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Home My WebLink About2002 Greater Kuparuk AreaJames R. Hand Supervisor - Drillsite Petroleum Engineering Greater Kuparuk Area ConocoPhillips Alaska Inc. ATO- 1 276 PO Box 100360 Anchorage AK 9951 0-0360 Phone (907)263-4027 Fax: (907)265-6133 April 1, 2003 Ms. Sarah H. Palin, Commissioner Alaska Oil and Gas Conservation Commission 333 West 7th Ave. Suite #I00 Anchorage, Alaska 99501 -3539 Re: 2002 KRU Annual Surveillance Report Dear Ms. Palin, In compliance with Rule 3, Conservation Order No. 198B, 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 2002. The following is an outline of the information provided: A summary of the enhanced recovery project (Attachment 1). Voidage balance, by month, of produced and injected fluids, including low molecular weight hydrocarbons (Attachment 2, Attachment 3). Analysis of reservoir pressure surveys taken in 2002 (Attachment 4). A tabulation of both injection (Attachment 5) and production (Attachment 6) logs and surveys analyzed during 2002 from wells in the Kuparuk permit area. Composition of enriched gas injected during 2002 and estimate of MMP (Attachment 7). Kuparuk LSEOR development plan (Attachment 8). If you have any questions concerning this data, please contact Robert Christensen at (907) 659-7535 or Mark Stevenson at (907) 263-491 7. Sincerely, gz-- //m ames R. Hand Supervisor - Drillsite Petroleum Engineering Greater Kuparuk Area Attachment 1 Kuparuk River Unit Kuparuk River Oil Pool 2002 Annual Surveillance Report Summary of the Enhanced Recovery Project Conservation Order 198B Rule 3. Kuparuk River Unit Reservoir Surveillance Proqram (a) Progress of enhanced recovery project(s) implementation and reservoir management summary including engineering and performance parameters. ENHANCEDRECOVERY Miscible water-alternating-gas (MWAG) continues as the predominant EOR process at the Kuparuk field. In 2002, four additional wells at DSI E commenced MWAG operations. The total number of MWAG drill sites in Kuparuk -is 28. The field continues to manufacture miscible injectant (MI) at two of its Central Processing Facilities (CPF's). MI manufacture occurs by blending together produced lean gas and natural gas liquids (NGLs). NGLs originate from two sources (1) the Kuparuk field itself (known as indigenous NGLs), and (2) imported from Prudhoe Bay. Importation is utilized to fill any shortfall between total NGL requirement and indigenous NGL production. Due to the superior performance of the MWAG process over the Immiscible Water-Alternating Gas (IWAG) process, the Kuparuk EOR project continues to maximize the manufacture of MI by blending all available lean gas with NGLs. There was no IWAG injection at Kuparuk in2002. The EOR project expanded to four new wells at DSIE during 2002. There was also a 12" pipeline installated in 2002 between Central Processing Facility 2 and Drill Site 1Y to assure adequate MI delivery pressures to the CPFl and CPF3 LSEOR expansion drillsites. The 2002 annual average MI injection into the LSEOR expansion drillsites as of 2002 is 66 MMSCFD. Total MI injection into Kuparuk averaged 222 MMSCFD for2002. The incremental oil production resulting from MWAG at Kuparuk averaged 30 MBPD in 2002. The Greater Kuparuk Area utilized an average of 14 MBPD of indigenous NGLs and 28 MBPD of imported NGLs to manufacture 286 MMSCFD of MI, of which 66 MMSCFD was supplied to the GKA satellite fields Tarn and Meltwater. The priorities for gas management for the Kuparuk field in 2002 were: I) focus MI injection into newly expanded MWAG patterns (A and C sands) and 2) focus MI injection into patterns nearing full maturity. A sand patterns and new C Sand MWAG patterns have higher gas storage efficiency than mature C sand patterns resulting in greater overall oil production due to the consequent suppression of gas production. This, combined with the less than expected gas production from the satellite fields in 2002, resulted in a reduction in the total volume of lean gas available for MI manufacture in 2002 when compared to 2001. As a result of the reduced amount of MI manufacture, the focus of MI injection towards patterns nearing full maturity is to terminate MI injection to those patterns, and utilize that MI for less mature patterns. Conservation Order 1988 Rule 3. Kuparuk River Unit Reservoir Surveillance Proqram MWAG Small Scale EOR (SSEOR and SSEORX) Drill Sites IA, IY, and 22 continued MWAG during 2002. The 2002 average MI injection rate was 14 MMSCFD. To date, these drill sites recovered over half of the ultimate incremental reserves through the MWAG process. Large Scale EOR (LSEOR) The original LSEOR Drill Sites include: 1 F, 1 G, IQ, 1 R, 2A, 28, 2C, 2D, 2F, 2G, 2H, 2K, 2M, 2T, 2U, 2V, 2W, and 2X. The total MI injection rate into these drillsites averaged I31 MMSCFD in 2002. CPF-3 EOR DS3F was not part of the original LSEOR scope, but was approved shortly thereafter for MI injection. The 2002 average MI injection into DS3F was 11 MMSCFD. EOR Expansions CPF-3 has four additional drill sites on MWAG: DS3B, 3H, 30, and 3Q. CPF-1 has two additional drill sites 1C and 1 E. The combined average MI injection into these expansion drillsites is 66 MMSCFD. IWAG The Kuparuk EOR project continues to maximize MWAG operation by blending all available lean gas for MI. No IWAG operation is currently undertaken. KUPARUK EOR DRILL SITE STATUS SSEOR and SSEORX LSEOR and LSEORX EOR Expansion in 2001 EOR Expansion in 2002 - 4 wells EOR Expansion in 2003 EOR Expansion in 2004 Potential Future Expansion Kuparuk EOR Drill Sites (SSEOR+LSEOR+3F) Incremental EOR Oil Rate (Data Available from Jan '93 through Dec '02) Attachment 2 Kuparuk River Unit Kuparuk River Oil Pool 2002 Annual Surveillance Report Produced Fluid Volumes Attachment 2 Kuparuk River Oil Pool 2002 Annual Reservoir Surveillance Report Produced Fluid Volumes OIL GAS WATER CUM OIL CUM GAS CUM WATER MO YR MSTB MMSCF MSTB MSTB MMSCF MSTB 1 2002 5,462 6,196 18,000 1,806,544 1,002,321 1,937,709 2 2002 4,814 5,421 15,917 1,811,358 1,007,742 1,953,627 3 2002 5,368 6,386 17,465 1,816,725 1,014,128 1,971,091 4 2002 4,935 5,776 15,803 1,821,660 1,019,904 1,986,895 5 2002 4,824 5,085 14,813 1,826,484 1,024,989 2,001,708 6 2002 4,743 4,792 15,085 1,831,227 1,029,781 2,016,793 7 2002 4,697 4,749 14,963 1,835,924 1,034,529 2,031,755 8 2002 4,976 4,845 15,020 1,840,900 1,039,375 2,046,775 9 2002 4,832 4,847 14,638 1,845,732 1,044,222 2,061,413 10 2002 4,784 5,661 15,053 1,850,516 1,049,883 2,076,466 11 2002 4,427 5,433 13,842 1,854,943 1,055,315 2,090,308 12 2002 5,151 6,482 14,580 1,860,094 1,061,798 