME PERF TOP SS PERF BTM SS ZONE 2E-16 -5893.5 -5907.3 A 3N-01 -6258.52 -6263.88 A 2E-16 -5922.64 -5946.41 A a 3N-01 -6263.88 -6267.24 A 2F -05X -5830.28 -5839.47 A 3N-01 -6267.24 -6270.59 A 2F -05X -5848.66 -5872.61 A 3N-01 -6277.3 -6286.01 A 2F-08 -5770.14 -5782.47 AC 3N-01 -6286.01 -6290.69 A 2F-08 -5844.99 -5854.46 AC >< 3N-01 1 -6290.69 -6304.081 A 2F-08 -5866.77 -5897.07 AC 3N -02A -6348.68 -6357.39 A 2F-12 -5841.69 -5853.39 A 3N -02A -6348.68 -6357.39 A 2F-12 -5866.78 -5900.3 A 3N -02A -6357.39 -6358.18 A 2G-02 -5928.56 -5941.79 A 3N -02A -6357.39 -6358.18 A 2G-02 -5953.59 -5982.09 A aas 3N -02A -6358.18 -6360.56 A 2G-15 -5967.26 -5968.64 A 3N -02A -6358.18 -6360.56 A 2G-15 -5968.64 -5970.02 A 3N -02A -6360.56 -6361.35 A 2G-15 -5970.02 -5972.79 A 3N -02A -6360.56 -6361.351 A 2G-15 -5972.79 -5974.17 A 3N -02A -6361.35 -6364.52 A 2G-15 -5974.17 -5978.32 A 3N -02A -6361.35 -6364.52 A 2G-15 -5992.19 -5994.27 A 3N -02A -6372.45 -6397.79 A 2G-15 -5994.27 -5996.36 A 3N -02A -6372.45 -6397.79 A 2G-15 -5996.36 -5997.75 A 3N-03 -6230.62 -6237.71 A 2G-15 -5997.75 -5999.83 A 3N-03 -6230.62 -6237.71 A 2G-15 -5999.83 -6003.311 A 3N-03 -6230.62 -6237.71 A 2G-15 -6003.31 -6004.7 A 13N-03 -6230.62 -6237.71 A 2G-15 -6004.7 -6007.49 A ,113N-03 -6230.621 -6237.71 A 2G-15 2G-15 -6007.49 -6008.88 -6008.88 -6013.06 A A H 3N-03 3 N - 0 3 -6230.62 -6237.71 -6237.71 -6238.5 A A 2G-15 -6013.06 -6015.15 A 3N-03 -6237.71 -6238.5 A 2G-15 -6015.15 -6022.83 A 3N-03 -6237.71 -6238.5 A 2H-05 -5975.37 -5978.42 A 3N-03 -6237.71 -6238.5 A 2H-05 -5978.42 -5989.85 A ..... 3N-03 .......... -6237.71 -6238.51 A 2H-05 -5989.85 -5996.73 A3N-03 -6237.71 -6238.5 2H-05 -6018.18 -6038.16 A. . . . . . . . . . . . . . . . . . . . . . .. .. .. . 3N-03 -6238.5 -6239.29 2H-10 -5974.07 -5998.92 A I 3N-03 -6238.5 -6239.29 A 2H-10 -6023.03 -6038.87 A M 3N-03 -6238.5 -6239.29 A 2H-11 -5907.73 -5915.35 AC 3N-03 -6238.5 -6239.29 A 2H-11 -5963.54 -5980.4 AC 3N-03 -6238.5 -6239.29 A 2H-11 -6003.13 -6022.47 -AC 3N-03 -6238.5 -6239.29 A 2H-12 -5946.51 -5954.44 A 3N-03 -6239.29 -6240.08 A 2H-12 -5975.27 -5996.71 A u^3N-03 -6239.29 -6240.081 A 2H-13 -5939.03 -5939.83 AC 3N-03 -6239.29 -6240.08 A 2H-13 -5940.62 -5941.42 3N-03 -6239.29 -6240.08 A 2H-13 -5974.08 -5978.07 AC 3N-03 -6239.29 -6240.08 A 2H-13 -5988.44 -5999.61 AC 3N-03 -6239.29 -6240.08 A 2H-13 -5999.61 -6010 AC ..... 3N-03 -6240.08 -6244.81 A 2H-13 -6022.79 -6043.6 -AC 3N-03 -6240.08 -6244.81 A 2K-02 -5946.3 -5986.74 AC 3N-03 -6240.08 -6244.81 A_ 2K-02 -6013.6 -6041.97 AC 3N-03 -6240.08 -6244.81 A 2K-06 -5977.71 -5992.46 AC 3N-03 -6240.08 -6244.81 A 2K-06 -6027.6 -6055.41 AC 3N-03 -6240.08 -6244.81 A 2K-09 -603i§ -6062.94 A 3N-03 -6251.9 -6270.03 A 2K-19 -613E1?61 -6154.72 A -6251.9 -6270.03 Kuparuk Perf Intervals and Stratigraphic Zones WELL NAME PERF TOP SS PERF BTM SS ZONE WELL NAME PERF TOP SS PERF BTM SS ZONE 2K-22 -6174.65 -6183.75 A 3N-03 -6251.9 -6270.03 A 2K-22 -6189.13 -6190.91 A 3N-03 -6251.9 -6270.03 A 2K-22 -6208.73 -6225.3 A 3N-03 -6251.9 -6270.03 A 2K-26 -6013.36 -6025.16 A 3N-03 -6251.9 -6270.03 A 2K-26 -6044.02 -6065.E A 3N-03 -6284.22 -6289.74 A 2K-27 -6026.93 9 -6043.69 A 3N-03 -6284.22 -6289.741 A 2M-06 -5828.68 -5842.29 A 3N-03 -6284.22 -6289.74 A 2M-06 -5842.29 -5857.46 A -6284.22 -6289.74 A 2M-08 -6006 -6027.88 AMs' 3N-03 -6284.22 -6289.74 A 2M -09A -5887.7 -5897.45 A 3N-03 -6284.22 -6289.74 A 2M -09A -5903.96 -5927.62 A 3N-04 -6206.62 -6215.34 AC 2M -09A -5940.71 -5994.14 A 3N-04 -6239.81 -6242.44 AC 2M-10 -5826.46 -5833.78 AC 3N-04 -6242.44 -6245.06 AC 2M-10 -5846.22 -5852.08 AC 3N-04 -6245.06 -6248.571 A 2M-10 -5855.74 -5868.93 AC 3N-04 -6251.19 -6257.321 A 2M-10 -5877 -5891.66 ACm- 3N-04 -6263.45 -6268.71 AC 2M-10 -5891.66 -5906.34 AC 3N-05 -6115.96 -6123.37 A 2T -12A -5721.94 -5747.94 C 3N-05 -6123.37 -6124.11 A 2T -12A -5814.02 -5845.17 A --m 3N-05 -6124.11 -6127.07 A .2T-27 -5730.63 -5745.29 A 3N-05 -6134.49 -6141.91 A 2T-27 -5767.29 -5780.5 A 3N-05 -6141.91 -6142.65 A 2T-27 -5792.24 -5797.38 A 3N-05 -6142.65 -6144.14 A 2T-31 -5681.32 -5697.45 A 3N-05 -6144.14 -6147.8511 2T-31 -5723.41 -5733.191 A 3N-05 -6164.19 -6185.01 A 2T -38A -5726.83 -5727.99 A 3N-06 -6351.21 -6354.38 A 2T -38A -5727.99 -5729.15 A 3N-06 -6354.38 -6355.17 A 2T -38A -5729.15 -5738.43 A 3N-06 -6355.17 -6355.96 A 2T -38A -5759.84 -5765.61 A 3N-06 -6355.96 -6356.75 A 2T-39 -5766.02 -5772.14 AC 3N-06 -6356.75 -6358.34 A 2T-39 -5783.32 -5790.45 AC 3N -06 -6371.031 -6375 A 2T-39 -5814.97 -5823.18 AC 3N-06 -6375 -6375.791 A 2T-39 -5838.62 -5843.8 AC 3N-06 -6375.79 -6379.76 A 2T-40 -5711.73 -5719.84 A 3N-06 -6379.76 -6380.56 A 2T-40 -5711.73 -5719.84 A 3N-06 -6380.56 -6390.9 A 2T-40 -5726.33 -5734.46 A 3N -08A -6226.55 -6235.11 AC 2T-40 -5726.33 -5734.46 A 3N -08A -6291.56 -6298.4 AC 2U-09 -5707.32 -5743.52 A 3N -08A -6298.4 -6299.25 AC 2U-09 -5755.56 -5782.28 A =aG 3N -08A -6299.25 -6300.96 A 2U-13 -5666.72 -5737.44 AC -a 3N -08A -6300.96 -6301.81 AC 2U-13 -5889.34 -5893.66 AC '� 3N -08A .......... -6301.81 -6310.35 AC 2U-13 -5899.41 -5934.95 AC 3N -08A -6312.06 -6337.66 AC 2U-13 -5967.29 -5971.73 AC .......... 3N -08A -6347.03 -6352.151 AC 2U-13 -5993.28 -5997.01. AC 3N-09 -6274.11 -6278.41 AC 2V-09 -5671.37 -5718.91 AC 3N-09 -6278.41 -6279.12 AC 2V-09 -5729.6 -5734.94 AC 3N-09 -6279.12 -6279.84 AC 2V-09 -5740.28 -5743.33 AC 3N-09 -6299.18 -6308.49 AC 2V-09 -5813.31 -5823.96 C - 3N-09 -6314.22 -6321.39 AC 2V-09 -5833.85 -5860.47 AC- - ...... 3N-09 -6321.39 -6322.1 AC 2V-11 -5650.77 -5667.17 AC 3N-09 -6322��l 32 AC 12V- 11 1 -5667.99 -5686.01 AC 3N-09 -632 3�7� 2 AC Kuparuk Perf Intervals and Stratigraphic Zones WELL NAME PERF TOP SS PERF BTM SS ZONENAME WELL lid PERF TOP SS PERF BTM SS ZONE 2V-11 -5692.57 4 -5695.84 AC AC .R 3N-09 -6327.12 -6335.71 AC 2V-11 -5700.75 8 -5706.4� AC AC 11 . . . . . . . . . . . . . . . . 3N-09 -6340.01 -6347.17 AC 2V-11 -5789 -5803.68 8 AC AC 3N-09 -6347.17 -6347.89 AC 2V-11 -5816.72 1 -5844.41 AC AC 3N-09 -6347.89 -6349.32 AC 2V-14 -5699.11 8 -5723.48 AC AC KA . . . . . . . . . 3N-09 -6349.32 -6350.04 AC 2V-14 -5804.33 -5809.97 7 AC AC m.,- 3N-09 1 -6350.04 -6354.331 AC 2V-14 -5815.6 -5829.26 C 3N-09 -6354.33 -6355.77 AC 2V-14 -5838.9 -5877.35 AC 3N-09 -6355.77 -6360.07 AC 2V-14 -5912.58 -5915.7 9 C AC 3N-09 -6360.07 -6364.36 AC 2V-14 -5923.8 -5930.21 AC 3N-09 -6364.36 -6374.39 AC 2V-15 -5794.49 -5803.96 A 3N-10 -6437.29 -6448.44 A 2V-15 -5894.91 -5903.E A 3N-10 -6448.44 -6449.1 A 2V-16 -5789.68 -5797.59 -A 3N-10 -6449.1 -6449.75 A 2V-16 -5803.92 -5835.5 A C.-.- 3N-10 -6449.751 -6450.41 A 2V-16 -5876.48 -5884.35 A -.1-1 3N-10 -6450.411 -6451.06 A 2W-01 -5933.25 -5937.49 A 3N-10 -6451.06 -6451.72 A 2W-01 -5950.18 -5981.08 A aa<r 3N-10 -6451.72 -6452.38 A 2W-01 -6029.14 -6040.23 -A 3N-10 -6462.21 -6466.8 A 2W-07 -5701.65 -5762.94 AC 3 N - 13 -6302.3 -6317.58 AC 2W-07 -5701.65 -5762.94 AC s 3N-13 -6357.31 -6361.9 AC 2W-07 -5862.92 -5863.91 AC €==3N-13 -6361.9 -6364.19 AC 2W-07 -5862.92 -5863.91 AC 3N-13 -6364.19 -6365.72 AC 2W-07 -5863.91 -5904.52 AC =3N-13 -6365.72 -6367.25 AC 2W-07 -5863.91 -5904.52 AC M3N-13 -6367.25 -6368.01 AC 2W-07 -5904.52 -5905.51. AC 3N-13 -6374.89 -6383.29 AC 2W-07 -5904.52 -5905.51 AC 3N-13 -6383.29 -6386.35 AC 2W-17 -5871.6 -5877.07 A 3N-13 -6386.35 -6389.4 AC 2W-17 -5888.92 -5911.76 A 3N-13 -6389.4 -6390.93 A 2W-17 -5948.39 -5979.68 -A 3N-13 -6390.93 -6392.46 AC 2X-07 -5701.83 -5772.63 AC 3N -13 -6406.21 -6431.43 AC 2X-07 -5889.24 -5897.97 AC R- 3N-15 -6422.99 -6429.2 A 2X-07 -5908.42 -5934.45 AC 3N-15 -6429.2 -6430.76 A 2X-08 -5713.08 -5740.34 AC 3N-15 -6430.76 -6432.31 A 2X-08 -5740.34 -5767.61 AC 3N-15 -6432.31 -6433.09 A 2X-08 -5776.71 -5794.9 AC Q. 3N-15 -6433.09 -6435.42 A 2X-08 -5932.79 -5963.57 AC 3N-15 -6443.18 -6450.9511 2X-08 -5963.57 -5964.48 AC 3N-15 -6450.95 -6451.72 A 2X-08 -5964.48 -5985.29 AC -6451.72 -6453.28 A 2X-09 -5638.2 -5694.631 AC -6453.28 -6454.05 A 2X-09 -5700.23 -5723.25 AC 3N-15 -6454.05 -6454.83 A 2X-09 -5792.85 -5798.31 AC 3N-15 -6454.83 -6455.6 A 2X-09 -5803.77 -5810.59 AC 3N-15 -6455.6 -6457.16 A 2X-09 -5810.59 -5817.4 AC 3N-15 -6457.16 -6457.93 A 2X-09 -5817.4 -5822.84 AC 3N-15 -6457.93 -6459.491 A 2X-09 -5835.05 -5856.68 AC 3N-15 -6461.04 -6471.91 A 2X-11 -5708.05 -5726.22 AC 3N-16 -6420.06 -6436.72 c 2X-11 -5726.22 -5735.31 AC 3N-16 -6513.76 -6520.12 A 2X-11 -5744.36 -5753.43! 3N-16 -6520.12 -6521.71 A 12X-11 -5753-.43- -5782.46 AC 3N-16 -6521.71 -6523.3 A 12X-11 1 -5901.57 -5911.62 AC 3N-16 -6523.3 -6528.08 A Kuparuk Perf Intervals and Stratigraphic Zones WELL NAME PERF TOP SS PERF BTM SS ZONE WELL Im NAME PERF TOP SS PERF BTM SS ZONE 2X-11 -5922.58 -5948.21 AC =3N-16 -6532.85 -6536.04 A 2X-14 -5716.1 -5807.32 AC M3N-16 -6536.04 -6540.02 A 2X-14 -5955.35 -5957.03 AC MM3N-16 -6540.02 -6541.61 A 2X-14 -5957.03 -5965.43 AC 3N-16 -6541.61 -6543.2 A 2X-14 -5965.43 -5972.15 AC 3N-16 -6543.2 -6544.8 A 2X-14 -5980.54 -5997.32 AC 3N-16 -6544.8 -6548.781 A 2X-14 -5997.32 -6005.71 AC .. 3N-16 -6548.78 -6549.57 A 2X-15 -5728.58 -5773.E AC 3N-16 -6549.57 -6551.96 A 2X-15 -5788.79 -5803.69 --KC- 3N-16 -6551.96 -6562.32 A 2X-15 -5949.53 -5969.57 AC 3N-18 -6449.67 -6461.13 A 2X-15 -5981.68 -6002.28 AC 3N-18 -6461.13 -6462.41 A 2X-16 -5708.23 -5770.8 AC 3N-18 -6462.41 -6463.69 A 2X-16 -5884.76 -5891.42 AC 3N-18 -6476.53 -6489.46 A 2X-16 -5896.76 -5903.45 AC. . . . . . .sA 3N-18 .......... . . . . . . . . . . . . . . -6489.46 -6490.75 A 2X-16 -5910.15 -5915.52 AC 3N-18 -6490.75 -6492.05 A 2X-16 -5935.73 -5950.64 AC 3N-18 -6492.05 -6492.7 A 2X-18 -5852.4 -5868.01 A 3N-18 -6499.2 -6513.59 A 2X-18 -5890.02 -5904.26 -A - nt� __f 3N-18 . -6544.69 -6547.37 A 2X-19 -5689.07 -5735.9 c 3N-18 -6550.05 -6556.11 A 2X-19 -5735.9 -5767.9f -C -1.0' 30-01 -6563.69 -6575.4 A 2X-19 -5767.91 -5769.361 C --30-01 -6563.69 -6575.4 2X-19 -5769.36 -5780.95 C. -30-01 -6577.74 -6590.2411 2Z-05 -6009.32 -6013.04 A 30-01 -6577.74 -6590.24 A 2Z-05 -6021.96 -6046.53 A 30-01 -6609.02 -6624.7 A 2Z-10 -5764.52 -5780.5 AC 30-01 -6609.02 -6624.7 A 2Z-10 -5780.5 -5828.51 AC 30-04 -6483.35 -6495.06 A 2Z-10 -5938.93 -5945.24 AC 30-04 -6499.45 -6516.3 A 2Z-10 -5953.91 -5982.99 AC `-M. 30-04 -6525.1 -6539.76 A 2Z -13A -5919.75 -5924.391 AC 30-06 -6512.061 -6520.22 A 2Z -13A -5919.75 -5924.39 AC 30-06 -6526.74 -6546.321 A 2Z -13A -5966.65 -5987.17 AC SK -130-06 -6552.04 -6568.38 A 2Z -13A -5966.65 -5987.17 A 30-07 -6614.91 -6624.55 A 2Z -13A -5966.65 -5987.17 AC 30-07 -6632.58 -6651.86 A 2Z -13A -5987.54 -5995.56 AC 30-07 -6664.72 -6680.8 A 2Z -13A -5987.54 -5995.56 AC 30-10 -6450.68 -6459.65 A 2Z -13A -5987.54 -5995.56 A 30-10 -6467.12 -6485.07 A 2Z -13A -5999.66 -5992.02 AC 30-10 -6492.54 -6507.49 A 2Z -13A -5999.66 -5992.0 A a 30-11 -6478.97 -6487.341 2Z -13A -5999.66 -5992.021 AC ...-30-11 -6494.87 -6512.48 A 2Z-18 -5779.19 -5794.15 _7C- z3O-11 -6524.25 -6541.1 A 2Z-18 -5800.14 -5841.03 AC 30-12 -6556.14 -6566.04 A 2Z-18 -5845.02 -5846.02 AC 5.�MX 30-12 -6571 -6594.77 A 2Z-18 -5952.74 -5960.72 c 30-12 -6606.66 -6626.47 A 2Z-18 -5968.7 -5992.63 AC 30-13 -6561.34 -6582.77 A 2Z-18 -6013.58 -6026.55 AC 30-13 -6582.77 -6586.08 A 2Z-20 -5762.021 -5821.16 AC 30-13 -6586.08 -6627� A 2Z-20 -5762.02 -5821.161 AC -.-.-..-.30-13 -661-7.5--4 -6634.16 A 2Z-20 -5941.68 -5942.3§1 AC 30-14 -6543.67 -6555.28 A 2Z-20 -5941-.68- -5942.38 AC 30-14 -6543.67 -6555.28 A 12Z-20 -5942.38 -5947.31 AC ---%-30-14 -6561.92 -6578.53 A Kuparuk Perf Intervals and Stratigraphic Zones WELL NAME PERF TOP SS PERF BTM SS ZONE WELL NAME PERF TOP SS PERF BTM SS ZONE 2Z-20 -5942.38 -5947.3 AC M30-14 -6561.92 -6578.53 A 2Z-20 -5947.3 -5948.71 AC 30-14 -6598.47 -6615.09 A 2Z-20 -5947.3 -5948.71 AC «<> 30-14 -65T98.47 -6615.09 A 2Z-20 -5956.44 -5960.66 AC 30-15 -6374.01 -6383.79 A 2Z-20 -5956.44 -5960.66 30-15 -6387.71 -6402.05 A 2Z-20 -5960.66 -5971.9 AC 30-15 1 -6416.38 -6430.051 A 2Z-20 - 5960.66 - 5971.9 C 30-18 -6466.64 -6484.07 AC 2Z-20 -5971.9 -5976.83 AC -30-18 -6492.8 -6523 AC 2Z-20 -5971.9 -5976.83 AC 30-18 -6535.74 -6558.07 AC 2Z-20 -5995.12 -6006.39 AC t 30-18 -6566.05 -6598.03 AC 2Z-20 -5995.12 -6006.39 AC 30-18 -6609.24 -6625.26 AC 2Z-21 -5782.3 -5849.76 AC 3Q-01 -6464.32 -6509.4 A 2Z-21 -5979.99 -5997.36 AC 3Q-04 -6431.31 -6438.15 A 2Z-21 -6013.78 -6032.12 AC 3Q-04 1 -6438.15 -6448.411 A 3A -03B -6063.22 -6102.82 A 3Q-04 -6450.97 -6485.21 A 3A -03B -6102.82 -6120.42 A3Q . . . . . . ........... ...... -05 -6171.44 -6173.05 A 3A-06 -5866.11 -5924.46 C 3Q-05 -6173.05 -6205.25 A 3A-06 -5866.11 -5924.46 c 3Q-07 -6195.2 -6207.97 A 3A-06 -5866.11 -5924.46 AC ...... 3Q-07 -6210.66 -6224.11 A 3A-06 -6016.31 -6017.07 A .. 3Q-07 -6230.83 -6257.73 A 3A-06 -6016.31 -6017.07 AC 3Q-09 -6233.96 -6252.29 A 3A-06 -6016.31 -6017.07 A 3Q 09 -6256.45 -6262.29 AC 3A-06 -6017.07 -6032.38 A i 3Q-09 -6262.29 -6285.62 AC 3A-06 -6017.07 -6032.38 A M3Q-15 -6540.42 -6557.33 A 3A-06 -6017.07 -6032.38 AC 3Q-15 -6540.42 -6557.33 A 3A-06 -6032.38 -6033.15 A 3Q-15 -6557.33 -6558.18 A 3A-06 -6032.38 -6033.15 AC as 3Q-15 -6557.33 -6558.18 A 3A-06 -6032.38 -6033.15 A 3Q-15 -6558.18 -6559.03 A 3A-06 -6040.81 -6077.64 A 3Q-15 -6558.18 -6559.03 A 3A-06 -6040.81 -6077.64 AC 3Q-15 -6559.03 -6559.87 A 3A-06 -6040.81 -6077.64 A 3Q-15 -6559.03 -6559.87 A 3A-06 -6096.11 -6100.73 AC 3Q-15 -E5-9.87 -6561.56 A 3A-06 -6096.11 -6100.73 A .......... 3Q-15 -6559.87 -6561.56 A 3A-06 -6096.11 -6100.73 A 3Q-15 -6561.56 -6562.41 A 3A-15 -6047.17 -6059.39 A III 3Q-15 -6561.56 -6562.41 A 3A-15 -6067.54 -6097.47 A <j 3Q-15 -6562.41 -6563.2611 3A-15 -6107.01 -6127.5 A 3Q-15 -6562.41 -6563.26 3A-17 -5512.16 -5930.18 AC M3Q-15 -6563.26 -6564.1 A 3A-17 -5938.01 -5945.84 AC ::>3Q-15 -6563.26 -6564.1 A 3A-17 -6011.53 -6034.95 AC 3Q-15 -6564.1 -6565.79 A 3B-01 -5932.63 -5999.94 c 3Q-15 -6564.1 -6565.79 A 3B-01 -6106.33 -6126.3 A 3Q-15 -6572.55 -6581 A 3B-01 -6142.61 -6170.88 A 3Q-15 -6572.55 -6581 A 3B-05 -5967.44 -5974.73 C << 3Q-15 -65811 -6581.85 A 3B-05 -6018.38 -6035.82 C 3Q-15 -6581 -6581.85 A 3B-05 -6165.02 -6194.03 A -15 -6581.85 -6582.69 A 3B-05 -6204.18 -6237.57 A-15 .......... .... ... -6581.85 -6582.69 A 3B-06 -5944.78 -5958.68 AC K. `x„:3Q-15 -6582.69 -6583.54 A 3B-06 -5964.24 -5985.13 AC 3Q-15 -6582.69 -6583.54 A 3B-06 -6000.48 -6007.47 AC 3Q-15 -6583.54 -6584.381 A Kuparuk Perf Intervals and Stratigraphic Zones WELL NAME PERF TOP SS PERF BTM SS ZONE WELL NAME PERF TOP SS PERF BTM SS ZONE 3B-06 -6053.75 -6088.98 AC M3Q-15 -6583.54 -6584.38 A 3B-06 -6102.42 -6130.8 AC M3Q-15 -6584.38 -6585.23 A 38-08 -5921.46 -5926.92 C3Q- 15 -6584.38 -6585.23 A 3B-08 -5949.32 -5960.11 c 3Q-15 -6585.23 -6586.07 A 3B-08 -5980.21 -5993.52 C 3Q-15 -6585.23 -6586.07 A 3B-08 -6105.85 -6138.92 A 3Q-15 1 -6586.07 -6586.921 A 3B-08 -6151.5 -6166.74 A 30-15 -6586.07 -6586.92 A 3B-08 -6171.39 -6175.37 A =s 3Q-15 -6586.92 -6587.76 A 3B-09 -5912.98 -5938.6 C 3Q-15 -6586.92 -6587.76 A 3B-09 -5979.59 -5989.94 C 3Q-15 -6587.76 -6588.61 A 3B-09 -6116.77 -6155.49 A 3Q-15 -6587.76 -6588.61 A 3B-09 -6171.58 -6184.75 A v 3Q-15 -6588.61 -6589.45 A 3B-10 -5907.94 -5945 AC MM3Q-15 -6588.611 -6589.45 A 3B-10 -5907.94 -5945 C 3Q-15 -6589.45 -6590.3 A 3B-10 -5964.78 -5973.02 c 3Q-15 -6589.45 - 6590.3 A 3B-10 -5964.78 -5973.0 -AC » 3Q-15 -6590.3 -6591.14 A 3B-10 -6002.75 -6008.54 AC 3Q-15 -6590.3 -6591.14 A 3B-10 -6096.43 -6131.3 AC 3Q-15 -6591.14 -6591.98 A B-10 -6136.28 -6152.89 AC 3Q-15 -6591.14 -6591.98 A 3B-10 -6167.83 -6171.98 AC z> 3Q-15 -6591.98 -6606.34 A 3B-11 -5828.95 -5858.90.1 I C R- -6591.981 -6606.34 A 3B-11 -5881.47 -5886.75 C M 3Q-16 -6426.29 -6433.39 A 3B-14 -5901.22 -5956.8 AC 3Q-16- -6433.39 -6435.17 A 3B-14 -5901.22 -5956.8 AC a 3Q-16 -6441.37 -6450.25 A 3B-14 -5980.63 -5986.59 -AC 3Q-16 -6450.25 -6454.68 A 3B-14 -5980.63 -5986.59 AC 3Q-16 -6464.44 -6482.17 A 3B-14 -6075.97 -6107.76 AC 3Q-16 -6482.17 -6485.72 A 3B-14 -6075.97 -6107.76 -AC 3Q-16 1 -6485.72 -6491,041 A 3B-14 -6119.68 -6135.581 AC ffiR... 3Q-21 -6407.83 -6417.271 A 3B-14 -6119.68 -6135.581 AC 3Q-21 -6422 -6437.73 A 3C-01 -6130.16 -6134.5 A 3Q-21 -6442.44 -6473.84 A 3C-01 -6137.39 -6164.82 A 3Q-22 -6125.21 -6135.73 AC 3C-01 -6182.13 -6196.55 A 3Q-22 -6149.25 -6160.51 AC 3C-02 -6095.32 -6106.22 C 3Q-22 -6165.76 -6178.51 AC 3C-02 -6095.32 -6106.22 C 3Q-22 -6189 -6211.44 AC 3C-02 -6232 -6235.06 A 3R -10A -6648.69 -6666.2 3C-02 -6232 -6235.06 A 3R-1 OA -6666.2 -6692.45 A 3C-02 -6238.11 -6265.54 A R -M 3R-15 -6586.84 -6615.491 A 3C-02 -6238.11 -6265.54 A 3R-17 -6615.05 -6667.67 A 3C-02 -6279.97 -6294.37 A 3R-18 -6544.31 -6557.49 A 3C-02 -6279.97 -6294.37 A 3R -18 -6557.49 -6590.86 A 3C-03 -6272.86 -6289.8 AG 13R-19 -6576.17 -6580.49 A 3C-03 -6434.72 -6437.68 AC 3R-19 -6586.25 -6598.36 A 3C-03 -6439.9 -6464.35 AC3R-19 -6598.99 -6596.71 A 3C-03 -6477.68 -6494.73 AC 3R-19 -6599.72 -6599.13 A 3C-03 -6496.95 -6507.32 -AC g,g 3R-19 -6600.13 -6599.761 A 3C-05 -6516.76 -6538.77 A 3 R - 1 9T-- -6600.74 -6600.18 A -6551.69 -6582.18 A 3R-19 -6601.18 -6600.79 A 3C_10 _6451.58 -6484.35 3R-19 -6601.26 -6601.33 A 13C-10 -6500.38 -6519.35 A 3R-19 -6602.07 -6601.23 A Kuparuk Perf Intervals and Stratigraphic Zones WELL NAME PERF TOP SS PERF BTM SS ZONE WELL NAME PERF TOP SS PERF BTM SS ZONE 3C-11 -6465.51 -6470.78 A ><>3R-19 -6603.67 -6608.56 A 3C-11 -6474.07 -6503.7 A €>`3R-19 -6605.94 -6602.36 A 3C-12 -6298.3 -6312.91 C <<' 3R-19 -6608.79 -6606.36 A 3C-12 -6423.56 -6460.11 A a^3R-20 -6633.44 -6697.99 A 3C-12 -6475.15 -6475.99 A 3R-21 -6565.62 -6581.71 A 3C-12 -6475.99 -6480.18 A 3R-21 -6581.71 -6605.78 A 3C-12 -6480.18 -6492.77 A a 3R-21 -6605.78 -6638.56 A 3C-12 6501.18 6518.06 A ><:3R-22 -6602.95 -6614.87 A 3C -14A -6184.24 -6196.26 C ` ; 3R-22 -6614.87 -6636.88 A 3C-15 -6237.98 -6250.25 C >3R-22 -6636.88 -6667.13 A 3C -15A -6282.81 -6300.52 A 3R-25 -6622.82 -6641.8 A 3C -15A -6301.32 -6317.43 A =_':3R-25 -6641.8 -6670.29 A 3C -15A -6318.24 -6320.66 A 3S -06A -5813.93 -5838.49 C 3C -15A -6333.59 -6363.72 A of 3S -08C -5788.27 -5788.15 C 3C-17 -6415.85 -6443.69 A -... -08C -5791.64 -5791.76 C 3C-17 -6444.59 -6462.63 A 3S -08C -5800.66 -5800.39 C 3C-17 -6471.67 -6517.09 A z13S-08C -5805.11 -5804.96 C 3F-01 -5694.14 -5800.34 C =<:13S -08C -5805.29 -5805.32 C 3F-01 -5936.84 -5940.97 A <3S -08C -5806.67 -5806.67 C 3F-01 -5944.4 -5971.87 A _<3S -08C -5807.44 -5807.38 C 3F-01 -5992.46 -6011.68 A<:> < 3S -08C -5807.91 -5808.14 C 3F-03 -5699.72 -5700.46 C 3S -08C -5809.35 -5809.15 C 3F-03 -5700.46 -5761.93 C `<<? 3S -08C -5813.29 -5813.29 C 3F-03 -5919.41 -5952.46 A < > 3S-OSC -5814.35 -5814.54 C 3F-03 -5969.35 -5986.24 A3S-15 -5839.87 -5854.65 C 3F-03 -5995.06 -6000.93 Aa 3S -17A -5819.25 -5834.71 C 3F-04 -5736.91 -5794.47 C �> 3S-18 -5806.54 -5842.2 C 3F-04 -5736.91 -5794.47 C _=3S-21 -5784.7 -5803.68 C 7-04 -5794.47 -5835.53 C " 3S -24A 1 -5840.54 -5856.62 C 3F-04 -5794.47 -5835.53 C »'-1C-27 -6286.67 -6349.04 C 3F-04 -5968.24 -6001.03 A 1C-27 -6337.74 -6316.38 C 3F-04 -5968.24 -6001.03 A 1F -18A -5988.08 -5981.79 C 3F-04 -6017.43 -6048.61 A 1F -18A -6011.64 -5990.72 C 3F-04 -6017.43 -6048.61 A _ 1 L-06 -5794.44 -5853.43 C 3F-09 -5717 -5790.35 C 9.11 L-06 -5858.14 -5869.53 B 3F-12 5654.86 5677.61 C =t 1 L-06 -5955.74 -5966.77 A 3F-12 -5753.48 -5779.28 A 1L-06 -5982.91 -5989.99 A 3F -13A -5780.98 -5787.34 AC >€' 1 L-06 -5998.34 -6001.54 A 3F -13A -5990.6 -6003.4 AC 1 L-06 -6017.52 -6020.08 A 3F-15 -5667.85 -5675 C 1Y -24A -6020.76 -6024.88 A 3F-15 -5767.38 -5776.67 A <<1Y -24A -6024.82 -6010.98 A 3F-15 -5776.67 -5778.1 A 1Y-31 -5946.08 -5992.27 C 3F-15 5778.1 5779.52 A = 1Y-31 -6026.7 -6050.81 C 3F-15 -5779.52 -5780.95 A %:'1Y-31 -6193.18 -6213.47 A 3F-15 5780.95 5786.66 A ..2D-06BL1 -5859.12 -5879.24 A 3F-15 5800.23 5843.77 A2D-06BL1 -5949.88 -5927.44 A 3F-15 -5870.91 -5875.91 A 2D-06BL1 -5989.25 -5991.76 A 3F-17 -5940.13 -5958.32 A 2D-06BL1 5990.07 -5955.39 A 3F-17 -5975.62 -5986.55 A 2F-20 -8979.06 -8999.05 A 3F-18 -5721.64 5728.04 AC >€2W-11 5769.01 -5847.62 C Kuparuk Perf Intervals and Stratigraphic Zones WELL NAME PERF TOP SS PERF BTM SS ZONE WELL NAME PERF TOP SS PERF BTM SS ZONE 3F-18 -5728.04 -5733.53 AC ':2W-11 -5855.37 -5858.67 B 3F-18 -5733.53 -5736.27 AC 2W-11 -5952.54 -5956.56 A 3F-18 -5783.81 -5792.94 AC -5959.58 -5984.71 A 3F-18 -5912.77 -5931.11 AC 2W-1 1 -5987.73 -5995.77 A 3F-20 -5993.7 -6014.0 -A 2W-11 -5997.78 -6000.8 A 3F-20 3F-21 -6028.51 -6034.14 -6053.11 -6038.62 A A M2W-11 2Z -01A -6006.331 -5922.1 -6009.85 -5939.51 A A 3F-21 -6038.62 -6049.74 A 3H -16A -5896.97 -5889.05 c 3F-21 -6061.9 -6087.08 A 30-02A -6512.43 -6532.71 A 3G-03 -5721.04 -5733.14 AC 30-02A -6516.06 -6487.45 A 3G-03 -5733.14 -5736.16 AC 30-02A -6532.92 -6515.79 A ConocoPhillips March 31. 2009 Mr. Dan Seamount, Commissioner Alaska Oil and Gas Conservation Commission 333 West 7th Ave. Suite #100 Anchorage, Alaska 99501-3539 James T. Rodgers Manager— GKA Light Oil Greater Kuparuk Area ConocoPhillips Alaska Inc. ATO -1220 PO Box 100360 Anchorage AK 99510-0360 Phone (907)263-4027 Fax: (907)265-6133 Re: Kuparuk River Oil Pool — Proposed Pressure Survey Plan for 2009 Dear Mr. Seamount, In compliance with Rule 8, Conservation Order No. 432, ConocoPhillips Alaska, Inc., operator of the Kuparuk River Oil Pool, is hereby submitting the proposed pressure survey plan for 2009. There were 344 pressure surveys reported for the Kuparuk River Oil Pool to the AOGCC in 2008. In 2009, we expect to conduct approximately 150 pressure surveys, including initial surveys for new wells prior to initial sustained production. If you have any questions concerning this data, please contact Mark Kovar at 265- 6097. Sincerely, James T. Rodgers Manager- GKA Light Oil Greater Kuparuk Area bcc: Central Files ATO -3 16 ATTACHMENT 5 1 of 5 KUPARUK RIVER UNIT KUPARUK RIVER OIL POOL CONSERVATION ORDER 1986 RULE 4 - INJECTMTY PROFILES 2008 ANNUAL SUBMITTAL WELL API DATE OF DATE OF DATA TYPE REASON FOR WELL ZONES INJECTION NUMBER NUMBER INITIAL PROFILE/ PROFILE/ PROFILE/ COMPLETION TAKING ENBD / 50- INJECTION SURVEY SURVEY SURVEY INJECTION MSCFD 1A-02 02920599-00 12/08/91 02/11/08 SPINNER A/C SPLITS Sel. Single AC 1750 A 975 1A-02 02920599.00 12/08/91 04/13/08 SPINNER A/C SPLITS Sel. Single AC 2940 A 0 1A-06 02920638-00 03/09/92 0621/08 SZT A/C SPLITS Sel. Single AC 2400 A 2304 1A-12 02920688-00 0127/83 07/07/08 SZT A/C SPLITS Sel. Single AC 0 A 2160 16-04 02920595-00 09/10/90 06/18/08 SPINNER A/C SPLITS Sel. Single AC 2212 A 0 1 B-04 02920595-00 09/10/90 0828/08 SPINNER A/C SPLITS Sel. Single AC 1600 A 680 18-05 02920237-00 1023/94 06/15/08 SPINNER A/C SPLITS Sel. Triple AC 6200 A 0 1 B-05 02920237-00 10/23/94 12/19/08 SPINNER A/C SPLITS Sel. Triple AC 3608 A 392 1 B-09 02920655-00 0626/82 0621/08 SPINNER A/C SPLITS Sel. Triple AC 6300 A 0 1E-08 02920496-00 08/17/90 03/12/08 SPINNER A/C SPLITS Sel. Single AC 1450 A 522 1E-21 02920892-00 05/02/83 1222/08 SPINNER A/C SPLITS Sel. Single AC 4700 A 0 1E-22 02920884-00 1129/98 1224/08 SPINNER A/C SPLITS Sel. Single AC 4200 A 0 IE -23 02920858-00 05/03/83 12/04/08 SPINNER A/C SPLITS Sel. Single AC 3760 A 183 1F-04 02920846-00 1028/85 0526/08 SPINNER A/C SPLITS Sel. Single AC 1500 A 432 ATTACIDOUT 5 KUPARUK RIVER UNIT KUPARUK RIVER OIL POOL CONSERVATION ORDER 1988 RULE 4 - INJECTMTY PROFILES 2008 ANNUAL SUBMITTAL 2 Of 5 WELL API DATE OF DATE OF DATA TYPE REASON FOR WELL ZONES INJECTION NUMBER NUMBER INITIAL PROFILE/ PROFILE/ PROFILE/ COMPLETION TAKING ENFD / 50- INJECTION SURVEY SURVEY SURVEY INJECTION MSCFD 1F-05 02920807-00 1028/85 04/25/08 SPINNER A/C SPLITS Sel. Single AC 2360 A 1691 1F-10 02920984-00 08/16/84 02/12/08 SPINNER A/C SPLITS Sel. Single AC 1870 A 1290 1F-10 02920984-00 08/16/84 10/27/08 SPINNER A/C SPLITS Sel. Single AC 2000 A 1679 1F-15 02921025-00 08/16/84 04/02/08 SPINNER A/C SPLITS Sel. Single AC 2200 A 594 1G-06 02920890-00 08/28/84 07/13/08 SPINNER A/C SPLITS Sel. Triple AC 3894 A 0 1G-06 02920890-00 08/28/84 12/04/08 SPINNER A/C SPLITS Sel. Triple AC 3600 A 0 1G-09 02921001-00 0826/84 0626/08 SZT A/C SPLITS Sel. Triple AC 340 A 340 1G-09 02921001-00 08/26/84 10/04/08 SPINNER A/C SPLITS Sel. Triple AC 6150 A 369 1 H-03 02920792-00 08/12/93 01/17/08 SZT A/C SPLITS Sel. Single AC 635 A 635 1 H-03 02920792-00 08/12/93 0724/08 SZT A/C SPLITS Sel. Single AC 1500 A 450 1H-07 02920755-00 08/12/93 01/01/08 SZT A/C SPLITS Sel. Triple AC 400 A 0 1H-07 02920755-00 08/12/93 01/01/08 SZT A/C SPLITS Sel. Triple AC 400 A 0 1H-08 02920763-00 06/13/93 10/30/08 SPINNER A/C SPLITS Sel. Triple AC 3800 A 0 1Y-03 02920943.00 1025/93 12/07/08 SPINNER FOLLOW-UP Sel. Single AC 550 ATTACHHF= 5 KUPARUK RIVER UNIT KUPARUK RIVER OIL POOL CONSERVATION ORDER 198B RULE 4 - INJECTIVITY PROFILES 2008 ANNUAL SUBMITTAL 3 of 5 WELL API DATE OF DATE OF DATA TYPE REASON FOR WELL ZONES INJECTION NUMBER NUMBER INITIAL PROFILE/ PROFILE/ PROFILE/ COMPLETION TAKING BWPD / 50- INJECTION SURVEY SURVEY SURVEY INJECTION MSCFD A 550 1Y-04 02920948-00 10/25/93 07/13/08 SPINNER A/C SPLITS Sel. Triple AC 3850 A 38 1Y-11 02920926-00 06/10/89 05/01/08 SPINNER A/C SPLITS Sel. Single AC 2120 A 2096 1Y-12 02920913-00 03/30/85 12/02/08 SPINNER A/C SPLITS Single AC 1828 A 420 2A-02 10320024-00 03/31/85 07/18/08 SPINNER A/C SPLITS Sel. Single AC 7000 A 1750 2A48 10320049-00 02/24/88 06/21/08 SPINNER A/C SPLITS Sel. Single AC 4000 A 520 2A-08 10320049-00 02/24/88 07/26/08 SPINNER A/C SPLITS Sel. Single AC 3110 A 778 2A-20 10320196-00 05/12/94 11/09/08 SPINNER A/C SPLITS Single AC 6100 A 597B 2C-02 02920972-00 11/09/85 12/24/08 SPINNER A/C SPLITS Sel. Single AC 2756 A 827 2C-04 02920973-00 11/09/85 09/14/08 SPINNER A/C SPLITS Sel. Single AC 6384 A 5132 2D-05 02921157-00 11/09/85 08/23/08 SPINNER A/C SPLITS Sel. Single AC 1420 A 57 213-07 02921169-00 1121/85 09/07/08 SPINNER A/C SPLITS Sel. Single AC 2800 A 2800 2M-06 10320176-00 05/08/93 08/02/08 SPINNER A/C SPLITS Single AC 956 A 0 2T-18 10320213-00 0826/95 12/17/08 SPINNER A/C SPLITS Single AC 1060 A 615 ATTACM4ENT 5 KUPARUK RIVER UNIT KUPARUK RIVER OIL POOL CONSERVATION ORDER 1988 RULE 4 - INJECTNITY PROFILES 2008 ANNUAL SUBMITTAL 4 of 5 WELL API DATE OF DATE OF DATA TYPE REASON FOR WELL ZONES INJECTION NUMBER NUMBER INITIAL PROFILE/ PROFILE/ PROFILE/ COMPLETION TAKING HWPD / 50- INJECTION SURVEY SURVEY SURVEY INJECTION MSCFD 2U-03 02921269-00 11/20/85 11/17/08 SPINNER A/C SPLITS Sel. Single AC 5200 A 2600 2U-04 02921270-00 11/19/85 11/10/08 SPINNER A/C SPLITS Sel. Single AC 4200 A 0 2U-05 02921281-00 11/11/86 11/12/08 SPINNER A/C SPLITS Sel. Single AC 2500 A 2500 2U-14 02921262-00 01/14/86 12/02/08 SPINNER A/C SPLITS Sel. Single AC 5500 A 385 2V-01 0292103400 11/08/84 12/06/08 SPINNER A/C SPLITS Sel. Single AC 1800 A 0 2V-03 02921040-00 11/08/84 12/17/08 SPINNER A/C SPLITS Sel. Single AC 5440 A 859 2W-02 02921279-00 11/19/85 07/09/08 SPINNER A/C SPLITS Sel. Single AC 4883 A 3272 2W-04 02921275-00 11/23/85 0624/08 SPINNER A/C SPLITS Sel, Single AC 5300 A 2862 2W-05 02921208-00 1123/85 0725/08 SPINNER A/C SPLITS Sel. Single AC 8500 A 170 2W-10 02921239-00 11/19/85 07/08/08 SPINNER A/C SPLITS Sel. Single AC 5454 A 807 2W-14 02921253-00 11/19/85 12/11/08 SPINNER A/C SPLITS Sel. Single AC 4900 A 4900 2X-05 02920985-00 11/19/85 10/07/08 SPINNER A/C SPLITS Sel. Single AC 3100 A 598 2X-08 02920992-00 0224/86 02/14/08 SPINNER A/C SPLITS Sel. Single AC 5000 A 0 3A-04 02921433-00 0121/87 1127/08 SPINNER A/C SPLITS Sel. Single AC 1557 ATTACHMENT 5 KUPARUK RIVER UNIT KUPARUK RIVER OIL POOL CONSERVATION ORDER 1988 RULE 4 - INJECTIVITY PROFILES 2008 ANNUAL SUBMITTAL 5 of 5 WELL NUMBER API NUMBER 50- DATE OF INITIAL INJECTION DATE OF PROFILE/ SURVEY DATA TYPE PROFILE/ SURVEY REASON FOR PROFILE/ SURVEY WELL COMPLETION ZONES TAKING INJECTION INJECTION ENPD / MSCFD A 87 3A-07 02921444-00 01/09/91 11/07/08 SPINNER A/C SPLITS Sel. Single AC 1350 A 611 3A-11 02921458-00 0121/87 10/31/08 SPINNER A/C SPLITS Sel. Single AC 2626 A 571 36-10 02921368-00 12/30/85 0627/08 SPINNER A/C SPLITS Sel. Single AC 2200 A 1559 3C-02 02921414-00 01/26/86 12/13/08 SPINNER A/C SPLITS Sel. Single AC 2200 A 1976 317-12 02921483-00 07/05/86 1225/08 SPINNER A/C SPLITS Sel. Single AC 2250 A 35 31-1-02 10320083-00 05/28/91 10/24/08 SPINNER A/C SPLITS Single AC 5000 A 0 31-1-15 10320082-00 12/09/88 10/16/08 SPINNER A/C SPLITS Single AC 2131 A 168 3J-02 02921398-00 11/09/91 1229/08 SPINNER A/C SPLITS Sel. Single AC 1600 A 991 3J-12 02921469-00 10/14/87 01/01/08 SPINNER A/C SPLITS Sel. Single AC 1421 A 1293 3K-13 02921630-00 11/05/87 0526/08 SPINNER A/C SPLITS Sel. Single AC 616 A 363 3K-19 02923022-00 0725/01 05/27/08 SPINNER A/C SPLITS Monobore AC 1000 A 850 3N-11 02921580-00 10/29/87 02/16/08 SPINNER A/C SPLITS Single AC 2400 A 2112 67 >> Total IPROF Covert for 2008 ATTAMENT 6 KUPARUK RIVER UNIT KUPARUK RIVER OIL POOL CONSERVATION ORDER 432 RULE 9 - PRODUCTIVITY PROFILES ANNUAL 2008 SUBMITTAL 1 of 5 WELL API DATE OF DATE OF DATA TYPE REASON FOR WELL ZONES PRODUCTION NUMBER NUMBER INITIAL PROFILE/ PROFILE/ PROFILE/ COMPLETION PROD- OIL WATER GAS 50- PRODUCTION SURVEY SURVEY SURVEY TYPE UCING BOPD BWPD MSCFD 1A-01 02920590-00 12/93 02/06/08 SPINNER A/C SPLITS Sel. Triple ALL 284 2215 2653 A 0 0 0 1A-03 02920615-00 12/93 06/04/08 SPINNER A/C SPLITS Sel. Triple AC 385 1380 5890 A 0 0 0 1A-19 02922111-00 12/93 03/22/08 SPINNER A/C SPLITS Sel. Triple AC 365 5180 3111 A 0 0 0 1A-20 02922112-00 12/93 06/01/08 SPINNER A/C SPLITS Sel. Triple AC 303 725 1544 A 104 4 24 1A-22 02922127-00 12/93 07/23/08 SPINNER A/C SPLITS Sel. Triple AC 221 1286 759 A 27 197 87 1A-28 02922126-00 02/94 07/24/08 SPINNER A/C SPLITS Sel. Single AC 131 341 ill A 99 319 84 1B-06 02920603-00 12/93 11/13/08 SPINNER A/C SPLITS Sel. Single AC 297 1451 1360 A 15 73 68 1B-10 02920656-00 12/93 01/18/08 SPINNER FOLLOW-UP Multi Lateral ALL 317 7795 2291 A 0 0 0 1B-13 02922468-00 09/94 06/22/08 SPINNER A/C SPLITS Multi Lateral AC 250 556 411 A 13 28 21 1B-16 02922457-00 09/94 06/11/08 SPINNER PERF C SANDS Single AC 1352 2920 8105 A 28 60 165 1F-06 02920820-00 01/94 07/17/08 SPINNER A/C SPLITS Sel. Single AC 383 737 636 A 0 0 0 1F-09 02920983-00 12/93 05/30/08 SPINNER A/C SPLITS Sel. Single AC 346 556 460 A 249 326 230 1F-12 02921012-00 12/93 05/01/08 SPINNER A/C SPLITS Sal. Single AC 221 743 1533 A 184 623 1206 1F-17 02922657-00 06/96 07/29/08 SPINNER A/C SPLITS Single AC 173 693 223 ATTACHDIT 6 KUPARUK RIVER UNIT KUPARUK RIVER OIL POOL CONSERVATION ORDER 432 RULE 9 - PRODUCTIVITY PROFILES ANNUAL 2008 SUBMITTAL 2 Of 5 WELL API DATE OF DATE OF DATA TYPE REASON FOR WELL ZONES PRODUCTION NUMBER NUMBER INITIAL PROFILE/ PROFILE/ PROFILE/ COMPLETION PROD- OIL WATER GAS 50- PRODUCTION SURVEY SURVEY SURVEY TYPE UCING BOPD BWPD MSCFD A 111 693 146 1G-13 02921016-00 12/93 06/02/08 SPINNER A/C SPLITS Sel. Single AC 291 1810 735 A 60 8 19 1H-11 02922351-00 12/93 08/24/08 SPINNER A/C SPLITS Single ALL 227 1313 275 A 0 0 0 1L-09 02922025-00 02/94 05/14/08 SPINNER A/C SPLITS Sel. Single AC 322 343 262 A 191 59 61 1L-15 02921204-00 12/93 07/06/08 SPINNER A/C SPLITS Sel. Single AC 287 2197 914 A 0 0 0 1L -20A 02922027-01 04/00 08/27/08 SPINNER A/C SPLITS Single AC 317 660 250 A 27 0 10 1L-24 02922170-00 02/94 07/28/08 SPINNER A/C SPLITS Single AC 173 416 89 A 0 0 0 1R-02 02921405-00 02/94 04/08/08 SZT FOLLOW-UP Sel. Single A 250 1 247 A 250 1 247 1R-11 02921352-00 01/94 04/08/08 SZT FOLLOW-UP Sel. Single AC 465 831 5737 A 178 568 222 1R-11 02921352-00 01/94 08/15/08 SPINNER A/C SPLITS Sel. Single AC 0 0 0 A 270 550 420 1Y-21 02922387-00 01/94 07/11/08 SZT CLOSE C SANDS Sel. Single A 126 296 115 A 126 296 115 1Y-27 02922379-00 02/94 01/10/08 SZT CLOSE C SANDS Sel. Triple A 104 174 509 A 104 174 509 1Y-27 02922379-00 02/94 11/18/08 SZT CLOSE C SANDS Sel. Triple A 91 200 353 A 91 200 353 1Y-28 02922380-00 02/94 03/10/08 SPINNER A/C SPLITS Sel. Triple AC 182 4665 1716 A 116 245 1001 ATTAMOM 6 KUPARUK RIVER UNIT KUPARUK RIVER OIL POOL CONSERVATION ORDER 432 RULE 9 - PRODUCTIVITY PROFILES ANNUAL 2008 SUBMITTAL 3 of 5 WELL API DATE OF DATE OF DATA TYPE REASON FOR WELL ZONES PRODUCTION NUMBER NUMBER INITIAL PROFILE/ PROFILE/ PROFILE/ COMPLETION PROD- OIL WATER GAS 50- PRODUCTION SURVEY SURVEY SURVEY TYPE UCING BOPD BWPD MSCFD 1Y-31 02922381-00 01/94 04/14/08 SPINNER A/C SPLITS Sel. Triple ALL 186 4062 579 A 66 117 146 2A-13 10320039-00 02/94 10/02/06 SPINNER A/C SPLITS Sel. Single AC 230 4000 470 A 0 0 0 2A-17 10320193-00 04/94 09/10/08 SPINNER A/C SPLITS Single AC 158 2076 252 A 0 0 0 2A-24 10320195-00 04/94 08/15/08 SPINNER A/C SPLITS Single AC 269 1493 1708 A 161 896 1025 2B -03A 02921151-01 02/03 08/24/08 SPINNER A/C SPLITS Sol. Single AC 187 552 271 A 40 466 60 2B-13 02921138-00 01/94 01/10/08 SPINNER A/C SPLITS Sel. Single AC 309 830 190 A 188 428 58 2B-14 02921143-00 01/94 08/19/08 SPINNER A/C SPLITS Sel. Single AC 437 3588 2459 A 0 0 0 2C-14 02921226-00 02/94 11/04/08 SPINNER A/C SPLITS Sel. Single AC 151 361 163 A 125 300 135 2C-15 02921219-00 01/94 11/19/08 SPINNER A/C SPLITS Sel. Single AC 205 438 239 A 55 118 64 2H-09 10320050-00 02/94 09/05/08 SPINNER A/C SPLITS Sol. Single AC 304 574 463 A 188 356 287 2H-12 10320053-00 02/94 09/09/08 SPINNER A/C SPLITS Sel. Single AC 163 2256 451 A 36 16 93 2M-11 10320159-00 12/93 08/29/08 SPINNER A/C SPLITS Single AC 136 1375 433 A 40 413 133 2M-20 10320169-00 02/94 01/21/08 SPINNER A/C SPLITS Single AC 1006 2090 3133 A 0 0 0 2T-19 10320214-00 06/95 08/31/08 SPINNER A/C SPLITS Single AC 201 522 456 A 141 517 187 ATTAC14ENT 6 KUPARUK RIVER UNIT KUPARUK RIVER OIL POOL CONSERVATION ORDER 432 RULE 9 - PRODUCTIVITY PROFILES ANNUAL 2008 SUBMITTAL 4 of 5 WELL API DATE OF DATE OF DATA TYPE REASON FOR WELL ZONES PRODUCTION NUMBER NUMBER INITIAL PROFILE/ PROFILE/ PROFILE/ COMPLETION PROD- OIL WATER GAS 50- PRODUCTION SURVEY SURVEY SURVEY TYPE UCING BOPD BWPD MSCFD 2U-08 02921284-00 12/93 11/28/08 SPINNER A/C SPLITS Sel. Single AC 234 3997 2921 A 7 12 90 2U-10 02921302-00 12/93 11/16/08 SPINNER A/C SPLITS Sel. Single AC 190 2154 4035 A 11 129 242 2U-13 02921261-00 12/93 04/15/08 SPINNER A/C SPLITS Sel. Single AC 600 2800 3344 A 1 1 1 2V-09 02921300-00 12/93 11/16/08 SPINNER A/C SPLITS Sel. Single AC 470 3230 1366 A 38 258 109 2V-10 02921310-00 12/93 12/06/08 SPINNER A/C SPLITS Sel. Single AC 176 5000 876 A 23 750 114 2V-11 02921311-00 02/94 11/02/08 SPINNER A/C SPLITS Sel. Single AC 897 2351 690 A 153 400 117 2V-12 02921312-00 12/93 11/10/08 SPINNER A/C SPLITS Sel. Single AC 607 3604 1256 A 30 180 63 2V-15 02921295-00 01/94 08/30/08 SPINNER A/C SPLITS Sel. Single AC 170 3366 973 A 35 673 183 2W-01 02921273-00 12/93 07/16/08 SPINNER A/C SPLITS Sel. Single AC 440 3331 2462 A 136 483 957 2W-11 02921238-00 12/93 08/06/06 SPINNER A/C SPLITS Sel. Single AC 315 3453 10293 A 47 518 1544 2W-15 02921254-00 12/93 04/07/08 SPINNER A/C SPLITS Sel. Single AC 565 2034 4082 A 238 504 898 2W-17 02923370-00 12/07 06/05/08 SPINNER A sands Contr: Single A 124 828 304 A 124 828 304 2X-10 02921187-00 12/93 08/17/08 SPINNER A/C SPLITS Sel. Single AC 594 2331 2011 A 103 781 335 2X-12 02921189-00 12/93 11/22/06 SPINNER A/C SPLITS Single C 276 1837 185 WELL API NUMBER NUMBER .. ^.q 02921189-01 3A-09 02920699-00 3B-08 02921343-00 3B-09 02921367-00 3F-01 02921446-00 3F-05 02921460-00 3J-11 02921468-00 3J-17 02922700-00 3J-19 02922702-00 ATTACK6 KUPARUK RIVER UNIT KUPARUK RIVER OIL POOL CONSERVATION ORDER 432 RULE 9 - PRODUCTNITY PROFILES ANNUAL 2008 SUBMITTAL DATE OF DATE OF DATA TYPE INITIAL PROFILE/ PROFILE/ PRODUCTION SURVEY SURVEY 0 0 A 05/99 11/21/08 SPINNER. 