2,104,888 2002 TOTAL 59,012 65,673 185,179 Cumulatives at Dec 31, 2001 1,801,081 996,125 1,919,710 Produced Fluid Volumes (Reservoir Units) OIL GAS WATER CUM OIL CUM GAS CUM WATER MO YR MRVB MRVB MRVB MRVB MRVB MRVB 1 2002 6,719 7,069 18,317 2,222,048 1,291,369 1,971,819 2 2002 5,920 6,191 16,196 2,227,969 1,297,560 1,988,015 3 2002 6,603 7,244 17,773 2,234,571 1,304,804 2,005,788 4 2002 6,071 6,565 16,080 2,240,642 1,311,370 2,021,868 5 2002 5,933 5,857 15,073 2,246,574 1,317,227 2,036,941 6 2002 5,835 5,551 15,349 2,252,409 1,322,777 2,052,290 7 2002 5,778 5,500 15,225 2,258,187 1,328,278 2,067,515 8 2002 6,120 5,639 15,284 2,264,307 1,333,917 2,082,798 9 2002 5,943 5,622 14,895 2,270,250 1,339,539 2,097,694 10 2002 5,884 6,427 15,318 2,276,133 1,345,966 2,113,011 11 2002 5,446 6,141 14,086 2,281,580 1,352,106 2,127,097 12 2002 6,335 7,306 14,837 2,287,915 1,359,412 2,141,934 2002 TOTAL 72,586 75,113 188,432 Cumulatives at Dec 31, 2001 2,215,330 1,284,299 1,953,502 Attachment 3 Kuparuk River Oil Pool 2002 Annual Surveillance Report Injected Fluid Volumes Attachment 3 Kuparuk River Oil Pool 2002 Annual Reservoir Surveillance Report Injected Fluid Volumes WATER GAS MI CUM WATER CUM GAS MI MO YR MSTB MMSCF MMSCF MSTB MMSCF MMSCF 1 2002 20,148 0 7,840 3,942,084 1,058,152 602,837 2 2002 17,742 0 6,443 3,959,826 1,058,152 609,280 3 2002 19,656 0 7,943 3,979,482 1,058,152 617,223 4 2002 18,647 0 7,241 3,998,129 1,058,152 624,465 5 2002 18,935 0 6,254 4,017,065 1,058,152 630,719 6 2002 18,675 0 5,787 4,035,740 1,058,152 636,506 7 2002 16,772 0 5,454 4,052,512 1,058,152 641,960 8 2002 18,266 0 6,084 4,070,777 1,058,152 648,044 9 2002 16,973 0 6,070 4,087,750 1,058,152 654,114 10 2002 16,549 0 6,827 4,104,298 1,058,152 660,941 11 2002 15,045 0 7,796 4,119,344 1,058,152 668,737 12 2002 17,932 0 7,416 4,137,276 1,058,152 676,153 2002 TOTAL 215,339 0 81,157 Cumulatives at Dec 31, 2001 3,921,937 1,058,152 594,996 Injected Fluid Volumes (Reservoir Units) WATER GAS MI CUM WATER CUM GAS CUM MI MO YR MRVB MRVB MRVB MRVB MRVB MRVB 1 2003 20,501 0 5,880 4,010,944 931,165 452,128 2 2003 18,053 0 4,832 4,028,997 931,165 456,960 3 2003 20,000 0 5,957 4,048,997 931,165 462,917 4 2003 18,973 0 5,431 4,067,970 931,165 468,349 5 2003 19,266 0 4,691 4,087,236 931,165 473,040 6 2003 19,002 0 4,340 4,106,238 931,165 477,380 7 2003 17,065 0 4,090 4,123,303 931,165 481,470 8 2003 18,585 0 4,563 4,141,888 931,165 486,033 9 2003 17,271 0 4,552 4,159,159 931,165 490,586 10 2003 16,839 0 5,120 4,175,998 931,165 495,706 11 2003 15,309 0 5,847 4,191,307 931,165 501,552 12 2003 18,245 0 5,562 4,209,552 931,165 507,115 2002 TOTAL 219,108 0 60,868 Cumulatives at Dec 31, 2001 3,990,444 931,165 446,247 Attachment 4 Kuparuk River Oil Pool 2002 Annual Surveillance Report Reservoir Pressure Surveys Page 1 of 4 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION ANNUAL RESERVOIR PRESSURE REPORT - 2002 Name of Operator ConocoPhillips Alaska Inc. Address P. 0. Box 100360, Anchorage, AK 99510-0360 Unit or Lease Name I Field and Pool Kuparuk River Field IDatum Reference lOil Gravity lGas Gravity Kuparuk River Unit 1A-12 C 500292068800 0 09/02/02 Well Name ~uparuk River Oil Pool Sand Date Tested mmlddlyy -6200' SS I 0.91 1 0.71 Production and Test Data API Number Production Rates (BblsIDay) (Mcfd) oil] Water1 Gas O,G or WI Shut-in Time Casing Press. Final Shut-in Tubing Press. Pressure at Datum Pressure Test Data Liquid Gradient Tool Depth MD Wt. of Liquid Column B.H. Temp. Wt. of Gas Column Final Observed Pressure Page 2 of 4 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION ANNUAL RESERVOIR PRESSURE REPORT - 2002 Name of Operator ConocoPhillips Alaska Inc. Address P. 0. Box 100360, Anchorage, AK 99510-0360 Unit or Lease Name I Field and Pool Ku~aruk River Field l~atum Reference l0il Gravitv )Gas Gravitv Kuparuk River Unit 12U-09 A 500292130100 0 06/19/02 3400 1200 7918 156 3323 74 422 71 1 3482 1 Well Name ~uparuk River Oil Pool Sand Date Tested mm/dd/yy -6200' SS I 0.91 1 0.71 Production and Test Data API Number Shut-in Time Production Rates (BblsIDay) (Mcfd) oil( Water1 Gas O,G or WI Wt. of Liquid Column Liquid Gradient Final Shut-in Tubing Press. Pressure Test Data Pressure at Datum Wt. of Gas Column Tool Depth MD Casing Press. B.H. Temp. Final Observed Pressure Paae 3 of 4 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION ANNUAL RESERVOIR PRESSURE REPORT - 2002 Name of Operator Address ConocoPhillips Alaska Inc. P. 0. Box 100360, Anchorage, AK 9951 0-0360 Unit or Lease Name Field and Pool Kuparuk River Field Datum Reference Oil Gravity Gas Gravity Kuparuk River Unit Kuparuk River Oil Pool -6200' SS 0.91 0.71 Final Pressure Test Data Production and Test Data API O,G Date Shut-in Tool Final Production Rates Wt. of Wt. of Pressure Number or Tested Shut-in Tubing Depth B.H. Observed (BblsIDay) (Mcfd) Liquid Liquid Gas Casing at Well Name Sand WI mmlddlyy Time Press. MD Temp. Pressure oil1 Water1 Gas Gradient Column Column Press. Datum 3G-13 A+C 50 103201 3700 0411 1 102 408 1757 9000 120 4060 0 2500 0 421 0 Paae 4 of 4 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION ANNUAL RESERVOIR PRESSURE REPORT - 2002 [~ame of Operator (Address I ConocoPhillips Alaska Inc. I P. 0. Box 100360, Anchorage, AK 9951 0-0360 Unit or Lease Name I Field and Pool Kuparuk River Field IDatum Reference (oil Gravity as Gravity I hereby certify that the foregoing is true and correct to the best of my knowledge. LSigned & Title GKA Drillsite Petroleum Engineering Supervisor Date Y/'/& Form 1&2 Submit in Duplicate Rev 7 1 80 Kuparuk River Unit 13M-16 A+C 500292 1 72800 0 42161 Well Name Kuparuk River Oil Pool Sand Date Tested mm/dd/yy -6200' SS I 0.91 1 0.71 Production and Test Data Production Rates (BblsIDay) (Mcfd) Oil( water1 Gas API Number Shut-in Time O,G or WI Liquid Gradient Final Shut-in Tubing Press. Pressure at Datum Pressure Test Data Wt. of Liquid Column Final Observed Pressure Wt. of Gas Column Tool Depth MD Casing Press. B.H. Temp. Attachment 5 Kuparuk River Oil Pool 2002 Annual Surveillance Report Injection Survey Data KUPARUK RIVER UNIT KUPARUK RIVER OIL POOL CONSERVATION ORDER 198B RULE 4 - INJECTIVITY PROFILES 2002 ANNUAL SUBMITTAL WELL AP I 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 SZT S ZT S ZT SZT SPINNER SPINNER SPINNER SPINNER SPINNER SPINNER SZT SPINNER SPINNER SPINNER SPINNER Follow up Follow up Follow up Follow up Follow up Follow up Follow up Follow up Follow up Follow up Follow up Follow up Follow up Follow up Follow up Sel. Single Sel. Single Sel. Single Sel. Single Sel. Single Sel. Single Sel. Single Sel. Single Sel. Single Sel. Single Sel. Single