02/94 03/22/08 SPINNER 02/94 09/11/08 SPINNER 12/93 09/12/08 SPINNER 12/93 12/07/08 SPINNER 12/93 12/20/08 SPINNER 02/94 05/02/08 SPINNER 12/96 05/28/08 SPINNER 12/96 02/17/08 SPINNER REASON FOR WELL ZONES PROFILE/ COMPLETION PROD. SURVEY TYPE UCING 0 0 A A/C SPLITS Single AC 233 467 A A/C SPLITS Sel. Single AC 133 295 A A/C SPLITS Sel. Single AC 144 110 A A/C SPLITS Sel. Single AC 18 178 A A/C SPLITS Set. Single AC 126 80 A A/C SPLITS Sel. Single AC 158 383 A A/C SPLITS Sel. Single AC 43 457 A A/C SPLITS Single AC 175 140 A PERF C SANDS Single AC A 5of5 OIL 3OPO WATER BWPD GAS MSCFD 0 0 0 311 1858 1159 0 0 0 233 518 99 233 467 99 177 393 147 133 295 110 300 230 934 144 110 448 710 2140 4107 18 178 91 1107 3154 3623 126 80 409 350 850 650 158 383 650 116 1236 137 43 457 51 250 200 1265 175 140 886 Attachment 7 Kuparuk River Oil Pool 2008 Annual Reservoir Surveillance Report Miscible Injectant Composition Miscible Injectant (MI) is manufactured at CPF-1 and CPF-2. The compositions of both the lean gas, enriching fluids (NGLs) and the resulting MI are measured periodically throughout the year to ensure that the MI meets the design Minimum Miscible Pressure (MMP). The detailed compositional analysis of the MI from each CPF is provided in tabular form on the following pages, together with the Minimum Miscible Pressures (MMP). The target MMP is 3300 psia. A lower MMP means higher NGL content in MI. KUPARUK RIVER UNIT MI COMPOSITION: CPF-1 Date Facility CO2 N2 C1 C2 C3 iC4 nC4 iC5 nC5 C6 C7 C8+ MMP (Calc), psia 12/29/2008 CPF-1 0.860 0.660 60.907 5.461 4.565 3.328 7.977 4.428 5.260 3.236 2.125 1.193 2464 12/18/2008 CPF-1 0.948 0.252 61.629 6.058 4.537 3.086 7.951 4.632 5.701 2.282 1.751 1.173 Not Available 11/4/2008 CPF-1 0.902 0.282 65.340 5.998 4.628 2.881 7.111 4.128 4.917 1.759 1.297 0.757 Not Available 10/24/2008 CPF-1 0.697 0.260 53.372 3.942 2.882 1.869 5.026 11.524 14.881 2.318 1.905 1.324 Not Available 8/12/2008 CPF-1 0.794 0.308 70.486 5.962 4.558 2.709 7.005 1.822 2.172 1.941 1.419 0.824 3281 3/28/2008 CPF-1 0.994 0.362 77.931 5.907 3.989 2.007 4.598 1.188 1.320 0.876 0.559 0.269 3535 3/7/2008 CPF-1 0.762 0.291 70.418 5.697 4.402 3.054 7.155 2.063 2.438 1.724 1.259 0.737 3726 2/2/2008 CPF-1 0.778 0.304 70.616 6.031 4.655 2.846 6.783 2.012 2.367 1.660 1.217 0.731 3616 1/14/2008 CPF-1 0.944 0.331 73.245 6.129 4.613 2.672 6.372 1.253 1.460 1.460 0.982 0.539 2966 AVG 3265 MMP Target 3300 KUPARUK RIVER UNIT MI COMPOSITION: CPF-2 Date Facility CO2 N2 C1 C2 C3 iC4 nC4 iC5 nC5 C6 C7 C8+ MMP (Calc), psia 12/18/2008 CPF-2 0.864 0.241 67.839 7.000 4.985 2.653 6.411 3.161 3.867 1.330 1.028 0.621 Not Available 11/4/2008 CPF-2 0.734 0.173 57.363 7.349 6.062 3.648 8.708 4.732 5.936 2.240 1.847 1.208 Not Available 10/24/2008 CPF-2 0.942 0.201 59.912 6.572 5.507 3.769 9.964 2.899 3.544 2.936 2.275 1.479 Not Available 8/12/2008 CPF-2 0.705 0.251 70.792 7.022 5.042 2.619 6.763 1.521 1.863 1.542 1.181 0.699 3573 7/11/2008 CPF-2 0.656 0.227 65.800 6.753 5.461 2.804 8.070 2.218 2.775 2.348 1.804 1.084 2665 6/6/2008 CPF-2 0.682 0.249 68.076 6.679 4.936 2.992 7.822 1.842 2.317 1.978 1.531 0.896 3490 3/28/2008 CPF-2 0.666 0.258 70.574 6.759 4.796 2.914 6.780 1.626 2.003 1.575 1.258 0.791 3911 3/7/2008 CPF-2 0.688 0.262 69.979 6.806 4.841 3.011 6.888 1.689 2.098 1.592 1.305 0.841 3284 2/25/2008 CPF-2 0.638 0.257 69.378 6.478 4.600 2.892 6.814 1.999 2.540 1.901 1.542 0.961 2719 2/2/2008 CPF-2 0.688 0.294 70.360 6.653 4.460 2.953 6.914 1.690 2.114 1.658 1.352 0.864 3358 1/14/2008 CPF-2 0.668 0.248 68.932 6.585 4.558 3.092 7.099 1.941 2.467 1.884 1.548 0.978 3007 AVG 3256 MMP Target 3300 Attachment 8 Kuparuk River Unit Kuparuk River Oil Pool 2008 Annual Reservoir Surveillance Report LSEOR Development Plan During 2008, the Greater Kuparuk Area (GKA) averaged 21,093 BPD of PBU NGL imports and 9,162 BPD of indigenous NGLs for an annual average of 220 MMSCFD of Miscible Injectant (MI) manufacture. Of the total MI production in 2008, 156 MMSCFD was injected into the Kuparuk Field. Within the main Kuparuk Field, the 156 MMSCFD was allocated as: 12 MMSCFD for the SSEOR and SSEORX drillsites, 67 MMSCFD to the LSEOR drillsites and 77 MMSCFD to the LSEOR expansion drillsites. LSEOR expansion drillsites include drillsites: 1 B, 1 C, 1 D, 1 E, 1 L, 313, 3G, 3H, 30, 3Q and 3S. Further drilling activity in the Kuparuk River Oil Pool potentially provides new opportunities to maximize field recovery while preventing physical waste. Drilling opportunities, along with their associated miscible gas EOR potential, are under constant evaluation as the field matures, geologic and reservoir performance information is assimilated and as technology improves. Although drillsite 1 D is the only recent drillsite- level expansion project being sanctioned, the Kuparuk EOR project may be expanded to include any new wells. MWAG expansion to drillsite 1D has completed during 2008. MI injection in the drillsite started during October of 2008. The MI injection rate reached 26.5 MMSCFPD in December. ConocoPhillips March 31, 2009 Mr. Dan Seamount, Commissioner Alaska Oil and Gas Conservation Commission 333 West 7th Ave. Suite #100 Anchorage, Alaska 99501-3539 Re: GKA 365 -Day Shut-in Well Report Dear Mr. Seamount, James T. Rodgers Manager — GKA Light Oil Greater Kuparuk Area ConocoPhillips Alaska Inc. ATO -1220 PO Box 100360 Anchorage AK 99510-0360 Phone (907)263-4027 Fax: (907)265-6133 In compliance with AOGCC Regulation 20 AAC 25.115(a), ConocoPhillips Alaska, Inc., as operator of the Kuparuk River Field, is hereby submitting our 365+ days Shut In Well Report. The attached document lists all wells in the Greater Kuparuk Area that have been shut in for more than 365 days. It also lists the reason the wells were shut in as well as the mechanical condition of the well and any future plans. These wells are different from the suspended wells, which have a separate report. If you have any questions concerning this data, please contact Mark Kovar at 265- 6097. Sincerely, ames T. Rodgers Manager— GKA Light Oil Greater Kuparuk Area bcc: Central Files ATO -3 32 ATTACHMENT Greater Kuparuk Area 365 -Day Shut -In Well Report 2008 Annual Submittal 1 of 7 GKA Shut -In Wells Reason Well Current Mechanical Condition a Future Utility Plans Well Name Date Shut -In Shut -In' of the We112 & Possibilities Comments No known problems; Passed MITIA 1A-13 Apr -07 E on 07/15/07 3 Reservoir Management Low BHP due to lack of water injection support; Passed MITIA on Reservoir Management; Produce for 30 days to 113-101 Apr -07 E 09/05/05 6 evaluate injection requirement. No known problems; Passed 1C-22 May -06 E MITIA/MITOA on 02/14/06 3 Reservoir Management No known problems; Tubing pulled 1C-170 Mar -07 E 11/05/07 2 Awaiting workover to install 2nd casing sting. 1 E-05 Dec -06 E No known problems 3 Reservoir Management No known problems; Passed MITIA 1 E-09 Feb -01 E 06/04/06 3 Well line corrosion; Well line removed Plug stuck in tbg; Well line corrosion; Well line 1E-10 Nov -93 D,E No known problems 3 removed No known problems; Passed MITIA 1E-11 May -07 E on 06/04/06 2 Well line corrosion; Repairs Scheduled for 1 Q1 0 No known problems; Passed MITIA 1E-13 Oct -01 E 06/04/06 3 Well line corrosion; Well line removed 1E-14 Oct -90 E No known problems 3 Unable to inject or flow; Well line removed MITOA failed 9/17/05; MITIA 1E-16 I Mar -00 E Passed 06/04/06 3 Well line corrosion; Well line removed No known problems; Passed MITIA 1E-17 Jul -97 E 06/04/06 3 Well line corrosion; Well line removed No known problems; Passed MITIA 1E-19 Feb -98 E 06/04/06 3 Well line corrosion, Well line removed No known problems; Passed MITIA 1E-25 Se 94 I C. E 06/04/06 3 Low Iniectivi ; Well line removed T x IA communication; Suspected 1 E-26 Mar -04 C, D, E Liner damage 3 Well line corrosion No known problems; Passed MITIA Low Injectivity; Fish in Tbg Tail; Well line 1E-30 Aug -96 D, E 06/04/06 3 removed No known problems; Passed MITIA 1E-35 Apr -07 E on 06/04/06 2 Well line corrosion; Repairs Scheduled for 1Q09 Tx_ IA communication; IA x OA 1 F-08 I Jun -04 D 1communication. 3 No immediate plans; Under evaluation for RWO OA x OOA Communication; Passed MITIA 06/05/04; Passed MITT Well line corrosion; Shallow casing leak; No 1F-11 May -01 I D, E 06/16/04; Secured with TTP 3 immediate plans ATTACHMENT 9 Greater Kuparuk Area 365 -Day Shut -In Well Report 2008 Annual Submittal 2of7 GKA Shut -In Wells Reason Well Current Mechanical Condition Future Utility3 Plans Well Name Date Shut -In Shut-Ini of the Wel12 & Possibilities Comments No known problems; Passed MITIA Well line repairs completed; Well retruned to 1F-13 May -07 E on 06/01/08 6 injection 01/26/09 T x IA communication; Passed 1F -16A Apr -07 D MITIA on 06/01/08 1 OA HPP Candidate; Sludge issues No known problems; Passed MITIA 1G-02 Jun -04 E 07/15/07 2 Well line corrosion; Repairs Scheduled for 4Q09 Well line removed; No identified immediate 1H-105 Dec -04 C No known problems 3 plans 11-1-12 Mar -07 E No known problems 3 Well line corrosion; not immediate plans 1H-UGNU-01 Aug -07 C No known problems 3 Well line disconnected Well line removed; No identified immediate 1J-14 Dec -04 C No known problems 3 plans No known problems; Well secured 1M-17 May -02 B w/TTP 8 BPV 3 No immediate plans No known problems; Passed MITIA 1Q-01 Dec -99 E 07/17/06 3 Reservior Management: WI Flow line corrosion No known problems; Passed MITIA 1Q -02B Mar -07 E on 11/10/06 3 WI Flow line corrosion No known problems; Passed MITIA 1Q -08A Mar -07 E on 07/17/06 3 WI Flow line corrosion No known problems; Passed MITIA 1Q-09 Jun -07 E on 07/28/06 3 WI Flow line corrosion No known problems; Passed MITIA 1Q-11 Mar -07 E on 07/17/06 3 WI Flow line corrosion No known problems; Passed MITIA 1Q-12 Mar -07 E on 07/17/06 3 WI Flow line corrosion IA x OA communication; Passed 1Q-13 Mar -07 E MITIA on 07/17/06 3 WI Flow line corrosion IA x OA communication; Secured wfrTP; Passed MITT 01/13/07; 1Q-15 Jul -05 C, D Passed MITIA 01/20/07 2 Sidetrack scheduled 3Q09 T x IA communication. Well secured 1Q-21 Oct -03 B, D, E w/TTP. 3 Well line corrosion; Sidetrack/RWO Candidate No known problems; Passed MITIA 1R-06 May -07 E on 05/09/07 3 Well line corrosion; Repairs In Progress 1R-20 Jan -07 I D IT x IA communication 1 Sidetrack/RWO Candidate; no immediate plans No known problems; Passed MITIA Awaiting piping modifications; Repairs 1 R-23 Nov -07 E on 05/09/07 2 scheduled for 2Q09 ATTACHMENT 9 Greater Kuparuk Area 365 -Day Shut -In Well Report 2008 Annual Submittal 3of7 GKA Shut -In Wells Reason Well Current Mechanical Condition Future Utility3 Plans Well Name Date Shut -In Shut -Ing of the Wellz & Possibilities Comments No known problems; Passed MITIA 1 R-33 Oct -07 E on 05/09/07 3 Well line corrosion; Repairs scheduled for 4Q09 Failed MITOA on 04/25/06; Passed 1Y-08 Apr -07 E MITIA on 07/17/06 1 Reservoir Management. No known problems; Passed MITIA Reservoir Management; Returned to Injection 1Y-09 Jun -07 E on 07/17/06 6 01/16/09 T x IA communication; Failed MITIA 1Y-14 Oct -05 D 10/02/05; Passed MITOA 12/10/05 3 No identified immediate plans T x IA communication; Failed MITIA 2A-06 Mar -07 D 03/06/07 2 RWO scheduled 1Q09 No known problems; Secured w/csg plug and KWF; Passed CMIT 2E-05 Apr -94 C, E 07/28/06 2 Well line corrosion, RWO scheduled 2Q09 2E-06 Apr -94 C No known problems 3 No identified immediate plans 2E-07 Oct -94 C No known problems 3 No identified immediate plans 2E-09 Nov -93 C No known problems 3 No identified immediate plans No known problems; Passed MITIA 2E-12 Jul -06 E on 06/20/04 2 WI Flow line corrosion; Repairs In Progress No known problems; Passed MITIA 2E-13 Jul -06 E on 06/20/04 2 WI Flow line corrosion; Repairs In Progress T x IA Communication; Passed 2E-14 Jul -06 E MITIA on 05/31/07 2 WI Flow line corrosion; Repairs In Progress 2E-17 Apr -94 C No known problems 3 No identified immediate plans T x IA Communication; Passed 2F-04 Mar -07 E MITIA on 07/05/08 3 Low In'ectivi ; No identified immediate plans 2F-19 Aug -07 C No known problems 3 No immediate plans 2F-20 Jun -98 B Liner collapsed 3 No immediate plans 2G-13 Oct -05 C Well has casing damage. 3 No immediate plans 2G-17 Mar -03 C No known problems 3 No identified immediate plans IA x OA Communication; Passed MITOA on 04/07/07; Tubing 2K-08 Apr -06 D obstructed 3 Sidetrack/RWO Candidate SC Leak; Failed MITOA on 09/29/07; T x IA Communication; 2K-19 Se 07 D Passed MITIA on 09/29/07 3 No immediate plans RW0 failed to set packer. Needs 2K-22 Jun -06 D rerework 2 RWO scheduled 1Q09 No known problems; Passed MITIA 2L-03 Apr -02 C on 03/24/02 1 3 No immediate plans ATTACHMENT Greater Kuparuk Area 365 -Day Shut -In Well Report 2008 Annual Submittal 4of7 GKA Shut -In Wells Reason Well Current Mechanical Condition Future Utility' Plans Well Name Date Shut -In Shut-Ini of the We,12 & Possibilities Comments No known problems; Passed MITIA 2L -329A Dec -06 E on 08/08/06 3 Reservoir Management IA x OA communication; Passed MITOA on 01/18/08; Hole In 7" 2M-18 Dec -99 D Casing at 7041' 3 No immediate plans No known problems; Passed MIT on 2M-23 Sep -97 E 08/14/08 3 Class II Disposal Well 2N-305 Apr -07 D T x IA x Form x OA Communication 2 Sidetrack In Progress IA x Formation leak @ 5180'; Failed 2N-318 Mar -06 D CMIT on 04/19/06 2 Sidetrack scheduled 1Q09 No known problems; Passed 2N332 Feb -06 C MITT/MITIA on 03/28/06 3 No immediate plans No known problems; Passed MITIA 2N-3379 Oct -07 B on 04/14/07 3 No immediate plans No known problems; Passed MITIA 2P-434 Aug -07 E on 08/18/06 3 Low Injectivity 2P -448A Mar -09 C No known problems 3 Reservoir Management T x IA communication; IA x Formation Communication; Failed 2T-21 Jun -03 D, E CMIT 03/07/05; Secured w/TTP. 3 Well line corrosion No known problems; Passed MITIA 2T-32 Dec -02 E 06/02/07 1 Low Injectivity 2T-37 Jul -07 B No known problems 3 No immediate plans Tubing/casing breach by CTU. 2T-210 Jun -06 D Passed MITIA on 06/02/07 3 No immediate plans. T x IA communication; Passed 2U -07A Sep -07 E MITIA on 08/18/06 2 Well line corrosion; Repairs Scheduled for 3Q09 2U-11 Jul -07 E SC leak; Passed MITIA on 12/22/08 2 Well line corrosion; Repairs Scheduled for 3Q09 Tubing removed; OA cement job completed; Passed MITPC on 2V -08A Apr -06 D, E 01/19/08 2 RWO scheduled 2Q09; Well line corrosion 2X-19 May -04 C No known problems 2 Sidetrack scheduled 2QO9 T x IA Communication; Failed MITIA 2Z-03 Apr -02 D, E on 08/13/07 2 WI Flow line corrosion No known problems; Passed MITIA 2Z-04 Jun -06 E Ion 08/13/07 2 WI Flow line corrosion IA x OA communication; Passed 2Z-05 May -07 D MITOA on 06/27/05 2 FPJP candidate ATTACHMENT 9 Greater Kuparuk Area 365 -Day Shut -In Well Report 2008 Annual Submittal 5of7 GKA Shut -In Wells Reason Well Current Mechanical Condition z Future Utility Plans Well Name Date Shut -In Shut -In' of the We112 & Possibilities Comments No known problems; Passed MITIA 2Z-06 Jun -07 E on 08/13/07 2 WI Flow line corrosion IA x OA communication; Passed 2Z-08 Jun -06 E MITIA on 08/13/07 2 WI Flow line corrosion No known problems; Passed MITIA 2Z-14 Aug -07 E on 08/13/07 2 WI Flow line corrosion T x IA communication; IA x OA communication; Passed MITIA on 2Z-16 Mar -06 D,E 09/25/07 3 WI Flow line corrosion IA x OA communication; Passed 2Z-19 Apr -07 B MITOA on 08/23/05 3 No immediate plans No known problems; Passed MITIA 2Z-22 Aug -06 E on 08/13/07 2 WI Flow line corrosion No known problems; Passed MITIA 2Z-23 Sep -06 E on 08/13/07 2 WI Flow line corrosion 2Z -WS -1 Oct -86 C No known problems 3 No immediate plans No known problems; Passed MITIA 3C-05 Dec -07 E on 08/30/05 2 Well line corrosion; Repairs Scheduled for 2010 T x OA communication; Passed MITOOA 12/01/05; Well secured 3F -13A Sep -05 D w/TTP 3 No immediate plans 3G -14A Oct -03 C, E No known roblems 3 Well line corrosion 3G -19A Jul -05 C, D Possible Collapsed Csg 3 No immediate plans No known problems; Passed MITIA 3G-23 Feb -03 E on 08/20/07 1 Reservoir Management No known problems; Passed MITIA WAG surface piping being replaced due to 31-1-07 Jul -07 E on 06/10/06 1 subsidence T x IA communication; Failed CMIT 31-1-32 Jul -07 D on 08/02/07 1 No immediate plans No known problems; Passed MITIA 31-09 Mar -07 E on 07/31/07 3 Reservoir Management; WI Flow line corrosion No known problems; Passed MITIA Well line corrosion; Well returned to injection on - 3K -05 May -07 E on 05/21/05 6 01/25/09 No known problems; Passed MITIA 3K-18 Nov -07 E on 05/21/05 2 Well line corrosion; Repairs Scheduled for 2010 No known problems; Passed MITIA 3K-25 Oct -07 E Ion 07/01/06; Failed MITOA 07/01/06;1 2 Well line corrosion; Repairs Scheduled for 2010 