Sel. Single Sel. Single Sel. Single Sel. Single KUPARUK RIVER UNIT KUPARUK RIVER OIL POOL CONSERVATION ORDER 1988 RULE 4 - INJECTIVITY PROFILES 2002 ANNUAL SUBMITTAL 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 SPINNER SPINNER S ZT SPINNER SPINNER SPINNER SPINNER SPINNER SPINNER SPINNER SPINNER SPINNER SPINNER SPINNER SPINNER Follow up Follow up Follow up Follow up Follow up Follow up Follow up Follow up Follow up Follow up Follow up Follow up Follow up Follow up Follow up Sel. Single Sel. Single Sel. Single Sel. Single Single Sel. Single Sel. Single Sel. Single Sel. Single Sel. Single Sel. Single Single Single Single Single KUPARUK RIVER UNIT KUPARUK RIVER OIL POOL CONSERVATION ORDER 198B RULE 4 - INJECTIVITY PROFILES 2002 ANNUAL SUBMITTAL WELL AP I 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 SPINNER SPINNER SPINNER SPINNER SPINNER SPINNER SPINNER SPINNER SPINNER SPINNER SPINNER SPINNER SPINNER SPINNER Follow up Follow up Follow up Follow up Follow up Follow up Follow up Follow up Follow up Follow up Follow up Follow up Follow up Follow up Single Single Single Sel. Single Sel. Single Sel. Single Sel. Single Sel. Single Sel. Single Sel. Single Single Single Single Single Attachment 6 Kuparuk River Oil Pool 2002 Annual Surveillance Report Production Survey Data KUPARUK RIVER UNIT KUPARUK RIVER OIL POOL CONSERVATION ORDER 432 RULE 9 - PRODUCTIVITY PROFILES ANNUAL 2002 SUBMITTAL 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 SPINNER SPINNER SPINNER SPINNER SPINNER SPINNER SPINNER SPINNER SPINNER SPINNER S ZT S ZT SPINNER SPINNER SPINNER A/C SPLITS A/C SPLITS A/C SPLITS A/C SPLITS A/C SPLITS A/C SPLITS A/C SPLITS A/C SPLITS Intra A splits Intra A splits CLOSE C SANDS PERF C SANDS A/C SPLITS A/C SPLITS A/C SPLITS Sel. Single Sel. Single Sel. Single Sel. Single Sel. Single Sel. Single Single Single Sel. Single Sel. Single Sel. Single Single Single Single Single KUPARUK RIVER UNIT KUPARUK RIVER OIL POOL CONSERVATION ORDER 432 RULE 9 - PRODUCTIVITY PROFILES ANNUAL 2002 SUBMITTAL 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 SPINNER SPINNER SPINNER SPINNER SPINNER SPINNER SPINNER SPINNER SZT SPINNER SPINNER S ZT S ZT SPINNER SPINNER A/C SPLITS A/C SPLITS FOLLOW-UP A/C SPLITS A/C SPLITS A/C SPLITS A/C SPLITS A/C SPLITS A/C SPLITS A/C SPLITS A/C SPLITS OPEN C SANDS A/C SPLITS A/C SPLITS A/C SPLITS Single Single Single Sel. Single Sel. Single Sel. Single Single Single Sel. Single Sel. Single Sel. Single Sel. Single Sel. Single Single Single KUPARUK RIVER UNIT KUPARUK RIVER OIL POOL CONSERVATION ORDER 432 RULE 9 - PRODUCTIVITY PROFILES ANNUAL 2002 SUBMITTAL 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 3H-03 10320085-00 02 - 94 06-12-02 SPINNER 3H-11 10320091-00 12-93 01-12-02 SZT A/C SPLITS Sel. Single A+C A OPEN C SANDS Sel. Single A+C A 3M-19 02921737-00 02-94 01-21-02 SPINNER A/C SPLITS Single 3N-16 02921593-00 02-94 03-05-02 SPINNER A/C SPLITS Sel. Single A+C A Attachment 7 Kuparuk River Oil Pool 2002 Annual Surveillance Report Miscible lnjectant Composition Conservation Order l98B Rule 3. Kuparuk River Unit Reservoir Surveillance Proqram Attachment 7: MI Composition and MMP Miscible lnjectant (MI) compositions and corresponding Minimum Miscible Pressures (MMP) for the three CPF's are presented in the attached tables. No MI composition data is reported for CPF-3 for 2002 because MI manufacture at CPF-3 ceased in 2000 with the installation of the 1Y Jumper Line. This jumper enabled the expansion of the EOR Project to DS IQ, 30 and 3Q, as well as continued MI supply to DS-3F. MI is now supplied to the CPF-3 drillsites from both CPF-1 and CPF-2. The MMP of the blended CPF-1 and CPF-2 MI is estimated on a monthly average basis and is reported in the attached Table in the column for CPF-3. Prior to 2001, CPF-3 manufactured a small amount of MI for DS-3F with indigenous NGL's. Now, these CPF-3 indigenous NGL's are routed to the wet oil line for transport to CPF-1 and 2 for stabilization in the GKA sales oil, or else recovery as indigenous NGL for reuse within the EOR project. Date 01/16/2002 02/08/2002 0211 812002 0311 312002 04/05/2002 05/04/2002 0511 712002 06/20/2002 07/05/2002 07/21/2002 08/06/2002 08/29/2002 0911 412002 09/25/2002 10/12/2002 10/25/2002 1 1 /29/2002 1211 412002 Facility CPF-1 CPF-1 CPF-1 CPF-1 CPF-1 CPF-1 CPF-1 CPF-1 CPF-1 CPF-1 CPF-1 CPF-1 CPF-1 CPF-1 CPF-1 CPF-1 CPF-1 CPF-I ATTACHMENT 7 KUPARUK RIVER UNIT MI COMPOSITION - CPF-1 EOR ANALYTICAL REPORT KUPARUK LABORATORY CONOCOPHILLIPS ALASKA INC. Facility CPF-1 Sample Date 05/04/2002 Distribution: Sample Time. Line Pressure Line Temp. SETCIM Tag Flow (MSCFD) Component C02 N2 C1 C2 C3 iC4 nC4 iC5 nC5 C6 C7 C8+ rota1 Moles MW Density (Ibslscf) Rate (Ibld) Rate (MoVd) Rate (MMSCFD) 1425 3800 120 Calculated 74775 60.86 19.09 28.73 28.77 36.76 Actual ENFL Rate Ideal BG Rate Actual Gas Rate 2685201.48 2808055.806 29 14208.86 441 18.42 1 47097.1 74 55896926.12 Target Blend Gas Ratio (Ib BGIlb EF) Actual Blend Ratio (From measured flow rates) Youngren MMP Actual MMP (Using Lab MI Composition) Calc MMP (Using Lab BGIENFL comp and rates) MI (Calc) MI (Lab) MI (Target) Solvent (Lab) Lean Gas (Lab) 0.372 1.121 0.948 0.750 0.953 (Mole %) (Mole %) (Mole %) (Mole %) (Mole %) Date 01 11 612002 02/08/2002 02/19/2002 03/09/2002 04/05/2002 05/04/2002 0511 712002 06/05/2002 06/20/2002 07/05/2002 07/21 12002 08/06/2002 0911 412002 09/25/2002 1011 212002 10/25/2002 1 1 /29/2002 1211 412002 Facility CPF-2 CPF-2 CPF-2 CPF-2 CPF-2 CPFP CPF-2 CPF-2 CPF-2 CPF-2 CPF-2 CPF-2 CPF-2 CPF-2 CPF-2 CPF-2 CPFQ CPF-2 ATTACHMENT 7 KUPARUK RIVER UNIT MI COMPOSITION - CPF-2 Facility Sample Date Distribution: EOR ANALYTICAL REPORT KUPARUK LABORATORY CONOCOPHILLIPS ALASKA INC. CPF-2 1012512002 MW 64.36 21.10 28.59 Density (Ibslscf) 37.76 Actual ENFL Rate Ideal BG Rate Actual Gas Rate Rate (Ibld) 6741 983.23 Rate (Molld) 104760.53 50041 1.07 Rate (MMSCFD) 1901 56206.6 Taraet Blend Ratio wl CPF2 aas onlv [Ib BGllb EF) 1.57 Actual Blend Ratio (From measured flow rates) 1.57 Youngren MMP 3300.00 Actual MMP (Using Lab MI Composition) 3482 Calc MMP (Using Lab BGIENFL cornp and rates) MWC7+ in Oil 285 MMP (a) -0.001 7054 MMP (b) -2661 8.5 MMP (c) 1.6 Note: Shaded areas are lab analysis values Non-shaded are calculated values I Minimum Miscible Pressures of MI Supplied to Each CPF MMP Target Spec = Month Jan-02 Feb-02 Mar-02 Apr-02 May-02 J u n-02 Jul-02 Aug-02 Sep-02 Oct-02 Nov-02 Dec-02 Average * Calculated 3300 psia CPFI CPF2 CPF3* CALC MMP** (psia) 3775 3439 3548 CPF3 MI Source CPFI (%I CPF2(%) **Considers NGL pump downtime & gas compressor downtime Attachment 8 Kuparuk River Unit Kuparuk River Oil Pool 2002 Annual Surveillance Report Development Plan for LSEOR Attachment 8 Kuparuk River Oil Pool 2002 Annual Surveillance Report LSEOR Development Plan During 2002, the Greater Kuparuk Area (GKA) averaged 28 MBPD of PBU NGL imports and 14 MBPD of indigenous NGLs for an annual average of 286 MMSCFD of Miscible lnjectant (MI) manufacture. Of the GKA manufactured MI volume, 222MMSCFD was distributed to Kuparuk: 142 MMSCFD to LSEOR drillsites (including 3F), 14 MMSCFD to SSEOR and SSEORX drillsites, and 66 MMSCFD to LSEOR expansion drillsites. The remaining 66 MMSCFD was distributed to the GKA satellites. LSEOR expansion drillsites include drillsites: 1 C, 1 E, 38, 3H, 30, 3Q and 3s. Currently MI is injected into all of the 18 drillsites sanctioned under the LSEOR project and the CPF-3 EOR expansion drill site 3F. In 2003, plans are being developed to expand the Kuparuk EOR project to drill sites 3G, 1 B, and 1 L. Also, a West Sak (DSI C) EOR pilot is scheduled to begin in second half of 2003. Further drilling activity in the Kuparuk River Oil Pool potentially provides new opportunities to maximize field recovery while preventing physical waste. Drilling opportunities are under constant evaluation as the field matures, geologic and reservoir performance information is assimilated and as technology improves. The Kuparuk EOR project may be expanded to include any new wells. K ConocoPhillips April 1, 2003 Ms. Sarah H. Palin, Commissioner Alaska Oil and Gas Conservation Commission 333 West 7th Ave. Suite # 100 Anchorage, Alaska 99501-3539 James R. Hand Supervisor - Drillsite Petroleum Engineering Greater Kuparuk Area ConocoPhillips Alaska Inc. ATO-1276 PO Box 100360 Anchorage AK 99510-0360 Phone (907)263-4027 Fax: (907)265-6133 Re: 2001-2002 Meltwater Oil Pool Annual Reservoir Surveillance Report Dear Ms. Palin, In compliance with Rule 10, Conservation Order No. 456, ConnocoPhillips Alaska, operator of the Kuparuk River Field, is hereby submitting the annual report on the Meltwater Oil Pool. This report documents the required information pertinent to the field development and enhanced recovery operations from November 2001 through December 2002. The following is an outline of the information provided: a. Progress of FOR project and reservoir management summary (Attachment 1). b. Voidage balance, by month, for produced and injected fluids (Attachment 2, Attachment 3). c. Analysis of reservoir pressure surveys taken in 2001-2002 (Attachment 4). d. Results of production surveys, and any special surveys, taken on the Meltwater Oil Pool in 2001-2002 (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 Bob Christensen at (907) 659-7535 or Ronda Wenger at (907) 265-6902. Sincerely, ames R. Hand A PR 0 1 200? Supervisor - Drillsite Petroleum Engineering Greater Kuparuk Area _.•,ti;:U'rt .6 Attachment 1 Kuparuk River Unit Meltwater Oil Pool 2001-2002 Annual Reservoir Surveillance Report Progress of FOR 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. By year-end 2001, five Meltwater development wells had been drilled. Eleven development wells were drilled and online by the end of 2002. Progress of FOR Project Development activities in 2001-2002 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 2001-2002. 1. Construction of the Meltwater road, pads, power lines and pipelines took place in the 2000/2001 winter construction season. 2. Meltwater development drilling commenced in May of 2001. 3. After two wells were completed, drilling ceased on June 3, 2001 due to soft gravel on the road and pad. 4. Drilling resumed October 15, 2001 completing a total of 5 wells by 2001 year end. 5. Meltwater production began on November 28, 2001. 6. The 12" water line was commissioned in October 2001. The water has been used for jet pump lift in one producer and cycled through the 24" production header to mitigate paraffin deposition between drillsites 2P and 2N. No water has been injected into the Meltwater reservoir to date. Alternation of the MI injection to water is planned in 2Q 2003. 7. In January 2002, the 8" MI pipeline was commissioned. Miscible gas injection initiated into the two Meltwater injectors and miscible gas lift was initiated in select producers. 8. One well was drilled from 2P that penetrated the prospective Cairn exploration play. 9. After the eleventh development well was completed, drilling ceased on May 19, 2002 due to soft gravel on the road and pad. Below is a listing of the most important new findings derived from the 2001-2002 Meltwater development efforts: 1. The production performance and/or pressure data associated with wells 2P-417, 422A, 427, 431, 438, 441, 451 indicate the producers are in communication with one or both of the Meltwater injectors. 2. The 2P-422 penetration discovered a water bearing Bermuda sand interval. The oil water contact is estimated at 5515' TVDSS. The well was sidetracked to a hydrocarbon bearing location in the Meltwater Oil Pool. 3. The 2P-415 penetration into the Cairn feature found non-commercial hydrocarbon gas and condensate present in the main Cairn channel. The well was ultimately sidetracked and completed in the Bermuda interval. There is Cairn interval stringer sands present above the Bermuda in some well locations. In the Meltwater well locations where the Cairn interval stringer is present, the completions were altered to preserve access to the Cairn interval at a later date. 4. The 2P-448 location tested an apparent high energy depositional feature near the shelf slope margin on the western edge of the Meltwater field. Non -hydrocarbon bearing sand was discovered and the well was sidetracked to a hydrocarbon bearing location. 5. Paraffin deposition in the Meltwater wellbores and pipelines has occurred. The main techniques employed to combat the paraffin deposition are hot oil treatments (wellbore and surface line) and wireline paraffin cutting in the tubing. Paraffin deposition is mitigated in the 24" production line by cycling produced water through the 12" line, through the pigging facilities at 2P, and down the 24" production pipeline. This water cycling mitigation technique uses 1-20 MBWPD throughout the year to maintain the production header temperature above cloud point. Pigging of the 24" oil line between 2P and CPF2 has occurred once to mechanically remove the paraffin deposition in the pipeline. 6. A low volume high pressure gas kick occurred while drilling through the C37 interval in 2P-441. Mud weights increased from 9.6 to 11.5 ppg to control the pressure. An extra casing string was set and the well was drilled to total depth. 