T x IA x OA communication; Casing Sidetrack complete; Returned to production on 3M-03 Nov -02 D Failure; Well secured w/TTP 6 02/13/09 ATTACHMENT Greater Kuparuk Area 365 -Day Shut -In Well Report 2008 Annual Submittal 6of7 GKA Shut -In Wells Reason Well Current Mechanical Condition a Future Utility Plans Well Name Date Shut -In Shut -In' of the We112 & Possibilities Comments IA x OA communication; Passed 3M-11 May -06 D MITOA on 02/27/06 3 No immediate plans No known problems; Passed MITOA 3M-14 Aug -06 C on 02/19/06 3 No immediateplans; Evaluating for sidetrack Tx IA x OA communication; Passed 3M-18 Nov -02 D MITIA 02/22/05 3 No immediate plans No known problems; Passed 3M -29A Oct -05 6 Passed CMIT x IA 04/15/05 3 No immediate plans Attempted brinker platelet repair on surface SC leak; IA x OA communication; casing 1/26/09, unsuccessful. No immediate 3N-06 I May -07 D Failed MITOA 05/05/07 3 plans T x IA communication; Secured 30-19 Jan -01 D w/TTP 3 No immediate plans IA x OA communication; Passed 3Q-06 Feb -06 D MITT on 11/19/05 3 No immediate lans; Evaluating for sidetrack No known problems; Passed MITIA 3R -10A Mar -07 E 09/25/08 2 Well line corrosion; Repairs In Progress No known problems; Passed MITIA 3R -11D Se 00 E 08/20/07 3 Class II Disposal No known problems; Passed MITIA 3R-15 Oct -07 E 09/25/08 2 Well line corrosion; Repairs Scheduled for 2010 No known problems; Passed MITIA CPF-1A Jun -05 E 05/13/05 3 No Future Plans; Will not be used for injection No known problems; MITIA CPF-2 Aug -89 E 01/22/04 3 No Future Plans; Will not be used for injection WSW -01 Apr -83 D Tbg x IA Communication 3 No Future Plans; Will not be used for injection No known problems; Passed MITIA WSW -02 Mar -94 E 10/05/97 3 No Future Plans; Will not be used for injection No known problems; Passed MITIA WSW -03 Jul -01 E 10/05/97 3 No Future Plans; Will not be used for injection WSW -04 Aug -96 D Failed MITIA 04/27/96 3 No Future Plans; Will not be used for injection No known problems; Passed MITIA No Future Plans; Ok for use with CPF1 WSW -05 Jul -01 E 10/30/06 3 Supervisor approval No known problems; Passed MITIA WSW -06 I Jul -94 E 10/05/97 3 No Future Plans; Will not be used for injection No known problems; Passed MITIA WSW -07 Jul -01 E 10/05/97 3 No Future Plans; Will not be used for injection ATTACHMENT Greater Kuparuk Area 365 -Day Shut -In Well Report 2008 Annual Submittal 7of7 Reasons for Well Shut -In A. High Gas Oil Ratio, curently uncompetitive to produce due to facility constraints, no known mechanical problems B. High Water Oil Ratio, currently uneconomic to produce, no known mechanical problems C. Low production rate, no known mechanical problems D. Mechanical Problem E. Other (Specify under comments) Current Mechanical Condition Briefly describe the current mechanical condition including the condition of installed tubing and casing strings. Future Utility 1. Evaluating remedial, sidetrack and/or redrill opportunities 2. Remedial well work planned 3. Long term Shut-in well/ No immediate plans 4. Suspended well 5. P&A planned 6. Other (Specify under comments) GKA Shut -In Wells Reason Well Current Mechanical Condition a Future Utility Plans Well Name Date Shut -In � Shut -In of the Well s & Possibilities Comments T x IA communication; Failed MITIA WSW -08 Oct -96 D 05/24/93 3 No Future Plans; Will not be used for injection No known problems; MITIA No Future Plans; Ok for use with CPF1 WSW -09 Oct -96 E 10/30/06 3 Supervisor aroval WSW -10 Apr -83 D T x IA communication; Failed MITIA 3 No Future Plans; Will not be used for injection Tbg x IA Communication; Passed WSW -11 Aug -92 E MITIA 10/05/97 3 No Future Plans; Will not be used for injection Reasons for Well Shut -In A. High Gas Oil Ratio, curently uncompetitive to produce due to facility constraints, no known mechanical problems B. High Water Oil Ratio, currently uneconomic to produce, no known mechanical problems C. Low production rate, no known mechanical problems D. Mechanical Problem E. Other (Specify under comments) Current Mechanical Condition Briefly describe the current mechanical condition including the condition of installed tubing and casing strings. Future Utility 1. Evaluating remedial, sidetrack and/or redrill opportunities 2. Remedial well work planned 3. Long term Shut-in well/ No immediate plans 4. Suspended well 5. P&A planned 6. Other (Specify under comments) ConocoPhillips March 31, 2009 Mr. Dan Seamount, Commissioner Alaska Oil and Gas Conservation Commission 333 West 7th Ave. Suite #100 Anchorage, Alaska 99501-3539 James T. Rodgers Manager - GKA Light Oil Greater Kuparuk Area ConocoPhillips Alaska Inc. ATO -1220 PO Box 100360 Anchorage AK 99510-0360 Phone (907)263-4027 Fax: (907)265-6133 Re: 2008 Meltwater Oil Pool Annual Reservoir Surveillance Report Dear Mr. Seamount, In compliance with Rule 10, Conservation Order No. 456, ConocoPhillips Alaska, Inc., operator of the Kuparuk River Field, is hereby submitting the annual surveillance report on the Meltwater Oil Pool. This report documents the required information pertinent to the field development and enhanced recovery operations from January through December, 2008. The following is an outline of the information provided: a. Progress of EOR project and reservoir management summary (Attachment 1). b. Voidage balance, by month, for produced and injected fluids (Attachments 20). c. Analysis of reservoir pressure surveys taken in 2008 (Attachment 4). d. Results of production surveys, and any special surveys, taken on the Meltwater Oil Pool in 2008 (Attachment 5). e. Results of well allocation and test evaluation for Rule 7, and any other special monitoring (Attachment 6). f. Development Plan and Operation Review (Attachment 7). If you have any questions concerning this data, please contact Mark Kovar at (907) 265-6097. Sincerely, Wes T. Rodgers O Manager - GKA Light Oil Greater Kuparuk Area bcc: Central Files ATO -3 42 Attachment 1 Kuparuk River Unit Meltwater Oil Pool 2008 Annual Reservoir Surveillance Report Summary of EOR Project and Reservoir Management Summary Background In 2001, CPAI received approvals for formation of the Meltwater Oil Pool in the Kuparuk River Unit, an Area Injection Order for Meltwater, expansion of the Kuparuk River Unit, and formation of the Meltwater Participating Area. The Meltwater Pool Rules and Area Injection Order were approved on August 1, 2001. The Unit Expansion and Participating area were approved effective June 1, 2001. Injection of miscible injectant (MI) began in January 2002 and the MWAG (miscible water alternating gas) process was implemented during May 2003. The Meltwater MWAG process uses Kuparuk spec MI which is injected above the minimum miscibility pressure. For compositional analysis of the Kuparuk spec MI, refer to the Kuparuk section of the annual surveillance report. The Meltwater field currently has 19 total wells (12 producers and 7 injectors). See attached map for well locations. Progress of EOR Project Development activities in 2008 followed the plans described in the Pool Rules, Area Injection Order, Unit Expansion, and Participating Area (PA) applications. Below is a listing of the key events related to the Meltwater Pool and PA in 2008: 1. In order to better determine communication between producers and injectors, an aggressive pressure survey program was undertaken with 25 surveys being conducted, (up from the 16 taken in 2007). 2. Due to the high pressures and lack of visible interactions with any offset producers, three water injectors (2P-419, 2P-432 and 2P-434) are currently shut-in. In order to facilitate pressure reduction so that ConocoPhillips can safely sidetrack these wells, it was decided to flowback these injectors through the surface header facilities of long term shut-in producers. 2P-432 began flowback in February 2009 and plant constraints will dictate when the other injectors will commence flowbacks. Shut-in bottomhole pressure for this well was >4000 psi as of January, 2009. The initial flowrate for 2P-432 was 3000 BWPD with very small amounts of oil and gas. 3. Five producers are currently shut-in. Four producers, 2P -422A, 2P-443, 2P -448A and 2P-451, are shut-in due to low pressure support. After a pressure rebuilding period, 2P - 422A and 2P -448A were both returned to service in Q1 2009. They had to be taken off- line again due to insufficient pressure support. The remaining shut-in producer, 2P-438, had to be shut-in due to its 100 percent watercut. 4. While most producer/injector patterns see fairly limited communication, producer 2P - 424A saw a relatively strong increase of oil production in December. This production response is suspected to be a result of the offset gas injection into 2P-427 which commenced in June. This supports the findings of similar positive support seen between the pair in 2007 when perforations were added to 2P-427. The four Meltwater wells on jet pump as a means of artificial lift had their pumps pulled and replaced in 2007. 2P -406's pump failed in 2008 and was replaced again in July. Below is a listing of the most important new findings derived from the 2008 Meltwater development efforts: Work is ongoing to rebuild the Meltwater subsurface model. Much of the work involves analyzing the new seismic data obtained during winter 2007-2008. The analysis of this 4D seismic data should provide a better interpretation of the reservoir architecture and communication between producers and injectors. Outer annuli pressures in 2P-406, 2P-431, 2P-432, 213-434, 213-438, 2P-447, 2P -448A, and 2P-451 remained at elevated levels in 2008. In August, the outer annuli pressures were bled off and all build-ups increased at a rate less than or equal to that in past years. Fluid levels continue to be shot monthly for all problem wells and the calculated pressures at the C-80 interval are still below the measured/calculated leak off (refer to table of elevated OA pressures in Meltwater -Attachment 6). 3. When phase II injection wells were drilled in 2004, cumulative injection/withdrawal (INV) for the field was approximately 0.75. I/W rates for subsequent years were approximately 1.5 to maintain voidage replacement. In late 2004, cumulative INV reached 1.0 and has been steadily climbing since. Despite three injectors being taken off-line in 2008, instantaneous INV has remained above 2.0 for much of 2008. The cumulative year-end 2008 INV ratio, based on current FVFs, has now increased to 1.3. While it would be advantageous to decrease injection at this time, a minimum amount of both gas and water must be transported to Meltwater to maintain line velocity and minimize corrosion in the water line and freezing in the gas line. Reservoir Management Summary Meltwater came on-line in November of 2001 and has cumulatively produced 13.1 MMBO, 1.04 MMBW, and 30.7 BCF of gas by year-end 2008. Miscible gas injection began in 2002 with water injection beginning in 2003 (MWAG cycles). Cumulative injection through year-end 2008 at Meltwater has been 23.3 MMBW and 39.4 BCF of gas (of that 35.9 BCF of MI gas and 3.5 BCF of lean gas). Performance and surveillance data from the Meltwater producers indicates that they are receiving partial to limited support from offset injection wells. Further work will be done in 2009 to assess voidage replacement (on a pattern level, not fieldwide) and support issues in the field. The on-going interpretation of the new seismic data should prove invaluable for imaging higher - pressured injection and lower -pressured production compartments. This work, in conjunction with the pressure surveys, will assist in development of the geological and reservoir models being planned for the 2009-2010 time frame. These work products will be utilized in preparation of a Meltwater redevelopment plan. Meltwater Field — Net Pay Map O 5 eu2P P 2P 7� • P 2 u a • O 2P 2P• • 2 415 2P- Q 2 m # Net Pay (ft.) O 422A 0 5863011 —� 10 2P 2 20 30 40 so E13.-,ATEA-ty \��� k.. ) P.- 24 60 70 80 424A 90 0 —_ — _— • o� 100 5awcao MILES 110 0 10W 2000 30W 4000 SWO �Jry 120 130 PE ET 140 TRAIISVERSE I.ERCATOR PROJECW4 150 C.R.S.IWO SPHEROID CEIRRAL MMOIA1115000 caw 160 1.9psflceltlelem:'Untnaon' 170 5g 1380 W 0 15WINO 15£0000 1595N0 159]639232 Attachment 2 Meltwater Oil Pool 2008 Annual Reservoir Surveillance Report Produced Fluid Volumes Produced Fluid Volumes (Reservoir Units) OIL GAS WATER CUM OIL CUM GAS CUM WATER MO YR STB MSCF STB STB MSCF STB 1 2008 81441 104748 28748 12317777 29427718 954624 2 2008 74166 67825 6247 12391943 29495543 960871 3 2008 81834 74522 3487 12473777 29570065 964358 4 2008 77427 90599 3905 12551204 29660664 968263 5 2008 76113 124649 4531 12627317 29785313 972794 6 2008 61824 90210 3848 12689141 29875523 976642 7 2008 84374 162764 18929 12773515 30038287 995571 8 2008 76690 163906 9594 12850205 30202193 1005165 9 2008 65298 145811 16565 12915503 30348004 1021730 10 2008 61543 135050 9830 12977046 30483054 1031560 11 2008 60646 122385 6128 13037692 30605439 1037688 12 2008 55183 92563 4390 13092875 30698002 1042078 2008 TOTAL 856539 1375032 116202 Cumulatives at Dec 31, 2007 12236336 29322970 925876 Produced Fluid Volumes (Reservoir Units) OIL GAS WATER CUM OIL CUM GAS CUM WATER MO YR RVB RVB RVB RVB RVB RVB 1 2008 108724 43534 29150 16402919 20521294 962246 2 2008 99012 17592 6334 16501931 20538887 968580 3 2008 109248 19159 3536 16611179 20558046 972116 4 2008 103365 34199 3960 16714545 20592245 976076 5 2008 101611 62089 4594 16816155 20654334 980670 6 2008 82535 41602 3902 16898690 20695936 984572 7 2008 112639 88497 19194 17011330 20784433 1003766 8 2008 102381 93209 9728 17113711 20877642 1013494 9 2008 87173 84365 16797 17200884 20962007 1030291 10 2008 82160 77613 9968 17283044 21039621 1040259 11 2008 80962 67925 6214 17364006 21107545 1046473 12 2008 73669 46768 4451 17437675 21154313 1050924 2008 TOTAL 1143480 676553 117829 Cumulatives at Dec 31, 2007 16294196 20477760 933095 Attachment 3 Meltwater Oil Pool 2008 Annual Reservoir Surveillance Report Injected Fluid Volumes Injected Fluid Volumes (Reservoir Units) WATER GAS MI CUM WATER CUM GAS CUM MI MO YR STB MSCF MSCF STB MSCF MSCF 1 2008 213761 0 163944 21522256 3420088 33925628 2 2008 157222 0 181796 21679478 3420088 34107424 3 2008 176876 0 123436 21856354 3420088 34230860 4 2008 185024 0 124820 22041378 3420088 34355680 5 2008 159274 0 132480 22200652 3420088 34488160 6 2008 153545 0 116919 22354197 3420088 34605079 7 2008 128904 93838 44 22483101 3513926 34605123 8 2008 170411 17003 247225 22653512 3530929 34852348 9 2008 220803 0 291161 22874315 3530929 35143509 10 2008 196853 0 253278 23071168 3530929 35396787 11 2008 157112 0 201796 23228280 3530929 35598583 12 2008 63281 0 297261 23291561 3530929 35895844 2008 TOTAL 1983066 110841 2134160 Cumulatives at Dec 31, 2007 21308495 3420088 33761684 Injected Fluid Volumes (Reservoir Units) Cumulatives at Dec 31, 2007 21606814 4136865 29436855 WATER GAS MI CUM WATER CUM GAS CUM MI MO YR RVB RVB RVB RVB RVB RVB 1 2008 216754 0 131155 21823568 4136865 29568010 2 2008 159423 0 145437 21982991 4136865 29713447 3 2008 179352 0 98749 22162343 4136865 29812196 4 2008 187614 0 99856 22349957 4136865 29912052 5 2008 161504 0 105984 22511461 4136865 30018036 6 2008 155695 0 93535 22667156 4136865 30111571 7 2008 130709 104066 35 22797864 4240931 30111606 8 2008 172797 18856 197780 22970661 4259787 30309386 9 2008 223894 0 232929 23194555 4259787 30542315 10 2008 199609 0 202622 23394164 4259787 30744937 11 2008 159312 0 161437 23553476 4259787 30906374 12 2008 64167 0 237809 23617643 4259787 31144183 2008 TOTAL 2010829 122923 1707328 Cumulatives at Dec 31, 2007 21606814 4136865 29436855 Attachment 4 Meltwater Oil Pool 2008 Annual Reservoir Surveillance Report Reservoir Pressure Surveys & Stratigraphic codes for perf intervals STA JF AL,..,A ALASKA OIL AND GAS CONSERVATION COMMISSION RESERVOIR PRESSURE REPORT 1. operator. ConoccPhillips Alaska Inc. 2. Address: P. O. Box 100360, Anchorage, AK 99510-0360 3. Unit or Lease Name: Kupaluk River Unit 4. Field and Pool: Meltwater Oil Pool 5. Datum Reference: -5400'SS 6. Oil Gravity: 0.85(watef=1,0)0.74 7. Gas Gravity: S. Well Name and Number. 