7. Currently at 2P, one producer uses a water jet pump for artificial lift. The remaining eight producers use miscible gas lift for artificial lift when necessary to kick off production or stabilize oil rates. 8. Outer annuli pressures in 2P-431, 2P-438, and 2P-451 elevated to anomalous levels in 2002. Reservoir Management Summary Meltwater came on-line in November of 2001 and produced 0.14 million barrels of oil, 5.1 thousand barrels of water, and 0.12 billion cubic feet of gas by year-end 2001. By year-end 2002, Meltwater produced 2.90 million barrels of oil, 43.5 thousand barrels of water, and 4.14 BCF of gas. Miscible gas injection did not begin until January of 2002. 6.3 BCF of MI was injected in 2002. .4 Early performance from five of the nine Meltwater producers indicate they are receiving voidage replacement from the injectors. The pressure support is indicated by stabilized oil rates, decreasing GORs, and elevated initial reservoir pressure in some of the wells drilled after months of injection. Recent pressure data from 2P-448A as well as the production and GOR trends indicate the well is not receiving pressure support. 2P-451 had elevated initial reservoir pressures as a result of 2P-420 injection but is not receiving sufficient voidage replacement as seen by elevated, but stable GORs. Both 2P-448A and 2P-451 are located more than one well spacing away from an existing injectors. Effective voidage replacement to these two producers will not be feasible until injectors are drilled closer to the producing bottom hole locations. These injectors are planned in the next phase of drilling in 4Q 2003. The production rate of 2P-438 is relatively stable with slowly increasing GORs indicating the drainage of a large volume but insufficient voidage replacement. The 2003 drilling program will include offset injectors to provide additional pressure support to 2P-438. The initial reservoir pressure at 2P-422A was 600 psi over virgin conditions. This data indicates that the producer is in communication with one or both of the offset injectors. The fact that the high pressure at this bottom hole location did not bleed off to existing pressure sinks indicates a potential flow barrier or baffle to the west of 2P-422A. 2P-415A has not exhibited a discernible response to offset injection. 2P-415A is the poorest performing producer at Meltwater. The bottom hole location of 2P-415A is located in a lower permeability sand at the distal portion of the northern channel. A potential channel feature seen on seismic near 2P-415A could hinder injection support from 2P-420. Additional surveillance is required to define communication between the well pair. Attachment 2 Meltwater Oil Pool 2002 Annual Reservoir Surveillance Report Produced Fluid Volumes OIL GAS WATER CUM OIL CUM GAS CUM WATER MO YR STB MSCF BBL STB MSCF BBL 11 2001 5234 652 3069 5234 652 3069 12 2001 143621 116061 1994 143621 116061 1994 1 2002 126520 135975 1683 126520 135975 1683 2 2002 130574 132860 1051 257094 268835 2734 3 2002 170124 167934 1824 427218 436769 4558 4 2002 258973 322971 9694 686191 759740 14252 5 2002 336766 417908 5707 1022957 1177648 19959 6 2002 281862 388904 5675 1304819 1566552 25634 7 2002 253255 393907 7621 1558074 1960459 33255 8 2002 287931 418014 980 1846005 2378473 34235 9 2002 243142 370733 580 2089147 2749206 34815 10 2002 245899 387578 102 2335046 3136784 34917 11 2002 279878 469148 6120 2614924 3605932 41037 12 2002 286959 536195 2496 2901883 4142127 43533 2001 TOTAL 148855 116713 5063 2002 TOTAL 2901883 4142127 43533 Last years cum 0 0 0 Attachment 3 Meltwater Oil Pool 2002 Annual Reservoir Surveillance Report Injected Fluid Volumes WATER GAS NGLS CUM WATER CUM GAS CUM NGLS MO YR STB MSCF MSCF STB MSCF MSCF 11 2001 0 0 0 0 0 0 12 2001 0 0 0 0 0 0 1 2002 0 0 551328 0 0 551328 2 2002 0 0 904030 0 0 1455358 3 2002 0 0 303047 0 0 1758405 4 2002 0 0 361922 0 0 2120327 5 2002 0 0 293116 0 0 2413443 6 2002 0 0 564548 0 0 2977991 7 2002 0 0 799479 0 0 3777470 8 2002 0 0 804250 0 0 4581720 9 2002 0 0 777765 0 0 5359485 10 2002 0 0 382104 0 0 5741589 11 2002 0 0 64773 0 0 5806362 12 2002 0 0 538337 0 0 6344699 2001 TOTAL 0 0 0 2002 TOTAL 0 0 6344699 Last years cum 0 0 0 Attachment 4 Meltwater Oil Pool 2001-2002 Annual Reservoir Surveillance Report Reservoir Pressure Surveys Meltwater reservoir pressure is referenced to a depth of 5400' ss. Production commenced at 2P pad in November of 2001. Initial reservoir pressure measurements for nine of the Meltwater wells ranged from 2360-2560 psi. The initial reservoir pressure measurements for 2P-422A and 213-427 were 2996 and 3130 psi respectively. These significantly elevated reservoir pressures resulted from existing offset injection. A 72 hour pressure build up test on Well 2P-448A showed a final pressure of 1800 psi at datum depth. This low pressure in addition to production trends indicates 2P-448A is lacking sufficient injection support. A 15 day pressure fall off test on 2P-420 showed a final pressure of 2923 psi at datum depth. A listing of all 2001-2002 data is attached below. STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION ANNUAL RESERVOIR PRESSURE REPORT - 2002 Name of Operator Phillips Alaska Inc. Address I P. O. Box 100360, Anchorage, AK 99510-0360 Unit or Lease Name Field and Pool Kuparuk River Field Datum Reference Oil Gravity Gas Gravity Ku aruk River Unit Meltwater Oil Pool -5400' SS 34.9 0.74 Final Pressure Test Data Production and Test Data API O,G Shut-in Tool Final Production Rates Pressure Number or Date Shut-in Tubing Depth B.H. Observed Bbls/Da Mcfd at Well Name Sand WI Tested Time I Press. MD Temp. Pressure I Oill Waterl Gas Datum 2P-415A A 501032038301 O 12/24/01 99999 325 8645 146 2454 701 175 638 2443 2P-417 A 501032037500 O 12/13/01 99999 320 5505 147 2337 1500 0 1500 2389 2P-420 A 501032039100 GI 12/23/01 99999 2400 6347 142 2439 0 0 16000 2472 2P-438 A 501032037600 O 11/18/01 99999 300 8485 135 2397 4983 102 3309 2463 2P-420 A 501032039100 GI 10/19/02 364 900 6111 129 2903 0 0 3694 2923 2P-422A A 501032040001 O 05/04/02 99999 277 6877 142 2981 3993 40 3063 2996 2P-427 A 501032040800 O 10/19/02 9999 261 10013 144 3139 1911 144 3396 3130 2P-429 A 501032037800 GI 01/14/02 99999 2400 8341 143 2365 0 0 16000 2367 2P-431 A 501032041700 O 04/19/02 99999 288 9295 142 2538 3510 390 2461 2547 2P-441 A 501032040700 O 03/30/02 99999 290 6955 140 2516 2311 257 1920 2558 2P-448A A 501032039601 O 01/27/02 99999 275 7200 140 2292 1500 148 800 2360 2P-448A A 501032039601 O 10/05/02 72 277 6836 128 1638 730 0 2139 2012 2P-451 A 501032040200 O 03/24/02 99999 300 5570 141 2412 4000 167 4000 2501 1 hereby certi that the fore oing is an co ect to the best of my knowledge. y/ / Signed itle GKA Satellites Supervisor Date / / b 3 Form 1eal-2 Rev 7 1 80 Shut in time = 99999 hrs indicates initial reservoir pressure. 4- Attachment 5 Meltwater Oil Pool 2001-2002 Annual Reservoir Surveillance Report Production/Special Surveys • No production or injection surveys were run in 2001-2002. • Cement bond logs were run on the two Meltwater injectors in 2001. Both well logs indicated excellent cement bond above the perforations. • 2P-431, 2P-438, 2P-451 have abnormally high outer annuli pressures. As part of the diagnostic work to identify the source of the outer annuli gas, the following special logging surveys were completed: o In April and October 2002, neutron logs and water flow logs were run on the two injectors, 2P-420 and 2P-429 respectively. The logging objective was to identify channels in the cement behind pipe and look for elevated gas saturations above the injection interval. No channels or increase in gas saturations at shallow depths were found. o In November 2002, noise and temperature logs were run on 2P-431 and 2P-451 to look for casing thread leaks and/or fluid entry points from the formation to the near wellbore region. Noise and temperature anomalies were found in the log results. Initial interpretation indicated these anomalies were formation fluid entry and not casing thread leaks. Further shallow gas diagnostic information is in Attachment 6. r' Attachment 6 Meltwater Oil Pool 2001-2002 Annual Reservoir Surveillance Report Results of Well Allocation, Test Evaluation, and Special Monitoring Well Allocation Meltwater IDS 2P facilities were fabricated with a conventional test separator. A portable test separator system was utilized at IDS 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 gas lift and injection at IDS 2P. 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. Meltwater production was applied an allocation factor of 1.0 for 2001. In 2002, a float - float allocation methodology was implemented. The 2001- 2002 Meltwater allocation factors by month are listed below. Meltwater Oil Pool 2002 Production Allocation Factors Oil Gas Water Nov-01 1.0000 1.0000 1.0000 Dec-01 1.0000 1.0000 1.0000 Jan-02 0.9715 1.0000 1.0000 Feb-02 0.9692 0.9637 1.1027 Mar-02 0.9760 0.9649 1.0741 Apr-02 0.9745 0.9644 1.0581 May-02 0.9728 0.9812 1.0705 Jun-02 0.9712 0.9423 1.1046 Jul-02 0.9500 0.9263 1.0775 Aug-02 0.9503 0.9116 1.0010 Sep-02 0.9511 0.9217 0.9792 Oct-02 0.9590 0.9355 0.2215 Nov-02 0.9566 0.9827 0.8575 Dec-02 0.9860 0.9758 1.0023 r Fracture Stimulation Special Monitoring Radioactive tracer was used to identify the extent of height growth during fracture stimulation treatment of well 2P-417. • On 12/14/01 RA tracer (small amounts of antimony, iridium, and scandium) was added to the initial fractures stimulation treatment on 2P-417. • On 12/19/01 tracer log analysis showed 224' TVD fracture height growth above the top of the Bermuda interval. • Log analysis and elevated gas production during the flowback of 2P-417 indicate that the fracture grew into the thin, poor quality Cairn gas interval located above the top of the Bermuda interval. Gas production rates declined indicating minimal, if any, extended production from the Cairn interval. Shallow Gas Special Monitoring 2P-431, 2P-438 and 2P-451 have elevated outer annuli pressures that rapidly rebuild pressure after bleeding. The following diagnostic work was performed to troubleshoot the problem. • In December 2002, isotopic analysis was performed on outer annuli gas samples taken from 2P-431, 2P-438, and 21P-451 to assist in identifying the gas origin. This isotopic fingerprint was compared to the fingerprint of Bermuda gas as well as the miscible gas that is used for injection and gas lift at Meltwater. The isotopic analysis indicated that the gas present in the outer annuli of 2P-431, 2P- 438, and 2P-451 was miscible gas. • Minimal 1-12S has been detected in the OA gas whereas the miscible gas used for lift and injection has - 100 ppm 1-12S. This indicates that the H2S found in the miscible gas in the OA has been consumed in a chemical reaction. • During the OA bleed events to the production header, liquid slugs have been produced from the 2P-431 and less frequently from 2P-451. The composition of this liquid matches that of the enriching fluids used to make miscible gas injection. • All wells at Meltwater passed tubing and casing integrity tests prior to initial production or injection. To completely eliminate the inner annulus as a potential gas leak path, mechanical integrity tests (MIT) were repeated on the inner annulus of 2P-422A, 2P-431, 2P-4381 2P-451 in early 2003 and passed. After the diesel MIT IA passed on 2P-422A, 2P-438, and 2P-451, the IA was pressured with MI gas to identify the presence of casing thread leaks that might not be identifiable with a liquid integrity test. There were no casing thread leaks found in any of the wells tested. • When miscible injection rates are altered, no pulse affects are noted on the outer annuli of any Meltwater wells. s.` Aft Attachment 7 Meltwater Oil Pool 2001-2002 Annual Reservoir Surveillance Report Meltwater Development Plan and Operational Review Following are summaries of key activities that are planned for 2003 and subsequent years. Development Drilling — Four to eight additional development well locations have been identified. Current plans are to resume drilling in October 2003. These well candidates may be drilled sequentially or divided into two phases of drilling. The total well count after development drilling is expected to be 13-17 wells. MI/Water Injection — Miscible gas injection was initiated at DS 2P in January 2002 into two injectors. The facilities of both injectors are hooked up to implement a WAG (Water Alternating Gas) process. Starting in 2Q 2003 one injector will be converted to water injection while the other remains on MI. Laboratory core flood experiments indicate that short periods of fresh water injection are not expected to cause any appreciable compatibility problems with the Meltwater Formation. It is preferred to keep one injector on MI at all times. This strategy is to eliminate concerns of low MI gas pipeline volumes in the winter causing the miscible gas temperature to drop to ambient conditions. When cold MI is used for gas lift, it causes excessive paraffin deposition in the tubulars and the production header. Artificial Lift — Meltwater currently uses miscible gas (MI) for artificial lift. One 8" pipeline transports gas to drillsites 2N, 2L, and 2P. The miscible gas will be utilized for injection and gas lift until