9. API Number 50xxxxxxxxxxxx NO DASHES 10. Type See Instructions 11. AOGCC Pool Code 12. Zone 13. Perforated Intervals Top -Bottom TVDSS 14. Final Test Date 15. Shut -In Time, Hours 16. Press. Surv. Type (see instructions for codes) 17. B.H. Temp. 18. Depth Tool TVDSS 19, Final Observed Pressure at Tool Depth 20. Datum TVDSS (input) 21. Pressure Gradient, psi/B. 22. Pressure at Datum (ca) 2P40S 103-20484-00 O 490140 A 7/512008 274 SBHP 138 5345.81 1199 5400 0.32 1216 2P415A 10340383-01 O 490140 A 121182008 552 SBHP 127 4953,97 914 5400 10.32 1057 2P419 103-20483-00 0 490140 A 7/6/2008 764 SBHP 125 5114.59 4090 5400 0.32 4181 2P419 103-20483-00 O 490140 A 9252008 2700 SBHP 125 5114.59 3997 5400 0.32 4088 2P419 103-20483-00 O 490140 A 11292008 4262 SBHP 127 5114.59 3955 5400 0.32 4046 2P -024A 103-20475-01 0 490140 A 12/182008 552 SBHP 139 5198.34 2044 5400 0.43 2131 2P429 103-20378-00 O 490140 A 12/7/2008 288 SBHP 126 5114.2 4156 5400 0.32 4247 2P432 103-20420-00 O 490140 A 61162008 280 SBHP 107 5247.5 4116 5400 0.32 4165 2P432 103-2042000 0 490140 A 9/12008 2112 SBHP 133 5247.5 4191 5400 0.32 4240 2P432 10320420-00 O 490140 A 11/172008 3900 SBHP 127 5247.5 4312 5400 0.32 4361 2P434 103-20467-00 0 490140 A 6152008 7128 SBHP 128 5081.34 4060 5400 0.32 4162 2P434 103-20467-00 O 490140 A 9/12008 9240 SBHP 135 5013.34 4100 5400 0.32 4224 2P434 10320467-00 O 490140 A 11/171200811000 SBHP 130 5024.97 4210 5400 0.32 4330 2P438 103-20376-00 0 490140 A 1/420082808 SBHP 130 5189.58 2900 5400 0.32 2967 2P438 103-20376-00 0 490140 A 212620081150 SBHP 124 4720.26 2640 5400 0.32 2858 2P438 10320376-00 O 490140 A 982008 5600 SBHP 128 5189.58 3241 5400 0.32 3308 2P443 10320487-00 0 490140 A 12/192008 7032 SBHP 122 4711.87 2695 5400 0.32 2915 2P447 10320468-00 O 490140 A 111302008144 SBHP 121 5114.96 4461 5400 0.32 4552 2P448 10320396-00 O 490140 A 2/282008 768 SBHP 134 4426.89 1169 5400 0.32 1480 2P448 10320396-00 0 490140 A 921200813248 SBHP 133 4426.89 1310 5400 0.32 1621 2P448A 10320396-01 O 490140 IA 1 2272008 8712 SBHP 133 5189.76 1170 5400 0.32 1237 2P448A 10320395-01 O 490140 A 11/30200815360 ISSHP 1133 5189.76 1405 5400 0.32 1472 2P451 10320402-00 0 490140 A 21=0081890 SBHP 130 5121.35 2351 5400 0.32 2440 2P451 103-20402-00 O 490140 A 7/52008 5106 SBHP 13D 4971.38 1268012817 2P451 103-20402-00 O 490140 A 11/172008 2490 SBHP 138 5106.35 2588 5400 0.32 2682 23. All tests reported herein were made in accordance with the applicable rules, regulations and instructions of the Alaska Oil and Gas Conservation Commission. I hereby certify Mat the foregoi�\8+' true and�coirfey��o.t�+�ep'p`st o6Amy knowledge. Signature Title �r5 DLL C-� y �E Printed Name J s ear Date / 11/0 9 ate Meltwater Perf Intervals and Stratigraphic Zones WELL NAME PERF TOP SS PERF BTM SS ZONE 2P-406 -5338.28 -5353.35 A 2P -415A -5430.93 -5440.06 A 2P-419 -5087.35 -5095.82 A 2P-419 -5101.78 -5118.88 A 2P-419 -5214.67 -5223.58 A 2P-419 -5223.58 -5241.51 A 2P-419 -5275.28 -5284.55 A 2P -424A -5388.12 -5392.18 A 2P-429 -5298.37 -5335.18 A 2P-429 -5369.70 -5384.07 A 2P-429 -5384.07 -5398.42 A 2P-429 -5419.07 -5433.39 A 2P-429 -5433.39 -5447.12 A 2P-429 -5481.36 -5487.05 A 2P-432 -5210.02 -5228.76 A 2P-432 -5236.25 -5254.99 A 2P-432 -5266.23 -5286.84 A 2P-434 -5044.65 -5098.35 A 2P-434 -5105.52 -5109.10 A 2P-434 -5114.47 -5118.05 A 2P-438 -5189.58 -5194.85 A 2P-443 -5195.40 -5213.20 A 2P-443 -5213.20 -5217.65 A 2P-443 -5217.65 -5226.57 A 2P-447 -5073.42 -5093.74 A 2P-447 -5124.22 -5166.97 A 2P-447 -5166.97 -5177.86 A 2PP 448A -5183.32 -5195.40 A 2P-451 -5113.35 -5129.35 A ConocoPhillips March 31, 2009 Mr. Dan Seamount, Commissioner Alaska Oil and Gas Conservation Commission 333 West 71h Ave. Suite #100 Anchorage, Alaska 99501-3539 James T. Rodgers Manager— GKA Light Oil Greater Kuparuk Area ConocoPhillips Alaska Inc. ATO -1220 PO Box 100360 Anchorage AK 99510-0360 Phone (907)263-4027 Fax: (907)265-6133 Re: Kuparuk River Unit, Meltwater Oil Pool — Proposed Pressure Survey Plan for 2009 Dear Mr. Seamount, In compliance with Rule 7, Conservation Order No. 456A, ConocoPhillips Alaska, Inc., operator of the Meltwater Oil Pool, is hereby submitting the proposed pressure survey plan for 2009. There were 25 pressure surveys reported for the Meltwater Oil Pool to the AOGCC in 2008. In 2009, we expect to conduct approximately 20 pressure surveys, including regularly scheduled surveys to assess the progress of injector flowbacks currently underway. If you have any questions concerning this data, please contact Mark Kovar at (907) 265-6097. Sincerely, James T. Rodgers Manager — GKA Light Oil Greater Kuparuk Area bcc: Central Files ATO -3 Attachment 5 Meltwater Oil Pool 2008 Annual Reservoir Surveillance Report Production/Special Surveys During 2008, no production/injection profile logs or special surveillance logs were run. No special surveillance logs are planned to be run in 2009. Attachment 6 Meltwater Oil Pool 2008 Annual Reservoir Surveillance Report Results of Well Allocation, Test Evaluation, and Special Monitoring Well Allocation Meltwater DS2P facilities were fabricated with a conventional test separator. A portable test separator system has been utilized at DS 2P to handle the solids production during initial flowback (<1 week) of the fracture stimulated producers. A minimum of two well tests per month were taken on production wells. Test separator backpressure corrections were applied to wells that experienced greater than 100 psi backpressure over header pressure. Correction to stock tank barrel conditions were made by applying Meltwater specific pressure corrections (derived from the PVT analysis of Meltwater North #1 crude oil samples) and API temperature corrections. Miscible gas is used for injection and gas lift at DS2P. For the wells that were on MI lift during a well test, the metered liquid rates were adjusted for NGLs associated with MI lift. A Peng- Robinson equation of state calculated the NGL recycle volume based on MI volume, separator temperature and pressure. Production volumes were tracked through Setcim production monitoring systems. The 2008 Meltwater allocation factors by month are listed below. Meltwater Oil Pool 2008 Production Allocation Factors Oil Gas Water Jan -08 0.9521 0.8807 1.0198 Feb -08 0.9426 0.9130 0.9902 Mar -08 0.9563 0.9284 1.0060 Apr -08 0.9816 0.8616 0.9972 May -08 0.9687 0.8616 1.0215 Jun -08 0.9746 0.8099 1.0270 Jul -08 0.9174 1.2329 1.0677 Aug -08 0.9428 0.8977 1.0168 Sep -08 0.9569 0.9541 1.0348 Oct -08 0.9741 0.9286 1.0511 Nov -08 0.9454 0.8729 1.0138 Dec -08 0.9882 0.9619 1.0661 Shallow Gas Soecial Monitorin 2P-406, 213-431, 2P-432, 2P-434, 2P-438, 2P-441, 2P-447, 2P -448A and 213-451 have elevated outer annuli (OA) pressures that rebuild pressure after bleeding. The surface pressures are monitored daily via Setcim (wells have pressure transducers that transmit the real-time OA pressures). The OA fluid levels are shot approximately once per month. Calculations are then made to determine the approximate pressures in the outer annuli at the C-80 interval in each of the wells that have elevated surface OA pressures. This data is then sent to the AOGCC on a quarterly basis. (See table on following page). Throughout 2008, most wells exhibited relatively stable OA pressures, with the exception of 2P- 432 and 2P-434, which experienced gradual decreasing OAP. While there appears to be a connection between the cessation of injection in these wells and declining OA pressures, OAP and injection rates do not match up in time. Therefore, there is inconclusive evidence to say there is a relationship between the two. In August of 2008, short term bleeds (1-2 hours) were conducted on the nine wells exhibiting elevated OA pressures. Their build-up rates were analyzed and compared with those of previous bleeds performed 2002 through 2005. Three of the wells (2P-431, 2P-438 and 2P- 451) had numerous bleeds performed in the past with much data to compare and analyze. Other wells only had one other bleed to compare with or none in the case of 2P-406, which only recently began experiencing elevated OA pressures. In general, the post bleed build-up rates seen in 2008 were slower than those seen after previous bleeds. A more thorough examination of the data will be submitted to the AOGCC in April 2009. I N -x110 2P-431 2P -148A 2P432 2P-451 V434 Date ME.- Press (psig) Date Surt. Press (psig) OA FL (tvdfrom Press,a; surf) C40 Top Equiv. Mud (ppg) Surt. Press (prig) QA FL (tvdfrom Press -;5? surf) C-80 Top MudWt (ppg) Surf.OAEquiv. Press (tvdftom PressMud (prig) surf) C-80 Top W[ (ppg) surf. Press (psig) (tvdfrom Presse sum C40 Top rv, qu Mud Wt (ppg) 22I2006 1050 1444 1316 10.34 1540 2427 1679 13281 1475 2405 1611 12.73 900 2019 1059 8.37 3W008 1060 1530 1309 1028 1550 2384 1697 1.3M 1520 2436 1656 13.09 800 1980 969 7.66 04040 1055 1551 1308 10.10 1545 2424 1685 IM 1500 2438 1634 12.91 655 19% 806 631 05010 1060 1567 1312 10.14 1545 2417 1685 13:33' 1520 2488 1656 13.09 590 1952 750 5.88 068XiN8 10601 1519 13211 10.20 1545 24171 1685 13.33 1500 2410 1637 12.94 515 1924 678 531 07XM 970 1577 1220 9421 1530 2466 1664 13.16 1510 2511 1646 13.01 5051 1902 672 526 08M 1040 1508 1302 10.06 1535 2442 1672 1323 1515 2505 1651 13.05 41 1 1851 658 5,15 08(291D8 535 1503 804 6.21 1530 2296 1687 1335 1330 1826 1540 12.17 460 1772 657 5.14 101D40 620 1265 938 7.25 1545 2387 1690 1337 1160 750 1546 1221 380 1755 581 111D41D8 635 1162 974 7.53 1544 2402 1686 1334 1016 1892 1193 9.43 347 1646 578 11Q9W8 12/18N8 402 646 1023 829 793 1058 6.13 8.11 1539 1537 2387 2420 1664 1677 1332 1327 911 796 1546 1926 1156 971 9.14 7.67 318 289 1565 1436 572 580 IAQ 2P 13s 2P-441 2P -148A 2P-451 Date ME.- Press (psig) u (tvdfrom Press,a- surf) C-80 Top qwv. fvfudYA (ppg) Surf. u Press (tv(Ifrom (psig) surf) Press@ C-80 Top Equiv.Surf. Mud Wt (ppg) Press (psig) (tvdfrom Press@ surf} C-80 Top qurv, Mud Wt (ppg) u Press (psig) u {tvdfrom surf) Press@ C-80 Top qwv. Mud Wt (ppg) 2/1/2008 1565 1369 18491 14.60 1140 1908 1325 10.41 1355 2382 1480 11.59 1040 2258 1148 9.11 31571008 1575 1416 1853 14.64 1150 1998 1321 1038 1350 2430 1467 11.60 1020 2303 1118 8.87 041048 1555 1411 1834 14.48 1180 1973 1356 10.67 1340 2430 1455 11.50 1050 2286 1155 9.17 05010 1540 1422 1817 1435 1170 2084 1327 10.45 1335 2427 1450 11.46 1060 2292 1164 924 06MO 15201 1411 1798 1420 1200 2152 1347 10.60 1335 2421 1451 11.47 1065 2298 1168 927 07NZD8 1505 1411 1782 14.08 1165 2205 1299 1023 1335 2434 1449 11.46 1055 2292 1159 920 O&M 1490 1416 1768 1396 1235 2163 1384 10.89 1335 2424 1451 11.47 1130 2229 1254 9.95 OBQ9D8 650 I 1518 899 7.10 7051 1913l 8701 6.851 12351 2440 1336 10.56 990 1 2315 1033 8.60 Attachment 7 Meltwater Oil Pool 2008 Annual Reservoir Surveillance Report Meltwater Development Plan and Operational Review Following are summaries of key activities that are planned for 2009 and subsequent years Development Drilling — One or two additional development well locations have been identified and tentative plans are to pursue drilling these well locations during 2010-2012 timeframe. In order to utilize existing infrastructure to its greatest benefit, it is planned to make use of the recently -built CTD rig and sidetrack wellbores not currently believed to be in communication with existing producers/injectors. The 2007-2008 winter acquisition of additional seismic data was completed for the Tarn / Meltwater area. This new seismic data is currently being processed and analyzed and will help to further evaluate the potential of the peripheral edges of the Meltwater pool, help to analyze producer -injector patterns, and identify infill potential. In preparation for the potential CTD sidetracks, three injectors (2P-419, 2P-432 and 2P-434) have been taken off-line and targeted for injection water flowback in order to decrease their elevated reservoir pressures in a more timely manner. This will allow CTD operations to operate safely. 2P-432 began flowback in February 2009. Further flowbacks will be started based on results from 2P-432 and operational constraints (plant impacts). Pipeline Operations — Due to low flow rates through the water injection line, there is recognition of increased risk for microbial -induced under -deposit corrosion and increased diagnostic work is being conducted. Approximately every six months, pigging of the production line is conducted to minimize effects of under -deposit corrosion. Exploration/Delineation — No further exploration work is currently planned for the Bermuda interval. However, the overlying Cairn sand, believed to be gas bearing, had been targeted for 2009 development in order to supply fuel gas to the Kuparuk facilities. Pre -drill engineering assessment yielded probable volume quantities accessible from the 2P pad to be insufficient for economic sanction at this time. ConocoPhillips March 31, 2009 Mr. Dan Seamount, Commissioner Alaska Oil and Gas Conservation Commission 333 West 70" Ave. Suite #100 Anchorage, Alaska 99501-3539 James T. Rodgers Manager— GKA Light Oil ConocoPhillips Alaska Inc. ATO -1220 PO Box 100360 Anchorage AK 99510-0360 Phone (907)263-4027 Fax: (907)265-6133 Re: 2008 Tabasco Oil Pool Annual Reservoir Surveillance Report Dear Mr. Seamount, In compliance with Rule 11, Conservation Order No. 435, ConocoPhillips Alaska, Inc., operator of the Kuparuk River Field, is hereby submitting the annual surveillance report on the Tabasco Oil Pool. This report documents the required information pertinent to the field development and enhanced recovery operations from January through December 2008. The following is an outline of the information provided: a. A summary of the enhanced recovery project (Attachment 1). b. Voidage balance, by month, for produced and injected fluids (Attachment 2&3). c. Analysis of reservoir pressure surveys taken in 2008 (Attachment 4). d. Results of production surveys, and any special surveys, taken on the Tabasco Oil Pool in 2008 (Attachment 5). e. Results of well allocation and test evaluation for Rule 7, and any other special monitoring (Attachment 6). f. Future development plans (Attachment 7). If you have any questions concerning this data, please contact Mark Kovar at (907) 265-6097. Sincerely, am�odgers Manager — GKA Light Oil Greater Kuparuk Area bcc: Central Files ATO -3 Attachment 1 Kuparuk River Unit Tabasco Oil Pool 2008 Annual Reservoir Surveillance Report Summary of the Enhanced Recovery Project Tabasco produced 1155 MBO of crude, 120 MMSCF of gas, and 7660 MBW during 2008. Water injection was 9375 MBW over the same period. Cumulative oil, gas, water production, and water injection through year end 2008 were 14.9 MMBO, 2.5 BCF, 54.6 MMBW, and 63 MMBWI, respectively. The cumulative year-end 2008 I/W ratio, based on current FVFs, is estimated at 0.88 for Tabasco. Injector 2T -217A began injecting water in February 2008. 2T -217A is the second injector at Tabasco. 2T-203 came online in January 2008 following installation of new ESP in December 2007. ESP failures occurred in wells 2T-220 and 2T-208 in September 2008 and December 2008, respectively. 2T-204 suffered ESP failure in November 2008. Year end 2008 Tabasco well count (all at Kuparuk River Unit Drill Site 2T) was: Producers: 10 completed 6 on line Injectors: 2 completed 2 on line The water oil ratio (WOR) was 7.1 at the end of 2008 compared to 6.2 at the end of 2007. Water breakthrough has occurred at all producers. Production and injection logs, coupled with the structural positions and water breakthrough histories of the producers, suggest that the water production mechanism is dominated by gravity - induced slumping. Rig workovers are scheduled for 2T-208 and 2T-220 in Q2 2009. 2T-204 is not currently scheduled for a workover due to challenging economics in the current price environment. A full field model for Tabasco was completed and updated through year end 2008. The model will be used in 2009 to optimize waterflood strategy and explore development options. Attachment 2 Tabasco Oil Pool 2008 Annual Reservoir Surveillance Report Produced Fluid Volumes Cumulatives at Dec 31, 2007 13743505 2377653 46897388 Produced Fluid Volumes (Reservoir Units) OIL GAS WATER CUM OIL CUM GAS CUM WATER MO YR STB MSCF STB STB MSCF STB 1 2008 111609 12138 681031 13855114 2389791 47578419 2 2008 108013 11458 670694 13963127 2401249 48249113 3 2008 111060 12400 714905 14074187 2413649 48964018 4 2008 113560 11449 690342 14187747 2425098 49654360 5 2008 109681 10805 714321 14297428 2435903 50368681 6 2008 84147 7589 562103 14381575 2443492 50930784 7 2008 75441 6157 556180 14457016 2449649 51486964 8 2008 90325 9761 628551 14547341 2459410 52115515 9 2008 68275 8754 601600 14615616 2468164 52717115 10 2008 99711 10279 622659 14715327 2478443 53339774 11 2008 97094 9773 599756 14812421 2488216 53939530 12 2008 86526 8607 618034 14898947 2496823 54557564 2008 TOTAL 1155442 119170 7660176 Cumulatives at Dec 31, 2007 13743505 2377653 46897388 Produced Fluid Volumes (Reservoir Units) Cumulatives at Dec 31, 2007 14560467 76165 46897388 OIL GAS WATER CUM OIL CUM GAS CUM WATER MO YR RVB RVB RVB RVB RVB RVB 1 2008 117189 0 681031 14677656 76165 47578419 2 2008 113414 0 670694 14791070 76165 48249113 3 2008 116613 0 714905 14907683 76165 48964018 4 2008 119238 0 690342 15026921 76165 49654360 5 2008 115165 0 714321 15142086 76165 50368681 6 2008 88354 0 562103 15230440 76165 50930784 7 2008 79213 0 556180 15309653 76165 51486964 8 2008 94841 0 628551 15404494 76165 52115515 9 2008 71689 0 601600 15476183 76165 52717115 10 2008 104697 0 622659 15580880 76165 53339774 11 2008 101949 0 599756 15682828 76165 53939530 12 2008 90852 0 618034 15773681 76165 54557564 2008 TOTAL 1213214 0 7660176 Cumulatives at Dec 31, 2007 14560467 76165 46897388 Attachment 3 Tabasco Oil Pool 2008 Annual Reservoir Surveillance Report Injected Fluid Volumes Cumulatives at Dec 31, 2007 53649253 Injected Fluid Volumes (Reservoir Units) WATER MO YR WATER GAS MI CUM WATER CUM GAS CUM MI MO YR STB MSCF MSCF STB MSCF MSCF 1 2008 861120 0 0 54510373 0 0 2 2008 786095 0 0 55296468 0 0 3 2008 903232 0 0 56199700 0 0 4 2008 840282 0 0 57039982 0 0 5 2008 777380 0 0 57817362 0 0 6 2008 686339 0 0 58503701 0 0 7 2008 833161 0 0 59336862 0 0 8 2008 810249 0 0 60147111 0 0 9 2008 687871 0 0 60834982 0 0 10 2008 728907 0 0 61563889 0 0 11 2008 738396 0 0 62302285 0 0 12 2008 722096 0 0 63024381 0 0 2008 TOTAL 9375128 0 0 Cumulatives at Dec 31, 2007 53649253 Injected Fluid Volumes (Reservoir Units) WATER MO YR RVB 1 2008 861120 2 2008 786095 3 2008 903232 4 2008 840282 5 2008 777380 6 2008 686339 7 2008 833161 8 2008 810249 9 2008 687871 10 2008 728907 11 2008 738396 12 2008 722096 2008 TOTAL 9375128 0 0 GAS MI CUM WATER CUM GAS CUM MI RVB RVB RVB RVB RVB 0 0 54510373 0 0 0 0 55296468 0 0 0 0 56199700 0 0 0 0 57039982 0 0 0 0 57817362 0 0 0 0 58503701 0 0 0 0 59336862 0 0 0 0 60147111 0 0 0 0 60834982 0 0 0 0 61563889 0 0 0 0 62302285 0 0 0 0 63024381 0 0 0 0 Cumulatives at Dec 31, 2007 53649253 0 0 Attachment 4 Tabasco Oil Pool 2008 Annual Reservoir Surveillance Report Reservoir Pressure Surveys & Stratigraphic codes for perf intervals STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION RESERVOIR PRESSURE REPORT 1. Operator. ConocoPhillips Alaska Inc. 2. Address: P. O. Box 100360, Anchorage, AK 99510-0360 3. Unit or Lease Name: Kupamk River Unit 4. Field and Pool: Tabasco Oil Pool 5. Datum Reference: -3000' SS 6. Oil Gravity: 0.96 (water= 1.0) 7. Gas Gravity: 0.572 8. Well Name and Number. 