the miscible gas FOR flood is complete at Tarn and Meltwater. Once the targeted MI slug size is injected into the both reservoirs, the gas pipeline will transfer lean gas. This lean gas will be used for gas lift. The lowest oil rate producer, 2P-415A, employs a water powered jet pump for artificial lift. The metered oil rates of 2P-415A fluctuate with the variance in water injection header pressure. Exploration/Delineation — No further exploration work is currently planned. Further delineation of the southern, northern, and south eastern edge of the Meltwater oil pool are planned during the 2003 drilling program. Gravel — Excessive clay content was discovered in the gravel used for the 2P drillsite and road causing soft gravel conditions in the summer of 2001-2002. Remediation efforts to restore the pad condition will continue in 2003. ConocoPhillips April 1, 2003 Ms. Sarah H. Palin, Commissioner Alaska Oil and Gas Conservation Commission 333 West 7th Ave. Suite #100 Anchorage, Alaska 99501-3539 James R. Hand Supervisor - Drillsite Petroleum Engineering Greater Kuparuk Area ConocoPhillips Alaska Inc. ATO-1276 PO Box 100360 Anchorage AK 99510-0360 Phone (907)263-4027 Fax: (907)265-6133 Re: 2002 Tabasco Oil Pool Annual Reservoir Surveillance Report Dear Ms. Taylor: In compliance with Rule 11, Conservation Order No. 435, ConocoPhillips Alaska, Inc., operator of the Kuparuk River Field, is hereby submitting the annual 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 2002. 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, Attachment 3). c. Analysis of reservoir pressure surveys taken in 2002 (Attachment 4). d. Results of production surveys, and any special surveys, taken on the Tabasco Oil Pool in 2002 (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 Jim Ennis at (907) 265-1544. Sincerely, APR 0 12003 eti.l�r� James R. Hand ., .:.. Supervisor - Drillsite Petroleum Engineering Greater Kuparuk Area Attachment 1 Kuparuk River Unit Tabasco Oil Pool 2002 Annual Reservoir Surveillance Report Summary of the Enhanced Recovery Project Tabasco produced 1089 MSTB of crude, 158 MMSCF of formation gas, and 5409 MB of water during 2002. Water injection was 5527 MB over the same period. Cumulative oil, gas, and water production and water injection through year end 2002 were 6720 MSTBO, 961 MMSCF, 15569 MBW, and 18890 MBWI, respectively. The cumulative injection/withdrawal ratio was 0.83 on a reservoir barrel basis through year end 2002. Reservoir pressure declined from approximately 1050 psi to 1020 psi during 2002. No new Tabasco wells were drilled in 2002. A rig workover of 2T-209, which included an extensive fishing job, was completed in March to replace the ESP system which had failed in October, 2001. Injector 2T-210 remained shut-in with mechanical problems which continue to prevent water injection. Year end 2002 Tabasco well count (all at Kuparuk River Unit Drill Site 2T) was: Producers: 7 completed 6 on line Injectors: 2 completed 1 on line Water production reduced slightly to a year end water:oil ratio of 4.0 bbl water per STBO as compared to 4.9 at year end 2001. This reduction is due to the repair of 2T-209's ESP. Water breakthrough has occurred at all 7 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. Attachment 2 Tabasco Oil Pool 2002 Annual Reservoir Surveillance Report Produced Fluid Volumes OIL GAS WATER CUM OIL CUM GAS CUM WATER MO YR STB MSCF BBL STB MSCF BBL 1 2002 51761 8693 274802 5682649 811326 10435425 2 2002 38736 8271 297358 5721385 819597 10732783 3 2002 59348 10942 705383 5780733 830539 11438166 4 2002 84794 14024 644853 5865527 844563 12083019 5 2002 90524 14239 556154 5956051 858802 12639173 6 2002 105990 14529 546160 6062041 873331 13185333 7 2002 108713 17662 506116 6170754 890993 13691449 8 2002 115076 19041 461343 6285830 910034 14152792 9 2002 100162 13852 249462 6385992 923886 14402254 10 2002 121303 18152 339739 6507295 942038 14741993 11 2002 107240 9571 401407 6614535 951609 15143400 12 2002 105353 9543 426213 6719888 961152 15569613 2002 TOTAL 1089000 158519 5408990 Cumulatives Dec 31, 2001 5630888 802633 10160623 Attachment 3 Tabasco Oil Pool 2002 Annual Reservoir Surveillance Report Injected Fluid Volumes WATER GAS NGLS CUM WATER CUM GAS CUM NGLS MO YR STB MSCF MSCF STB MSCF MSCF 1 2002 431632 0 0 13794232 0 0 2 2002 462063 0 0 14256295 0 0 3 2002 529974 0 0 14786269 0 0 4 2002 486634 0 0 15272903 0 0 5 2002 507731 0 0 15780634 0 0 6 2002 487005 0 0 16267639 0 0 7 2002 498594 0 0 16766233 0 0 8 2002 435141 0 0 17201374 0 0 9 2002 407497 0 0 17608871 0 0 10 2002 455657 0 0 18064528 0 0 11 2002 403313 0 0 18467841 0 0 12 2002 422120 0 0 18889961 0 0 2002 TOTAL 5527361 0 0 Cumulatives Dec 31, 2001 13362600 0 0 Attachment 4 Kuparuk River Unit Tabasco Oil Pool 2002 Annual Reservoir Surveillance Report Reservoir Pressure Surveys Rule 8 Form 10-412 follows • N It mrna orr-m a) n a) m r o 0 m r m T o r n o o � • O a R� r r r o_ E U U a c m m C7 U fn U) cu w a ro U N m V N 0 w� O'o m N V N a N V N (D N N N Oco o m ~ O c In c c O m 0 0 0 w O O O m �0. rorn m V T V o O m"t O 5 =N com co M Q cc W O O cc N a L N '_ ro O N IN O O m 0 0 C¢ 5 N N O N N L.2 �2 m m Q E o m o a d m co 0 "O N Cl O V m l0 n O N r m m V O m m U� m a; Z x al ? ro Z r m CA m O T m m O tr Oro O N o O m y C_ a y cn N LL L N O O LL 0 cc LL m co r- r O rn Lo m fo N Occ Up ca . c. nmr`mmmm�mm a x O¢ 'oo moo rmF Q Y Q Q L d cc > F < cr ¢tn Q W QO nrnmmmtommr� movvvv mrnr- y W w y 0 O U to L o n p N m m m r- r N m m m m m m m m m V V V V LL Z O Z¢ O a N cc N m N W U¢ cu LL m Y H fn < Q> N N m m 1 N V O m O U) (;j N N Lo r m o 0 '7 r� r r m r m N m N r C Q W C � N N C ro J cc �D JQ LL U) H d W N O o O m,t m r, N a) E Y Z O C m m m (d n m m m m m N N p� "O fn Z a d N a) N Q M cn~ p N a c d LL o00000000o E `� co n v co Lo co t` co o coo N O r 0 0 N 0 O o N 0 p` 0 d F r r m r o r r N r r r O r O r r r 0 r N Q � Y L � 00 0�0000000000 yO W\= O O O O O O O r o 0 O O o 0 0 0 o 0 o o d L N co N N N N N m N N N C Q E O o o o o o o 0 o 0' N N N N N N N N N N Z m m m m m m m m m m O O O O O O O O O O c p O O O O o 0 o 0 o o U C y m � Lo Lo � 47 In 1n In O C (n co W r O Q m Y N Z a) = a C a) O ro ro o O O ro J E ro N 7 rl n 0)m UD f- o o.0 "O m r r N V O Z O O CD CD N N d m f' co O C N C E Z OID UJ LL m Attachment 5 Kuparuk River Unit Tabasco Oil Pool 2002 Annual Reservoir Surveillance Report Production Logs and Special Surveys Well Date Type Comments 2T-201 5/6/02 Water Injection Profile 3355'-3400' 93.5% entry 3568'-3599' 6.5% entry Attachment 6 Kuparuk River Unit Tabasco Oil Pool 2002 Annual Reservoir Surveillance Report Wells Allocation and Test