9. API Number 50� NO DASHES 10. Type See Instructions 11, AOGCC Pool Code 12. Zone 13. Perforated Intervals Top -Bottom TVDSS 14. Final Test Date 15. Shut-in Time, Hours 16. Press. Surv. Type (see instructions for codes) 17.8 ' H. Tem. 18. Depth Tool TVDSS 19. Final Observed Pressure at Tool Depth 20, Datum TVDSS (input) 21. Pressure Gradient, psittt. 22. Pressure at Datum (cal) 2T-204 103-20327-00 O 490160 A 9130/2008 762 SBHP 67 2803,93 977 3000 0.33 1042 23. All tests reported herein were made in accordance with the applicable rules, regulations and instructions of the Alaska Oil and Gas Conservation Commission. (hereby ceifymat Cher eg 9'�s�true antl correct a of my nowletlge. S Signature ,�.` t � 7ele 7 �} Printed Name amen vY Date Form 10-412 Rev. 12/2008 INSTRUCTIONS ON REVERSE SIDE Submit In Duplicate Tabasco Perf Intervals and Stratigraphic Zones WELL NAME PERF TOP SS I PERF BTM SS ZONE 2T-204 -2974.00 -3124.00 A ConocoPhillips March 31, 2009 Mr. Dan Seamount, Commissioner Alaska Oil and Gas Conservation Commission 333 West 7th Ave. Suite #100 Anchorage, Alaska 99501-3539 James T. Rodgers Manager— GKA Light Oil Greater Kuparuk Area ConocoPhillips Alaska Inc. ATO -1220 PO Box 100360 Anchorage AK 99510-0360 Phone (907)263-4027 Fax: (907)265-6133 Re: Tabasco Oil Pool — Proposed Pressure Survey Plan for 2009 Dear Mr. Seamount, In compliance with Rule 8, Conservation Order No. 435A, ConocoPhillips Alaska, Inc., operator of the Tabasco Oil Pool, is hereby submitting the proposed pressure survey plan for 2009. There was one pressure survey reported for the Tabasco Oil Pool to the AOGCC in 2008. No formal pressure surveys are scheduled for 2009, though surveys may be conducted using ESP pressure gauges should any well be shut in for an extended period. If you have any questions concerning this data, please contact Mark Kovar at (907) 265-6097. Sincerely, James T. Rodgers Manager- GKA Light Oil Greater Kuparuk Area bcc: Central Files ATO -3 Attachment 5 Kuparuk River Unit Tabasco Oil Pool 2008 Annual Reservoir Surveillance Report Production Logs and Special Surveys 2T -217A (Injector) had an Injection Profile Log run on April 24, 2008 that included Spinner/Gradin/Pressure/Temperature/GR/CCL tools. Minimal results were obtained due to insufficient depth being reached. Since production wells are completed with gravel pack screens and electrical submersible pumps, no production logs or special surveys are planned for 2009. Attachment 6 Kuparuk River Unit Tabasco Oil Pool 2008 Annual Reservoir Surveillance Report Well Allocation and Test Evaluation Summary A minimum of two well tests per month were conducted on production wells. Fluid samples were obtained on a regular basis, and water cut corrections were applied to well tests as required based on subsequent lab analysis. Generally, good agreement was observed for water cuts comparing phase dynamics and shakeout analysis. Production volumes were tracked through the Setcim production monitoring system. In 2002, Tabasco switched from an allocation factor of 1.0 to floating production allocation factors. Tabasco 2008 production allocation factors were as follows: Tabasco Oil Pool 2008 Production Allocation Factors M Oil Gas Water Jan -08 0.9479 0.8894 1.0090 Feb -08 0.9487 0.8902 1.0138 Mar -08 0.9551 0.9324 1.0108 Apr -08 0.9844 0.8859 1.0103 May -08 0.9695 0.8721 1.0125 Jun -08 0.8316 0.7001 0.8892 Jul -08 0.8878 0.9131 0.9359 Aug -08 0.9468 0.9475 ! 1.0123 Sep -08 0.9683 0.9373 1.0252 Oct -08 0.9562 0.9221 1.0177 Nov -08 0.9475 0.9026 1.0345 Dec -08 0.9442 0.8725 1.0356 M Attachment 7 Kuparuk River Unit Tabasco Oil Pool 2008 Annual Reservoir Surveillance Report Future Development Plans Two new rig workovers are scheduled for Q2 2009. 2T-208 and 2T-220 will both undergo rig workovers to replace failed ESP pumps. Tabasco injection withdrawal ratios (I/W ratio) will be monitored to maintain an instantaneous value of 1.0 or greater. Adjustments to injection and/or production rates will be made to maintain an instantaneous IM ratio of 1.0 or greater so that gas will remain in solution and pressure support maintained for the Tabasco reservoir. A Tabasco full field model was completed and updated through year end 2008. The model will be used to optimize waterflood strategy and explore future development opportunities. Screening evaluations indicate that Tabasco development beyond Drill Site 2T is most prospective at Kuparuk River Unit Drill Sites 3H and 3G. Tabasco geologic and engineering studies in 1999 identified Drill Site 3H appraisal well locations which may be drilled in the future. Tabasco development beyond Drill Site 2T continues to prove challenging due to smaller accumulations, lower quality reservoir, and higher viscosity oil. ConocoPhillips March 31. 2009 Mr. Dan Seamount, Commissioner Alaska Oil and Gas Conservation Commission 333 West 7th Ave. Suite #100 Anchorage, Alaska 99501-3539 James T. Rodgers Manager — GKA Light Oil ConocoPhillips Alaska Inc. ATO -1220 PO Box 100360 Anchorage AK 99510.0360 Phone (907)263-4027 Fax: (907)265-6133 Re: 2008 Tarn Oil Pool Annual Reservoir Surveillance Report Dear Mr. Seamount, In compliance with Rule 11, Conservation Order No. 430, ConocoPhillips Alaska, operator of the Kuparuk River Field, is hereby submitting the annual surveillance report on the Tarn Oil Pool. This report documents the required information pertinent to the field development and enhanced recovery operations from January through December 2008. The following is an outline of the information provided: a. A summary of the enhanced recovery project (Attachment 1). b. Voidage balance, by month, for produced and injected fluids (Attachment 20). c. Analysis of reservoir pressure surveys taken in 2007 (Attachment 4). d. Results of production surveys, and any special surveys, taken on the Tarn Oil Pool in 2008 (Attachment 5). e. Results of well allocation and test evaluation for Rule 7, and any other special monitoring (Attachment 6). f. Development Plan and Operation Review (Attachment 7). If you have any questions concerning this data, please contact Mark Kovar at (907) 265-6097. Sincerely, James T. Rodgers Manager — GKA Light Oil Greater Kuparuk Area bcc: Central Files ATO -3 Attachment 1 Kuparuk River Unit Tarn Oil Pool 2008 Annual Reservoir Surveillance Report Summary of EOR Project and Reservoir Management Summary Background In 1998 Arco Alaska, Inc. received approvals for formation of the Tarn Oil Pool in the Kuparuk River Unit, an Area Injection Order for Tarn, expansion of the Kuparuk River Unit, and formation of the Tarn Participating Area. The Tarn Pool Rules and Area Injection Order were approved on July 21st and July 20th, 1998 respectively. The Unit Expansion and Participating area were approved effective July 1, 1998. Construction of the Tarn road, pads, powerlines, and pipelines took place in the 1998/1999 winter construction season. Tarn development drilling commenced in April of 1998. Tarn production began on July 8, 1998. Injection of miscible injectant (MI) began in November 1998. Tarn switched to a miscible water alternating gas (MWAG) recovery process in July 2001. Progress of EOR Project The permanent 12" water injection line was completed and brought on-line in July 2001. This allowed Tarn to switch from strictly an MI flood to an MWAG recovery process which increases ultimate recovery from the Tarn reservoir. Water injection capacity has been good and injectivity has remained strong with no signs of formation damage. Tarn is operating at injection pressures above parting pressure which enables water injection to match offtake. The Tarn MWAG process uses Kuparuk spec MI which is injected above the minimum miscibility pressure. For compositional analysis of the Kuparuk spec MI, refer to the Kuparuk section of the annual surveillance report. Reservoir Management Summary In 2008, Tarn produced 5.55 MMBO, 8.28 MMBW, and 11.23 BSCF gas. The injection totals for 2008 were 1.03 BSCF Lean Gas, 15.24 BSCF of MI and 15.21 MMBW. The cumulative year-end 2008 INV ratio, based on current FVFs, is estimated at 1.02 for Drill Site 2N, and 1.23 for Drill Site 2L. Plans are to continue maintaining reservoir pressure by balancing monthly injection and production rates. Attachment 2 Tarn River Oil Pool 2008 Annual Reservoir Surveillance Report Produced Fluid Volumes Cumulatives at Dec 31, 2007 85962579 129011664 27362613 Produced Fluid Volumes (Reservoir Units) OIL GAS WATER CUM OIL CUM GAS CUM WATER MO YR STB MSCF STB STB MSCF STB 1 2008 483370 1040463 713205 86445949 130052127 28075818 2 2008 470785 986849 659783 86916734 131038976 28735601 3 2008 521639 1031059 697194 87438373 132070035 29432795 4 2008 518561 1047068 656306 87956934 133117103 30089101 5 2008 504598 1007155 612113 88461532 134124258 30701214 6 2008 435634 697533 540868 88897166 134821791 31242082 7 2008 507702 916994 678337 89404868 135738785 31920419 8 2008 470256 801881 707072 89875124 136540666 32627491 9 2008 402207 793609 728970 90277331 137334275 33356461 10 2008 402832 888214 726910 90680163 138222489 34083371 11 2008 406270 997859 683898 91086433 139220348 34767269 12 2008 428568 1025449 873683 91515001 140245797 35640952 2008 TOTAL 5552422 11234133 8278339 Cumulatives at Dec 31, 2007 85962579 129011664 27362613 Produced Fluid Volumes (Reservoir Units) Cumulatives at Dec 31, 2007 115270343 116078161 27745689 OIL GAS WATER CUM OIL CUM GAS CUM WATER MO YR RVB RVB RVB RVB RVB RVB 1 2008 650287 835762 723190 115920630 116913923 28468879 2 2008 633275 782758 669020 116553905 117696681 29137899 3 2008 701777 794811 706955 117255682 118491492 29844854 4 2008 697951 817449 665494 117953633 119308941 30510348 5 2008 680143 777380 620683 118633776 120086321 31131031 6 2008 586835 478496 548440 119220611 120564816 31679471 7 2008 684535 672034 687834 119905145 121236850 32367305 8 2008 633321 568877 716971 120538466 121805727 33084276 9 2008 542151 603962 739176 121080617 122409689 33823451 10 2008 543488 712494 737087 121624105 123122183 34560538 11 2008 547449 839009 693473 122171555 123961192 35254011 12 2008 577231 857978 885915 122748786 124819170 36139925 2008 TOTAL 7478443 8741009 8394236 Cumulatives at Dec 31, 2007 115270343 116078161 27745689 Attachment 3 Tarn River Oil Pool 2008 Annual Reservoir Surveillance Report Injected Fluid Volumes Cumulatives at Dec 31, 2007 107963539 10795387 140602161 Injected Fluid Volumes (Reservoir Units) WATER GAS MI CUM WATER CUM GAS CUM MI MO YR STB MSCF MSCF STB MSCF MSCF 1 2008 1289663 0 1867945 109253202 10795387 142470106 2 2008 1541788 0 1090247 110794990 10795387 143560353 3 2008 1591459 0 1353864 112386449 10795387 144914217 4 2008 1309628 0 1479455 113696077 10795387 146393672 5 2008 1290347 0 1516413 114986424 10795387 147910085 6 2008 1041448 0 1032672 116027872 10795387 148942757 7 2008 1275265 728823 120826 117303137 11524210 149063583 8 2008 1252052 298823 1144617 118555189 11823033 150208200 9 2008 1252732 0 1173246 119807921 11823033 151381446 10 2008 1215497 0 1239959 121023418 11823033 152621405 11 2008 990878 0 1636446 122014296 11823033 154257851 12 2008 1162462 0 1584862 123176758 11823033 155842713 2008 TOTAL 15213219 1027646 15240552 Cumulatives at Dec 31, 2007 107963539 10795387 140602161 Injected Fluid Volumes (Reservoir Units) Cumulatives at Dec 31, 2007 109475032 12234905 114889045 WATER GAS MI CUM WATER CUM GAS CUM MI MO YR RVB RVB RVB RVB RVB RVB 1 2008 1307718 0 1519184 110782751 12234905 116408229 2 2008 1563373 0 882679 112346124 12234905 117290908 3 2008 1613739 0 1095654 113959863 12234905 118386562 4 2008 1327963 0 1199155 115287826 12234905 119585718 5 2008 1308412 0 1235059 116596238 12234905 120820777 6 2008 1056028 0 834508 117652266 12234905 121655285 7 2008 1293119 817376 99516 118945385 13052281 121754801 8 2008 1269581 341526 932184 120214965 13393807 122686985 9 2008 1270270 0 965036 121485236 13393807 123652021 10 2008 1232514 0 1008354 122717750 13393807 124660375 11 2008 1004750 0 1338022 123722500 13393807 125998397 12 2008 1178736 0 1288742 124901236 13393807 127287139 2008 TOTAL 15426204 1158902 12398094 Cumulatives at Dec 31, 2007 109475032 12234905 114889045 Attachment 4 Tarn Oil Pool 2008 Annual Reservoir Surveillance Report Reservoir Pressure Surveys & Stratigraphic codes for perf intervals STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION RESERVOIR PRESSURE REPORT 1. Operator. 2. Address: ConocoPhillips Alaska Inc. P. O. Box 100360, Anchorage, AK 99510-0360 3. Unit or Lease Name: 4. Field and Pool: 5, Datum Reference: 6. Oil Gravity: 7. Gas Gravity: Kuparuk River Unit Tam Oil Pool 5200' SS 0.83 (water = 1.0 0.74 S. Well Name and 9. API Number 10. Type 11. AOGCC 12. Zone 13. Perforated 14. Final Test 15. Shut -In 16. Press. I 17. B.H. 18. Depth Tool 19. Final 20. Datum 21. Pressure 22. Pressure at Number: Soxxxxx%XXXXXX See Pool Code Intervals Date Time, Hours Surv. Type Temp. TVDSSObservetl NDSS (input) Gradient, P.M. Datum (cal) NO DASHES Instructions Top - Bottom (see Pressure at NDSS instructions for Tool Depth codes) 2L309 103-20521-00 0 490165 A 06/29/2006 84 SBHP 115 4053.69 931 5200 0.32 1298 2L-313 10320277-00 O 490165 A 03/05/2008180 SBHP 141 5090.06 1867 5200 0.32 1902 21--313 103-20277-00 O 490165 iA 1 10/14/2008 5472 SBHP 142 15391.29 3560 5200 0.44 3476 21-319 103-20552-00 O 490165 A 01/01/2008 99999 SBHP 141 5335.62 2371 5200 0.32 2328 2L319 103-20552-00 0 490165 A 06/25/2008 72 PBU 134 5031.18 1577 5200 0,32 1631 2L-325 103-20275-00 O 490165 A 08/19/2008 96 SBHP 136 5205.22 1295 5200 0.31 1293 2L-327 103-20542-00 0 490165 A 06/28/2008 69 SBHP 137 5165.28 1148 5200 0.32 1159 2L -329A 103-20272-01 O 490165 A 08/08/2008 14000 SBHP 126 5047.73 3182 5200 0.31 3229 2L -329A 103-20272-01 0 490165 A 09/07/2008 15200 SBHP 136 5047.73 3184 5200 0.35 3237 2L330 103-2055400 O 490165 ESKER 01/01/2008 99999 SBHP 149 5644.94 2506 5200 0.32 2366 2L-330 103-20554-00 O 490165 A 04/19/2008 99999 SBHP 142 5263.26 3432 5200 0.32 12 2N-302 103-20380-00 O 490165 A 03/25/2008 4200 SBHP 132 5238.74 3317 5200 0.32 05 214-302 103-20380-00 O 490165 A 09/17/2008 720 SBHP 132 5246.7 3923 5200 0.44 13671 02 2N-302 103-20380-00 0 490165 A 11/26/2008 2352 SBHP 132 5244.53 3646 5200 0.31 32 2N302 103-20380-00 WINJ 490165 A 12/30/2008 3168 SBHP 132 5230.06 3581 5200 0.34 2N303 103-20352-00 O 490165 A 1 06/29/2008 84 SBHP 142 4888.93 1338 5200 0.32 1438 2N-305 103-20349-00 O 490165 A 02/28/2008 7464 SBHP 138 5220 3077 5200 0.32 3071 214-305 103-20349-00 O 490165 1 A 08/16/2008 11544 SBHP 146 5220 3253 5200 0.424 3245 2N305 103-20349-00 0 490165 A 09/18/2008 85900 S8HP 146 5220 3278 5200 0.32 3272 2N305 103-20349-00 O 490165 A 11/23/200813896 SBHP 138 5220 3309 5200 0.32 3303 2N-310 103-20549-00 O 490165 A 03/15/2008 99999 SBHP 145 5435.1 3157 5200 0.32 3082 214314 103-20355-00 WINJ 490165 A 05/28/2008 84 SBHP 125 4958.63 3060 5200 0.32 3137 2N316 103-20342-00 10 490165 A 05/19/2000 84 SBHP 127 4589.54 1362 5200 0.44 1631 2N318 103-20343-00 0 490165 A 07/10/2008 13509 SBHP 131 4842.39 3107 5200 0.44 3264 2N318 103-20343-00 0 490165 A 11/24/2008 23424 SBHP 129 4577.02 3084 5200 0.32 3283 Foran 10-012 Rev. 12/2008 INSTRUCTIONS ON REVERSE SIDE Submit in Duplicate STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION RESERVOIR PRESSURE REPORT 1. Operator: 2. Address: ConocePllillips Alaska Inc. P. O. Box 100360, Anchorage, AK 99510-0360 3. Unit or Lease Name: 4. Field and Pool: S. Datum Reference: 6. Oil Gravity: 7. Gas Gravity: Kuparuk River Unit 8. Well Name and Number: 9. API Number SOXXX%XXX70IXXX NO DASHES 10. Type 11. AOGCC 12. Zone 13. Perforated See PoolCode Intervals Instructions Top - Bottom 14. Flnal Test Date Tam Oil Pool 15.Shut-In Txne, Hours 16, Press. Surv. Type (see 17. B.H. Temp. -5200' SS 18. Depth Tool 19. Final TVDSS Observed Pressure at 0.83 (water= 1.0 20. Datum TVDSS (input) 0.74 21. Pressure Gradient. psil t. 22. Pressure at Datum (cal) TVDSS instructions for Tool Depth modes) 214-319 103-20271-00 O 490165 A 07/05/2008 228 SSHP 139 5146.86 1259 5200 0.32 1276 2N320 103-20287-00 0 490165 A 07/01/2008132 SBHP 134 4964.43 1446 5200 0,32 1521 2N -321A 103-20267-01 0 490165 A 1 09/07/2008 72 SBHP 137 4972.41 3505 5200 0.456 3609 2N-323 103-20258-00 0 490165 A 1 06/282008 69 SBHP 125 4993.49 2121 5200 0.32 2187 2N-323 103-20258-00 O 490165 A 12/302008 760 SBHP 133 4990.1 2504 5200 0.32 2571 2N-327 103-20548-00 O 490165 A 06/14/2008 144 SBHP 152 5655.411468 5200 0.33 1338 214329 103-20257-00 O 490165 A 05/19/2008 74 SBHP 130 5009.28 1360 5200 0.32 1441 214332 103-20340-00 O 490165 A 12/31/2008 33800 SBHP 130 4859.56 3079 5200 0.32 3188 2N341 103-2026340 0 490165 A 06/302008106 ISBHP 133 4904.66 1880 5200 0.32 1974 2N342 103-20547-00 O 490165 A 03/042006 408 SBHP 145 5503.91 2512 5200 0.32 2415 2N-342 103-20547-00 O 490165 A 12/312008 620 SBHP 145 5503.91 2365 5200 0.32 2268 214-350 103-20389-00 O 490165 A1020/2008 1300 SBHP 89 3121.27 1825 5200 0.445 2750 2N-350 103-20389-00 10 490165 A 11/15/2008 1879 SBHP 127 4781.03 2646 5200 0.42 2822 23. All tests reported herein were made in accordance wit the applicable rules, regulations and instructions of the Alaska Oil and Gas Conservation Commission. 1 hereby certifythat the h o g is true and matt to Sig Signature Printed Name (` � 1 a best of y knowledge. T C SJ � Title naee � I I 0 -7 Form 10-412 Rev. 12/2008 INSTRUCTIONS ON REVERSE SIDE Submit in Duplicate Tarn Perf Intervals and Stratigraphic Zones WELL NAME PERF TOP SS PERF BTM SS ZONE 2L-309 -5371.76 -5388.62 A 2L-313 -5380.48 -5391.29 A 2L-313 -5391.29 -5402.07 A 2L-319 -5328.02 -5343.24 A 2L-325 -5194.11 -5216.26 A 2L-327 -5156.48 -5174.09 A 2L -329A -5041.35 -5065.96 A 2L-330 -5257.43 -5268.39 A 2L-330 -5636.71 -5653.20 A 2N-302 -5248.14 -5258.27 A 2N-302 -5258.27 -5272.73 A 2N-303 -5210.30 -5221.11 A 2N-305 -5217.46 -5222.54 A 2N-310 -5283.24 -5300.06 A 2N-310 -5357.61 -5425.09 A 2N-310 -5434.19 -5482.32 A 2N-310 -5506.71 -5516.11 A 2N-310 -5727.23 -5746.06 A 2N-314 -4865.87 -4866.61 A 2N-314 -4867.60 -4868.82 A 2N-314 -4876.11 -4877.05 A 2N-314 -4877.63 -4878.45 A 2N-314 -4892.12 -4890.83 A 2N-314 -4937.12 -4934.72 A 2N-314 -4958.63 -4960.70 A 2N-316 -4883.22 -4886.80 A 2N-318 -4933.73 -4938.58 A 2N-319 -5139.59 -5154.12 A 2N-320 -4956.11 -4961.65 A 2N-320 -4969.98 -4992.28 A 2N-323 -4932.27 -4945.91 A 2N-323 -4979.91 -5007.05 A 2N-327 -5356.40 -5376.18 A 2N-327 -5772.72 -5792.60 A 2N-329 -4997.94 -5012.11 A 2N-329 -5012.11 -5033.35 A 2N-332 -4855.95 -4871.51 A 2N-341 -4820.46 -4828.40 A 2N-341 -4899.92 -4909.76 A 2N-341 -4909.76 -4919.51 A 2N-342 -5424.01 -5447.19 A 2N-342 -5496.14 -5511.69 A 2N-350 1 -4779.77 -4782.29 A ConocoPhillips April 1, 2009 Mr. Dan Seamount, Commissioner Alaska Oil and Gas Conservation Commission 333 West 7th Ave. Suite #100 Anchorage, Alaska 99501-3539 James T. Rodgers Manager— GKA Light Oil ConocoPhillips Alaska Inc. ATO -1220 PO Box 100360 Anchorage AK 99510-0360 Phone (907)263-4027 Fax: (907)265-6133 Re: Tarn Oil Pool — Proposed Pressure Survey Plan for 2009 Dear Mr. Seamount, In compliance with Rule 8, Conservation Order No. 430A, ConocoPhillips Alaska, Inc., operator of the Tarn Oil Pool, is hereby submitting the proposed pressure survey plan for 2009. There were 38 pressure surveys reported for the Tarn Oil Pool to the AOGCC in 2008. In 2009, we expect to conduct approximately 24 pressure surveys, including initial surveys for new wells prior to initial sustained production or injection. If you have any questions concerning this data, please contact Mark Kovar at (907) 265-6097. Sincerely, CJ d�S James T. Rodgers Manager — GKA Light Oil Greater Kuparuk Area bcc: Central Files ATO -3 Attachment 5 Kuparuk River Unit Tarn Oil Pool 2008 Annual Reservoir Surveillance Report Production Logs and Special Surveys One injection profile surveys was conducted at drill site 2N. Results from this survey indicate there are no casing or tubing leaks and all injection is within the Bermuda interval. Tarn Injection Profile Data Well Date Fluid Rate bw d 2N-306 5/22/08 Water 4000 Two production profiles were conducted on 2N-327 at drill site 2N to determine production coming from deeper perforated interval (Albian). Tarn Production Profile Data Well Date Company Rate Well Date Fluid bbl/d 2N-327 3/8/08 74% Water 540 2N-327 6/17/08 51%Water 609 Special logs were run to identify leaks and casing corrosion. Special Leak Detection and Corrosion Logs Well Date Company Comments 2L-313 10/16/08 PDS Multi -Finger Caliper and 12 Arm Magnetic Thickness Tool (MTT) from 10,344 ft MD to surface. 2L-325 12/18/08 HES Leak Detection Tool from 8,360 ft MD to surface. 73 Attachment 6 Tarn Oil Pool 2008 Annual Reservoir Surveillance Report Production Allocation Factors Oil Gas Water Jan -08 0.9478 0.8894 1.0090 Feb -08 0.9486 0.8900 1.0137 Mar -08 0.9550 0.9323 1.0108 Apr -08 0.9844 0.8858 1.0103 May -08 0.9695 0.8722 1.0125 Jun -08 0.9584 0.8326 1.0301 Jul -08 0.9811 1.0108 1.0395 Aug -08 0.9468 0.9474 1.0123 Sep -08 0.9685 0.9386 1.0252 Oct -08 0.9562 0.9219 1.0177 Nov -08 0.9476 0.9030 1.0345 Dec -08 0.9442 0.8725 1.0356 Attachment 7 Kuparuk River Unit Tarn Oil Pool 2008 Annual Reservoir Surveillance Report Tarn Development Plan and Operational Review Development Drilling — 2L-301, planned as a pre -produced injector, was spud December 24. This grassroots well was part of a four well program for the Winter 2008/9. 2L-301 targeted turbidite deposits in the eastern fringe of the 2L accumulation to provide injection support to current (2L-309) and future producers in the surrounding outboard area. In 2007, three wells tested a deep newly recognized potential reservoir within the Tarn Pool, informally named the 'Esker' interval (2N-327, 2N-310, and 2L- 330). 2N-310 tested wet, 2L-330 tested dry and 2N-327 tested with an initial rate of 100 bopd and 80% water cut. The 'Esker' perforations on 2L-330 were temporarily abandoned under a sand plug. The same interval on 2N-310 has been temporarily abandoned under a sand plug with a cement plug above it. On 2N-327, the 'Esker' interval production was commingled with production from the Tarn/Bermuda Formation and two production profiles (PPROF) were run during 2008 for surveillance purposes. The 2N-342, drilled in 2007, targeted a promising seismic anomaly adjacent to the main Tarn Field with similar attributes named 'Tarn South'; initial flow testing was successful although production issues have resulted in this well currently being shut-in. In 2008 perforations were added and a second hydraulic frac job was pumped with the intent of obtaining additional rate and temperature characteristics to keep the well from freezing. Despite these efforts, the well had to be shut-in due to the same production issues. A temporary conversion to surface powered jet pump is being pursued for 2009 to allow for an extended and steady flow test. Opportunities to maximize Tarn Field recovery while preventing physical waste are under constant evaluation as the field matures, geologic and reservoir performance information is assimilated, and as technology improves. Plans for 2009 include pre -producing 2L-301 for 12 months and drilling the 2N - 305A and 2N -318A sidetracks. 2L-326, a new grassroots pre -produced injection well from Tarn drillsite 2L targeting the channel to amalgamated turbidite transition zone in the NW portion of the 2N accumulation, is currently being analyzed to be drilled in late 2009. 2N -305A will be an MWAG-supported, fracture -stimulated, gas -lifted producer, that will be drilled approximately 500' ENE from the original 2N-305 bottom -hole location in an attempt to capture more oil from un -swept regions of the reservoir and restore production from the failed 2N-305 wellbore. 2N-305 had to be shut in and secured in 2007 due to a casing leak caused by corrosion during surface -powered jet pump service. 2N -318A will also be an MWAG-supported, fracture -stimulated, gas -lifted producer. This sidetrack will be drilled approximately 600' south of the original 2N-318 bottom -hole location, towards a thicker reservoir section, with the intent of achieving higher production rates and optimizing areal sweep by moving away from the 2N-314 MWAG injection well. 2N-318 was shut in and secured in 2006 due to a casing leak caused by corrosion during surface -powered jet pump service. An update of the geologic and full -field reservoir model is in progress. Integration with the new 2008 3D seismic is being used for development planning and flood optimization. Producer to Injector Conversions — 2L-311 is currently being analyzed as a candidate for conversion to an injector during 2009. Artificial Lift — Tarn was originally designed to use miscible gas (MI) as a means of gas lifting the production wells. However, paraffin deposition in the tubing string section that runs across the permafrost occurs when the production fluid temperature falls below the cloud point of 92°F. This is the case of longer reach wells and lower liquid rate production wells. Excessive paraffin build-up and the high frequency of required paraffin scrapes in some wells led to a change in artificial lift methodology towards surface -powered downhole jet pumps. In 2001, after successful pilot tests in 1999 and 2000, 13 of the gas lifted wells were converted to jet pump using hot produced water as power fluid. This technique has proven to be very successful in mitigating paraffin deposits. Slickline scrapes and hot oil treatments have been virtually eliminated leading to production increases of about 10%. Unfortunately the untreated saline produced water injected down the inner annuli (power fluid) has accelerated tubing and casing corrosion. Three (3) well integrity failures occurred on jet -pumped wells due to both tubing and casing corrosion in 2006-2007: 2L-321, 2N-318 and 2N-305. These wells were shut-in and secured. 2N-305 and 2N-318 will be sidetracked in 2009. A workover to install an additional casing string was successfully completed for 2L-321 during 2008. Consequently, completion designs and alternatives to jet pumps are being considered for new and existing wells. Capillary chemical injection tubes have been installed in several new wells. This will enable lower productivity, lower temperature, gas -lifted wells to produce with reduced paraffin deposition problems when a chemical (paraffin inhibitor) is injected down the capillary tube to treat produced oil flowing up the tubing. Surface facility issues are being evaluated to consider implementing this program. After water breaks through in a producing well, the need for jet pumps and other means of paraffin inhibition or removal may not be necessary, because water has a higher heat capacity and the overall higher production rate yields higher flowing temperatures. Plans to convert wells after water break -through back to gas lift are under way. In 2007, 2L-307 was converted from jet pump back to gas lift. In 2008, two additional well were converted from jet pump back to gas lift: 2L-315 and 2L-325. ConocoPhillips March 31, 2009 Mr. Dan Seamount, Commissioner Alaska Oil and Gas Conservation Commission 333 West 71h Ave. Suite #100 Anchorage, Alaska 99501-3539 James T. Rodgers Manager — GKA Light Oil Greater Kuparuk Area ConocoPhillips Alaska Inc. ATO -1220 PO Box 100360 Anchorage AK 99510-0360 Phone (907)263-4027 Fax: (907)265-6133 Re: 2008 West Sak Oil Pool Annual Reservoir Surveillance Report Dear Mr. Seamount, In compliance with Rule 11, Conservation Order No. 406A, ConocoPhillips Alaska, Inc., operator of the Kuparuk River Unit, is hereby submitting the annual surveillance report on the West Sak Oil Pool. This report documents information pertinent to field development and enhanced recovery operations from January 2008 through December 2008. The following is an outline of the information provided: a. A summary of the current enhanced oil recovery in the West Sak Oil Pool (Attachment 1). b. Voidage balance, by month, for produced and injected fluid (Attachment 2 & 3). c. Analysis of reservoir pressure surveys taken in 2008 and pressure survey plans for 2009 (Attachment 4). d. Results of injection surveys, production surveys, and any special surveys, conducted in the West Sak Oil Pool in 2008 (Attachments 5-7). e. Results of pool production allocation factors (Attachment 8). f. Future development plans (Attachment 9). If you have any questions concerning this data, please contact Mark Kovar at (907) 265-6097. Sincerely, James T. Rodgers Manager- GKA Light Oil Greater Kuparuk Area Attachment 1 Kuparuk River Unit West Sak Oil Pool 2008 Annual Reservoir Surveillance Report Summary of the Enhanced Recovery Project At the end of 2008 there were fifty-five active water injectors and fifty-five active producers in the West Sak Oil Pool. Of those wells, fourteen injectors and seventeen producers were active at Drill Site 1J at the end of 2008. This represents an increase of five active producers and two active injectors in West Sak from January 2008 to December 2008. The following wells were completed and put on production in 2008 into the West Sak Oil Pool: Name Well Type Target Service 1C -172A Multi -Lateral ADB Producer 1D -141A Single Lateral D Producer 1J-174' Multi -Lateral DB Producer 1J-178' Multi -Lateral DB Producer 3K-102 Multi -Lateral DB Producer 1J-122' Multi -Lateral ADB Injector 1J-176* Multi -Lateral DB Injector indicates wells spud in 2007, but brought on-line in 2008. Waterflooding the reservoir with CPF-1 produced water for pressure maintenance and improved sweep continues to be the main enhanced oil recovery mechanism in the West Sak oil pool. Waterflood performance was good in the majority of the West Sak patterns. However the reservoir experienced two rapid water breakthrough events in 2008. These events created high conductive pathways between an injector and a producer, otherwise known as a matrix bypass event. A list of the matrix bypass events in 2008 is provided below: Injector Producer Event Date Breakthrough Zone 1J-102 1J-159 March 2008 B Sand 1J-170 1J-166 July 2008 B Sand Studies to understand the mechanism of these matrix bypass events continued in 2008; analysis and review of the studies and events is ongoing. Early recommendations to mitigate future matrix bypass events were implemented and the rate of new events has declined. In addition, initial remediation strategies were implemented for several affected wells in 2008, with some success. New remediation strategies are in development. During 2003, ConocoPhillips Alaska, Inc. received approval to commence a West Sak Small Scale EOR (SSEOR) Pilot Project using Kuparuk MI in a water - alternating gas (WAG) pilot. The SSEOR Pilot Project is completed. The feasibility of future gas injection into West Sak Drill sites 1 E & 1 J is under evaluation. Attachment 2 West Sak Oil Pool 2008 Annual Reservoir Surveillance Report Produced Fluid Volumes Cumulatives at Dec 31, 2007 32082056 16909321 7329995 Produced Fluid Volumes (Reservoir Units) OIL GAS WATER CUM OIL CUM GAS CUM WATER MO YR STB MSCF STB STB MSCF STB 1 2008 450851 191378 121426 32532907 17100699 7451421 2 2008 427141 197940 74428 32960048 17298639 7525849 3 2008 482600 194862 219946 33442648 17493501 7745795 4 2008 489684 209021 241486 33932332 17702522 7987281 5 2008 578164 223626 192817 34510496 17926148 8180098 6 2008 560663 210091 148994 35071159 18136239 8329092 7 2008 550015 245469 147484 35621174 18381708 8476576 8 2008 496790 221042 124939 36117964 18602750 8601515 9 2008 500095 247627 129523 36618059 18850377 8731038 10 2008 517082 198725 120030 37135141 19049102 8851068 11 2008 523887 175304 145160 37659028 19224406 8996228 12 2008 532788 195442 156963 38191816 19419848 9153191 2008 TOTAL 6109760 2510527 1823196 Cumulatives at Dec 31, 2007 32082056 16909321 7329995 Produced Fluid Volumes (Reservoir Units) Cumulatives at Dec 31, 2007 34301745 16598890 7329995 OIL GAS WATER CUM OIL CUM GAS CUM WATER MO YR RVB RVB RVB RVB RVB RVB 1 2008 481509 186338 121426 34783254 16785228 7451421 2 2008 456187 199211 74428 35239440 16984439 7525849 3 2008 515417 175832 219946 35754857 17160271 7745795 4 2008 522983 190780 241486 36277839 17351051 7987281 5 2008 617479 188669 192817 36895319 17539720 8180098 6 2008 598788 176354 148994 37494107 17716075 8329092 7 2008 587416 221622 147484 38081523 17937697 8476576 8 2008 530572 199075 124939 38612094 18136772 8601515 9 2008 534101 241487 129523 39146196 18378259 8731038 10 2008 552244 155925 120030 39698439 18534184 8851068 11 2008 559511 117002 145160 40257951 18651186 8996228 12 2008 569018 145415 156963 40826968 18796601 9153191 2008 TOTAL 6525224 2197710 1823196 Cumulatives at Dec 31, 2007 34301745 16598890 7329995 Attachment 3 West Sak Oil Pool 2008 Annual Reservoir Surveillance Report Injected Fluid Volumes Cumulatives at Dec 31, 2007 48997513 0 447212 Injected Fluid Volumes (Reservoir Units) WATER GAS MI CUM WATER CUM GAS CUM MI MO YR STB MSCF MSCF STB MSCF MSCF 1 2008 685804 0 0 49683317 0 447212 2 2008 706973 0 0 50390290 0 447212 3 2008 726214 0 0 51116504 0 447212 4 2008 796178 0 0 51912682 0 447212 5 2008 749759 0 0 52662441 0 447212 6 2008 626125 0 0 53288566 0 447212 7 2008 656415 0 0 53944981 0 447212 8 2008 752378 0 0 54697359 0 447212 9 2008 715702 0 0 55413061 0 447212 10 2008 734644 0 0 56147705 0 447212 11 2008 911915 0 0 57059620 0 447212 12 2008 878805 0 0 57938425 0 447212 2008 TOTAL 8940912 0 0 Cumulatives at Dec 31, 2007 48997513 0 447212 Injected Fluid Volumes (Reservoir Units) Cumulatives at Dec 31, 2007 48997513 0 334962 WATER GAS MI CUM WATER CUM GAS CUM MI MO YR RVB RVB RVB RVB RVB RVB 1 2008 685804 0 0 49683317 0 334962 2 2008 706973 0 0 50390290 0 334962 3 2008 726214 0 0 51116504 0 334962 4 2008 796178 0 0 51912682 0 334962 5 2008 749759 0 0 52662441 0 334962 6 2008 626125 0 0 53288566 0 334962 7 2008 656415 0 0 53944981 0 334962 8 2008 752378 0 0 54697359 0 334962 9 2008 715702 0 0 55413061 0 334962 10 2008 734644 0 0 56147705 0 334962 11 2008 911915 0 0 57059620 0 334962 12 2008 878805 0 0 57938425 0 334962 2008 TOTAL 8940912 0 0 Cumulatives at Dec 31, 2007 48997513 0 334962 Attachment 4 West Sak Oil Pool 2008 Annual Reservoir Surveillance Report Reservoir Pressure Surveys & Stratigraphic codes for perf intervals STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION RESERVOIR PRESSURE REPORT 1. Operator: ConocoPhillips Alaska Inc. 2. Address: P. O. Boz 100360, Anchorage, AK 99510-0360 3. Unit or Lease Name: Kuparuk River Unit 4. Field and Pool: West Bak Oil Pool 5. Datum Reference: -3500'SS 6. Oil Gravity: 0.94(water =1.0 7. Gas Gravity: 0.57 8. Well Name and Number. 9. API Number 50XXXXXXXXXXXX NO DASHES 10. Type See Instructions 11. AOGCC Pool Code 12. Zone 13. Perforated Intervals Top - Bottom TVDSS 14. Final Test Date 15. Shut -In Time, Hours 16. Press. Sum. Type (see instructions for codes) 17. B.H. Temp. 18. Depth Tool TVDSS 19. Final Observed Pressure at Tool Depth 20. Datum TVDSS (input) 21. Pressure Gradient, psim. 22. Pressure al Datum (cap 16117 029-23027-00 WI 490150 A 12/28/2008 960 SBHP 83 3748.31 2204 3500 0.43 2097 1C-135 029-23053-00 O 490150 D 07/14/2008 5800 SBHP 75 3648.66 1444 3500 0.38 1388 16172 029-23159-00 10 490150 A 1 03/02/2008 30000 ISBHP 53 12641.52 1291 3500 0.4 11634 1C-164 029-23155-00 0 490150 D 08/11/2008 50 SBHP 73 3582.42 1400 3500 0.392 1368 16190 029-23136-00 O 490150 D 11/12/2008 5400 SBHP 75 3689.18 1770 3500 0.43 1689 10-103 029-23086-00 WI 490150 ABO 09/03/2008 168 SBHP 71 3358.96 1473 3500 0,393 1528 1 D-113 029-22917-00 O 490150 ABD 03/28/2008 5000 SBHP 70 3305.23 1645 3500 0.36 1715 1D-121 029-22814-00 O 490150 ABD 09/24/2008 600 SBHP 71 3440.48 1612 3500 0.195 1624 10-122 029-22905-00 WI 490150 ABD 05/18/2008 1440 SBHP 85 13623.44 1747 13500 0.42 11695 1D-126 029-22889-00 O 490150 ABD 03/16/2008 4000 SBHP 70 3314.56 1712 3500 0.34 1775 1D-130 029-22815-00 WI 490150 ABD 05/29/2008 700 SBHP 93 3666.83 1819 3500 0.4 1752 16133 029-22827-00 O 490150 ABD 06/01/2008 2160 SBHP 73 3347.85 1601 3500 0,36 1656 1D-138 029-22957-00 WI 490150 ABD 12/29/2008 30 SBHP 70 3580.98 2615 3500 0.47 2577 ID -140 029-22974-00 O 490150 BD 09/22/2008 5040 SBHP 71 3358.6 11702 3500 0.39 1757 10-141A 029-22967-01 10 490150 D 1 07/241200819999 ISBHP 67 3289,51 1360 3500 0.393 1443 1J-101 029-23286-00 O 490150 ABD 09/04/200818 SBHP 69 2976.15 705 3500 0.393 911 1J-109 029-23307-00 O 490150 ABD 1 12/22/200819999 SBHP 73 3603.97 1545 3500 0.393 1504 All tests reported herein were made in accordance with the applicable rules, regulations and instructions of the Alaska Oil and Gas Conservation Commission. hereby certify that the f 'n is true an a be my knowledge. Signature Title Printed Name J ia^.'✓�'� S I �^-� `��,f^ S Date �/ Q Form 10.412 Rev.1212008 INSTRUCTIONS ON REVERSE SIDE Submit in Duplicate West Sak Perfs and Stratigraphic Zones WELL NAME PERF TOP SS PERF BTM SS ZONE .............. WELL NAME PERF TOP SS PERF BTM SS ZONE IC -117 -3738.5 -3758.13 A.,,.,.,_:.'1D-122 -3532.37 -3565.81 ABD 1C-117 -3773.86 -3789.61 A10.i�c 1D-122 -3576.96 -3595.55 ABD 1C-117 -3795.52 -3807.33 A1D-122 -3619.72 -3629.03 ABD 1C-117 -3807.33 -3825.06 A1D-122 -3638.33 -3664.39 ABD 1C-117 -3825.06 -3827.03 A1D-122 -3683.96 -3696.07 ABD 1C-117 -3834.91 -3846.73 A 1D-122 -3703.53 -3718.46 ABD 1C-117 -3846.73 -3866.44 AD -122 -3727.79 -3746.46 ABD 1C-135 -3674.76 -3662.56 D'1D-122 -3755.8 -3772.62 AB1C-184 -3751.95 -3731.38 D1D-126 -3395.5 -3423.77 ABD 1C-190 -3743.42 -3673.01 D1D-126 -3453.97 -3472.85 ABD 1D-103 1D-103 -3482.29 -3499.46 -3485.64 -3503.67 ABD: ABD 1D-126 1D-126 -3548.44 -3564.52 -3559.79 -3580.61 ABD ABD 1D-103 -3515.75 -3519.64 ABD 1D-126 -3610.9 -3639.32 ABD 1D-103 -3521.62 -3520.66 ABD _ 1D-130 -3521.38 -3523.38 ABD 1D-103 -3522.1 -3524.2 ABD __ 1D-130 -3533.33 -3549.27 ABD 1D-103 -3530.49 -3528.12 ABD .............. 1D-130 -3561.22 -3563.21 ABD 1D-103 -3532.23 -3536.11 ABD "' `; iD-130 -3576.16 -3579.15 ABD 1D-103 -3535.32 -3539.8 ABD _ -1 1D-130 -3579.15 -3581.14 ABD 1D-103 -3540.16 -3537.67 ABD _1D-130 -3581.14 -3610.03 ABD 1D-103 -3548.74 -3552.52 ABD == iD-130 3615.01 3617.01 ABD 1D-103 3549.84 3547.42 ABD 1D-130 -3620 -3624.98 ABD 1D-103 -3552.79 -3556.96 ABD_ 1 D-130 -3624.98 -3630.96 ABD 1D-103 -3558.91 -3556.92 ABD...-- a_ 1D-130 -3630.96 -3632.95 ABD 1D-103 -3559.48 -3559.17 ABD.-,.,-# 1D-130 -3632.95 -3644.91 ABD 1D-103 -3560.21 -3561.15 ABD€;`€;_' 1D-130 -3646.9 -3648.89 ABD 1D-103 -3564.01 -3567.17 ABD _....::iD-130 -3663.84 -3666.83 ABD 1D-103 -3565.54 -3563.3 ABD 1D-130 -3666.83 -3668.83 ABD 1D-103 -3569.58 -3573.98 ABD ;- 1D-130 -3668.83 -3669.82 ABD 1D-103 -3575.52 -3573.08 ABD -" ID -130 -3678.79 -3710.69 ABD 1D-103 -3584 -3581.77 ABD . 1D-130 -3722.65 -3724.64 ABD 1D-103 3587.82 3592.3 ABD 1D-130 -3733.61 -3738.6 ABD 1D-103 -3594.04 -3591.34 ABD = 1D-130 -3748.57 -3760.53 ABD 1D-103 -3599.39 -3604.02 ABD 1D-130 -3760.53 -3762.52 ABD 1D-103 3603.67 3606.1 ABD 1D-130 -3762.52 -3770.5 ABD 1D-103 -3604.92 -3602.32 ABD 1D-130 -3770.5 -3772.49 ABD 1D-103 -3610.13 -3609.95 ABD 1D-130 -3772.49 -3788.44 ABD 1D-103 -3617.92 -3621.95 ABD 1D-130 -3798.41 -3800.4 ABD 1D-103 -3635.4 -3639.1 ABD 1D-130 -3808.38 -3820.34 ABD 1D-103 -3652.4 -3657.03 ABD ': 1D-130 -3830.32 -3832.31 ABD 1D-113 3477.36 3504.41 ABD.......:... iD-130 3858.24 -3860.23 ABD 1D-113 -3542.31 -3560.36 ABD 1D-133 -3531.51 -3565.13 ABD 1 D-113 3590.16 3608.22 ABD 1D-133 -3595.02 -3628.66 ABD 1D-113 -3639.85 -3657.93 ABD '' 1D-133 -3679.12 -3718.38 ABD 1D-113 -3701.36 -3716.76 ABD,.-...-- 1D-133 -3753.92 -3806.32 ABD 1D-121 -3540.38 -3570.361 ABD >, 1D-138 -3572.57 -3602.55 BD 1D-121 -3600.33 -3630.31 ABD a: ID -138 -3629.93 -3666.8 BD 1D-121 -3692.26 -3722.24 ABD 1D-140 -3640.69 -3668.99 BD 1D-121 -3770.21 -3800.19 ABD 1 D -141A -3662.88 -3639.77 D 1D-122 -3474.83 -3502.66 ABD U-101 -3566.88 3575.79 ABD West Sak Perfs and Stratigraphic Zones WELL I AME PERSS OP I PERFss TM I ZONE I..........,I AME PERSFSOP I PERF BTM ZONE ConocoPhillips March 31, 2009 Mr. Dan Seamount, Commissioner Alaska Oil and Gas Conservation Commission 333 West 71h Ave. Suite #100 Anchorage, Alaska 99501-3539 James T. Rodgers Manager - GKA Light Oil Greater Kuparuk Area ConocoPhillips Alaska Inc. ATO -1220 PO Box 100360 Anchorage AK 99510-0360 Phone (907)263-4027 Fax: (907)265-6133 In compliance with Rule 8, Conservation Order No. 406A, ConocoPhillips Alaska, Inc., operator of the West Sak Oil Pool, is hereby submitting the proposed pressure survey plan for 2009. There were 17 pressure surveys reported for the West Sak Oil Pool to the AOGCC in 2008. In 2009, we expect to conduct approximately three pressure surveys, including initial surveys for new wells prior to initial sustained production or injection. If you have any questions concerning this data, please contact Mark Kovar at (907) 265-6097. Sincerely, YA (Ja�'t T. Rodgers Il Manager- GKA Light Oil Greater Kuparuk Area ATTACHMENT 5 KUPARUK RIVER UNIT WEST SAK OIL POOL CONSERVATION ORDER 406 RULE 11 - INJECTIVITY PROFILES 2008 ANNUAL SUBMITTAL PAGE 1 WELL API DATE OF DATE OF DATA TYPE REASON FOR WELL ZONES INJECTION NUMBER NUMBER INITIAL PROFILE/ PROFILE/ PROFILE/ COMPLETION TAKING BWPD / 50- INJECTION SURVEY SURVEY SURVEY INJECTION MSCFD 1C-111 02923029-00 12/08/01 0921/08 SPINNER A/C SPLITS Single A+B+D 890 B 0 A 0 1C-117 02923027-00 01/04/02 09/23/08 SPINNER A/C SPLITS Sel. Triple A+B+D 285 B 3 A 0 1C-119 02923034-00 12/08/01 10/17/08 SPINNER A/C SPLITS Single A+B+D 658 B 165 A 0 1C-121 02923015-00 08/02/01 10/18/08 SPINNER A/C SPLITS Single A+B+D 550 B 330 A 0 IC-125 0292304400 12/08/01 06/05/08 SPINNER A/C SPLITS Single A+B+D 113 6 0 A 113 1C-127 0292302400 01/04/02 06/03/08 SPINNER OPEN ASANDS Single A+D 297 A 217 1D-136 02922955.00 08/06/00 1228/08 SPINNER A/C SPLITS Single A+B+D 475 B 333 A 0 1E-112 02923211-00 12/16/04 01/11/08 SPINNER A/C SPLITS Multi Lateral A+B+D 700 B 595 A 0 1E-114 02923223-00 04/07/05 08/10/08 SPINNER A/C SPLITS Multi Lateral A+D 2588 A 1035 1J-105 02923346-00 06/15/07 08/19/08 SPINNER A/C SPLITS Multi Lateral A+B+D 875 B 875 A 0 1J-118 02923337-00 05/18/07 08/17/08 SPINNER A/C SPLITS Multi Lateral A+B+D 1100 B 671 A 0 ATTACHMENT KUPARUK RIVER UNIT WEST SAK OIL POOL CONSERVATION ORDER 406 RULE 11 - INJECTIVITY PROFILES 2008 ANNUAL SUBMITTAL PAGE 2 WELL NUMBER API NUMBER 50- DATE OF INITIAL INJECTION DATE OF PROFILE/ SURVEY DATATYPE PROFILE/ SURVEY REASON FOR PROFILE/ SURVEY WELL COMPLETION ZONES TAKING INJECTION INJECTION BWPD / MSCFD 1J-122 02923359-00 12112/07 08/18/08 SPINNER A/C SPLITS Mufti Lateral A+B+D 1087 B 707 A 0 1J-127 02923306-00 10/01/06 01/21/08 SPINNER A/C SPLITS Multi Lateral A+B+D 1184 8 710 A 118 1J-127 02923306-00 10/01/06 08/14/08 SPINNER A/C SPLITS Multi Lateral A+D 660 A 0 1J-136 02923331-00 04/01/07 02/02/08 SPINNER FOLLOW-UP Multi Lateral B+D 952 B 724 1J-156 02923311-00 10/01/06 08/21/08 SPINNER A/C SPLITS Multi Lateral A+B+D 1357 6 801 A 0 1J-160 0292334400 06/06/07 05/17/08 SPINNER A/C SPLITS Multi Lateral B+D 700 B 105 1J-164 02923278-00 03/02/06 01/04/08 SPINNER FOLLOW-UP Multi Lateral A+B+D 982 B 982 A 0 1J-164 02923278-00 03/02/06 10/09/08 SPINNER A/C SPLITS Multi Lateral A+B+D 938 B 356 A 403 1J-170 02923310-00 10/02/06 0729/08 SPINNER A/C SPLITS Multi Lateral A+B+D 2000 B 2000 A 0 1J-180 02923329-00 05/13/07 05/19/08 SPINNER A/C SPLITS Mufti Lateral B+D 665 B 332 21_ >> Total ZPROF Covert for 2008 ATTACHMENT KUPARUK RIVER UNIT WEST SAK OIL POOL CONSERVATION ORDER 406 RULE 11 -PRODUCTIVITY PROFILES ANNUAL 2008 SUBMITTAL 1 Of 1 WELL API DATE OF DATE OF DATA TYPE REASON FOR WELL ZONES PRODUCTION NUMBER NUMBER INITIAL PROFILE/ PROFILE/ PROFILE/ COMPLETION PROD- OIL WATER GAS 50- PRODUCTION SURVEY SURVEY SURVEY TYPE UCING BOPD BWPD MSCFD 1J-101 02923286-00 01/06 10/19/08 SPINNER A/C SPLITS From Schematic A+B+D 1360 105 680 B 476 37 238 A 408 32 204 1J-152 02923298-00 04/06 07/02/08 SPINNER A/C SPLITS From Schematic A+B+D 2588 0 668 B 1294 0 334 A 0 0 0 1J-159 02923297-00 04/06 10/13/08 SPINNER A/C SPLITS From Schematic A+B+D 923 26 1677 B 0 0 0 A 0 0 0 1J-166 02923291-00 03/06 07/03/08 SPINNER A/C SPLITS From Schematic A+B+D 1519 480 316 B 1215 384 253 A 0 0 0 1J-166 02923291-00 03/06 10/10/08 SPINNER FOLLOW-UP From Schematic A+B+D 1019 93 1676 B 0 0 0 A 0 0 0 1J-168 02923260-00 10/05 10/12/08 SPINNER A/C SPLITS From Schematic A+B+D 921 28 1677 B 184 6 33 A 184 6 33 Attachment 7 Kuparuk River Unit West Sak Oil Pool 2008 Annual Reservoir Surveillance Report Production Logs and Special Surveys Geochemical Oil Production Splits: Well Name Sample Date A Sand B Sand D Sand 1C-102 03/01/08 0% 8% 92% 1C-102 07/26/08 0% 11% 89% 1C-104 07/26/08 0% 64% 36% 1C-111 06/02/08 0% 0% 100% 1C-111 09/21/08 0% 0% 100% 1C-117 06/03/08 29% 1% 70% 1C-117 09/23/08 0% 1% 99% 1C-117 11/07/08 100% 0% 0% 1C-119 06/16/08 5% 3% 92% 1 C-119 10/17/08 0% 25% 75% 1C-121 05/16/08 0% 40% 60% 1C-121 10/18/08 0% 60% 40% 1C-125 06/05/08 100% 0% 0% 1C-127 06/03/08 73% 0% 27% 1C-127 11/07/08 100% 0% 0% 1C -172A 07/01/08 100% 0% 0% 1D-102 07/22/08 0% 59% 41% 1D-108 02/10/08 65% 4% 31% 1D -110A 02/11/08 43% 12% 45% 1D -110A 07/27/08 36% 11% 53% 1D-112 02/11/08 19% 41% 40% 1D-112 07/27/08 54% 19% 27% 1D-113 08/18/08 22% 16% E% 1D-115 02/11/08 56% 18% 26% 1D-115 07/27/08 52% 25% 23% 1D-116 03/07/08 52% 19% 29% 1D-116 07/27/08 46% 27% 27% 1D-118 03/08/08 100% 0% 0% 1D-118 07/27/08 100% 0% 0% 1D-121 03/01/08 43% 23% 34% 1D-123 02/10/08 68% 21% 11% 1D-123 08/17/08 11% 59% 30% 1D-124 02/10/08 70% 15% 15% 1D-124 07/27/08 56% 19% 25% 1D-126 07/27/08 83% 5% 12% 1D-127 09/30/08 40% 0% 60% 1D-129 02/10/08 72% 17% 10% 1D-129 07/27/08 63% 9% 27% 1D-131 02/10/08 74% 26% 0% 1D-131 07/27/08 85% 5% 10% 1D-133 08/18/08 86% 1% 13% 1D-134 07/27/08 62% 7% 31% 1D-135 02/11/08 19% 33% 49% 1D-135 07/27/08 0% 43% 57% 1D-136 12/28/08 0% 70% 30% 1D-141 04/23/08 0% 0% 100% 1D -141A 07/20/08 0% 0% 100% Well Name Sample Date A Sand B Sand D Sand 1E-112 01/11/08 0% 85% 15% 1E-114 08/10/08 40% 0% 60% 1E-121 03/01/08 0% 37% 63% 1E-121 07/26/08 0% 24% 76% 1E-123 03/01/08 0% 37% 63% IE -123 07/23/08 0% 41% 59% 1 E-126 05/25/08 0% 83% 17% 1E-126 07/23/08 16% 0% 84% 1E-166 03/01/08 27% 74% 0% 1E-166 07/23/08 12% 62% 27% 1E-168 03/01/08 11% 32% 56% 1E-168 07/23/08 0% 36% 64% 1E-170 03/01/08 23% 55% 23% 1E-170 07/23/08 32% 47% 21% 11-101 02/23/08 36% 14% 50% 1J-101 07/22/08 46% 7% 47% 1J-101 10/19/08 30% 35% 35% 1J-103 01/22/08 0% 3% 97% 1J-103 02/23/08 0% 00/. 100% 1J-103 07/21/08 0% 0% 100% 1J-105 08/19/08 0% 100% 0% 1J-107 02/10/08 0% 0% 100% 1J-107 08/17/08 0% 0% 100% 1J-115 02/23/08 25% 19% 56% 1J-115 07/21/08 21% 28% 51% 11-118 08/17/08 0% 61% 39% 1J-120 02/11/08 7% 5% 89% 1J-120 08/18/08 0% 0% 100% 1J-122 08/18/08 0% 65% 35% 1J-127 01/21/08 10% 60% 30% 1J-127 08/14/08 0% 0% 100% 1J-135 02/11/08 0% 7% 93% 1J-135 07/22/08 0% 7% 93% 1J-136 02/02/08 0% 78% 22% 1J-137 02/10/08 0% 47% 53% 1J-137 07/21/08 0% 45% 55% 1J-152 02/23/08 20% 21% 59% 1J-152 04/18/08 66% 20% 14% 1J-152 07/02/08 0% 50% 50% 1J-152 07/21/08 53% 13% 34% 1J-156 08/21/08 0% 59% 41% 11-158 02/23/08 0% 36% 64% 1J-158 06/26/08 0% 43% 57% 11-158 07/21/08 0% 39% 61% 1J-159 03/05/08 55% 43% 2% 1J-159 07/21/08 29% 5% 66% 1J-159 10/13/08 0% 0% 100% 1J-160 05/17/08 0% 15% 85% 1J-162 02/23/08 0% 53% 47% 1J-162 07/21/08 0% 57% 43% 1J-164 01/04/08 0% 100% 0% 1J-164 10/09/08 43% 38% 19% 1J-166 04/30/08 73% 10% 17% 1J-166 07/03/08 0% 80% 20% 1J-166 07/21/08 33% 12% 56% 1J-166 08/22/08 23% 0% 78% 1J-166 10/10/08 0% 0% 100% 1A68 02/09/08 49% 26% 25% Well Name Sample Date A Sand B Sand D Sand 1J-168 07/22/08 12% 35% 53% 1J-168 10/12/08 20% 20% 60% 1J-170 07/29/08 0% 100% 0% 1J-174 02/01/08 0% 55% 45% 1J-174 03/01/08 0% 56% 44% 1J-174 03/06/08 0% 59% 41% 1J-174 07/21/08 0% 48% 52% 1J-178 01/05/08 0% 57% 43% 1J-178 07/21/08 0% 57% 43% Attachment 8 West Sak Oil Pool 2008 Annual Reservoir Surveillance Report Production Allocation Factors Oil Gas Water Jan -08 0.9478 0.8895 1.009 Feb -08 0.9487 0.8901 1.0137 Mar -08 0.9551 0.9323 1.0108 Apr -08 0.9844 0.8857 1.0103 May -08 0.9695 0.8722 1.0125 Jun -08 0.9584 0.8326 1.03 Jul -08 0.9811 1.0108 1.0394 Aug -08 0.9468 0.9473 1.0122 Sep -08 0.9685 0.9386 1.0252 Oct -08 0.9562 0.9219 1.0177 Nov -08 0.9476 0.903 1.0344 Dec -08 0.9442 0.8725 1.0356 Attachment 9 Kuparuk River Unit West Sak Oil Pool 2008 Annual Reservoir Surveillance Report Future Development Plans • WEST SAK DEVELOPMENT The Kuparuk River Unit working interest owners intend to complete three West Sak wells in 2009. Wells 3K-103 and 3K-108 (both dual lateral injectors) were drilled and completed with rig Doyon 15 in late 2008 and will be put on water injection in early 2009. These injectors support producer 3K-102 which will be put on production in the first quarter as well. The three West Sak 3K wells (3K- 102, 3K-103, and 3K-108) represent completion of the first pattern within the 3K Phase 1 development area. Due to the economic business climate, further West Sak development work is uncertain. • UGNU PILOTS/ STUDIES Plans to test an induction heater well 1 H-Ugnu-01 have been postponed due to the economic business climate. Feasibility studies and engineering continue for a thermal pilot in the DS -30 area. Resource wide subsurface description (reservoir & oil quality) activities are progressing which will enable a more robust analysis of the resource target and required piloting design/ technologies. ConocoPhillips March 17, 2009 Mr. Dan Seamount, Commissioner Alaska Oil and Gas Conservation Commission 333 West 7t' Ave. Suite #100 Anchorage, Alaska 99501-3539 James T. Rodgers Manager— GKA Light Oil ConocoPhillips Alaska Inc. ATO -1220 PO Box 100360 Anchorage AK 99510-0360 Phone (907)263-4027 Fax: (907)265-6133 Re: Allowable Gas Offtake from Kuparuk River Oil Pool 2008 Dear Mr. Seamount, In compliance with Rule 13, Conservation Order No. 432D, ConocoPhillips Alaska, Inc., operator of the Kuparuk River Oil Pool, is hereby submitting the gas offtake volume information. During 2008, the annualized average gas offtake was 1584 MSCFD, considerably less than the maximum allowable annual average gas offtake rate of 5 MMSCFD as stated in Rule 13 for Kuparuk River Oil Pool. If you have any questions concerning this data, please contact Mark Kovar at (907) 265-6097. Sincerely, Ja es T. Rodgers Manager — GKA Light Oil Greater Kuparuk Area bcc: Central Files ATO -3 Attachment 1 Kuparuk River Oil Pool 2008 Annual Reservoir Surveillance Report Gas Offtake Data 2009 Monthly Gas Offtake MSCFD SCFD RB/D January 1950 1949968 1722 February 2167 2166966 1913 March 2216 2216258 1957 April 2093 2092733 1848 May 2040 2039710 1801 June 1173 1173000 1036 July 1519 1519226 1341 August 1714 1714129 1514 September 1561 1560833 1378 October 863 863161 762 November 872 871533 770 December 842 841677 743 Average 1,5841,584,100 1,399 T� n %/I T� -�`ty b C) O O O O N o LOo N 0 LL U