Evaluation Summary A minimum of two well tests per month were taken on production wells. Fluid samples were obtained on a regular basis, and water cut corrections were applied to well tests as required based on the subsequent lab analysis. Generally, very good agreement was observed between the phase dynamics and the shakeout analysis. Production volumes were tracked through the Setcim production monitoring system. In 2002, Tabasco switched to floating production allocation factors which were as follows: Tabasco Oil Pool 2002 Production Allocation Factors Oil Gas Water Jan-02 0.9709 1.0000 1.0000 Feb-02 0.9693 0.9643 1.0926 Mar-02 0.9763 0.9651 1.0773 Apr-02 0.9734 0.9645 1.0687 May-02 0.9728 0.9812 1.0716 Jun-02 0.9712 0.9425 1.1051 Jul-02 0.9502 0.9264 1.0770 Aug-02 0.9503 0.9114 0.9937 Sep-02 0.9511 0.9218 0.9834 Oct-02 0.9590 0.9358 0.9807 Nov-02 0.9393 0.9183 0.9523 Dec-02 0.9859 0.9757 1.0010 Attachment 7 Kuparuk River Unit Tabasco Oil Pool 2002 Annual Reservoir Surveillance Report Future Development Plans Tabasco Drill Site 2T development plans for 2003 and beyond were created to take advantage of the gravity -induced water slumping. Horizontal producers are planned near the top of the interval to provide vertical standoff from the water. The first horizontal producer is now scheduled to be drilled in March, 2003. Current plans include drilling a total of three horizontal producers. Injection plans call for increasing injection to accomplish a cumulative net zero voidage and restore original reservoir pressure. Another workover to mitigate mechanical problems at injector 2T-210, which prevent water injection, continues to be considered. Conversion(s) of an existing producer(s) to water injection is planned if horizontal producers can be successfully installed. A full - field reservoir model is currently being used for development planning and flood optimization. Screening evaluations indicate that Tabasco development beyond Drill Site 2T is most prospective at Kuparuk River Unit Drill Sites 3H and 3G. 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Palin, Commissioner Alaska Oil and Gas Conservation Commission 333 West 7t" Ave. Suite # 100 Anchorage, Alaska 99501-3539 James R. Hand Supervisor - Drillsite Petroleum Engineering Greater Kuparuk Area ConocoPhillips Alaska Inc. ATO-1276 PO Box 100360 Anchorage AK 99510-0360 Phone (907)263-4027 Fax: (907)265-6133 Re: 2002 West Sak Oil Pool Annual Reservoir Surveillance Report Dear Ms. Palin, In compliance with Rule 11, Conservation Order No. 406, ConocoPhillips Alaska, Inc., operator of the Kuparuk River Field, is hereby submitting the annual report on the West Sak Oil Pool. This report documents the required information pertinent to the field development and enhanced recovery operations from January through December 2002. 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, Attachment 3). c. Analysis of reservoir pressure surveys taken in 2002 (Attachment 4). d. Results of production surveys, and any special surveys, taken on the West Sak Oil Pool in 2002 (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 call R. Scott Redman at (907) 263-4514, Jordan Wiess at (907) 263-4370, or Bob Christensen at (907) 659-7535 Sincerely, ames R. Hand Supervisor - Drillsite Petroleum Engineering Greater Kuparuk Area Attachment 1 Kuparuk River Unit West Sak Oil Pool 2002 Annual Reservoir Surveillance Report Summary of the Enhanced Recovery Project Development activities in 2002 included drilling one multilateral well and one undulating horizontal well. At the end of 2002, there were 26 water injectors and 24 producers in service in the West Sak Oil Pool. Implementation of the waterflood continued with waterflood response being seen in horizontal and conventional producers. Production details from Drill Sites 1 C/1 D, as of Dec, 2002: Oil production rate = 6825. BOPD Water production rate = 1196. BWPD Gas production rate = 1263. MCFPD Water injection rate = 16523. BWPD Cumulative* oil production 7742. MSTBO Cumulative* water production 1252. MSTBW Cumulative* gas production 2080. MMCF Cumulative* water injection 12212. MBW Cumulative I/W Ratio 1.304 The following wells were drilled in 2002 in the West Sak pool: Name Well Type 1 C-104 Multilateral 1 D-103 Horizontal Target Inj/Prod D/B Sand Producer D/B Sand Injector The 1 D-103 well is a horizontal undulating injector that injects into both the D and B sands. The 1 C-104 well is a multilateral producer, also targeting the D and B sands. k Excludes prior West Sak Pilot production. Gas production not included in calculation. Attachment 2 Kuparuk River Unit West Sak Oil Pool 2002 Annual Reservoir Surveillance Report Produced Fluid Volumes Month Year Oil (STB) Gas (MSCF) Water (BBL) Cum Oil (STB) Cum Gas (MSCF) Cum Water (BBL) 1 2002 194,793 57,112 15,284 5,464,538 1,502,287 798,276 2 2002 176,645 49,265 17,706 5,641,183 1,551,552 815,982 3 2002 202,989 61,953 22,903 5,844,172 1,613,505 838,885 4 2002 216,194 60,724 34,428 6,060,366 1,674,229 873,313 5 2002 234,236 63,086 38,624 6,294,602 1,737,315 911,937 6 2002 214,435 55,950 48,751 6,509,037 1,793,265 960,688 7 2002 198,627 49,931 51,349 6,707,664 1,843,196 1,012,037 8 2002 184,277 44,056 50,340 6,891,941 1,887,252 1,062,377 9 2002 201,538 46,493 55,936 7,093,479 1,933,745 1,118,313 10 2002 248,408 64,831 58,738 7,341,887 1,998,576 1,177,051 11 2002 188,766 44,578 36,246 7,530,653 2,043,154 1,213,297 12 2002 211,590 37,084 39,173 7,742,243 2,080,238 1,252,470 2002 Total 2,472,498 635,063 469,478 Cumulatives as of Dec 31, 2001 5,269,745 1,445,175 782,992 Attachment 3 Kuparuk River Unit West Sak Oil Pool 2002 Annual Reservoir Surveillance Report Injected Fluid Volumes Month Year Gas MI Water* (MSCF) (MSCF) (BBL) Cum Gas Cum MI Cum Water (MSCF) (MSCF) (BBL) 1 2002 - - 418,305 - - 7,585,409 2 2002 - - 287,641 - - 7,873,050 3 2002 - - 325,949 - - 8,198,999 4 2002 - - 382,772 - - 8,581,771 5 2002 - - 481,949 - - 9,063,720 6 2002 - - 268,599 - - 9,332,319 7 2002 - - 338,544 - - 9,670,863 8 2002 - - 477,463 - - 10,148,326 9 2002 - - 525,977 - - 10,674,303 10 2002 - - 544,822 - - 11,219,125 11 2002 - - 480,757 - - 11,699,882 12 2002 - - 512,212 - - 12,212,094 2002 Total 5,044,990 * Excludes pre -development injection Cumulatives as of Dec 31, 2001 0 0 7,167,104 Attachment 4 Kuparuk River Unit West Sak Oil Pool 2002 Annual Reservoir Surveillance Report Reservoir Pressure Surveys Rule 8 Format Follows for 1st, 2nd, 3rd, and 4t" Quarters N 010 O) 0 0 0 m O M 0 c0 M V m m N oo r Ln 0 c0 O co O cD o0 cD Lb O N M M o E y- cD N o o" CD M N r� o] 0 ap y r'Zr o 0 r r r N N N N N N r N r r r r r N r NN N � a c m C7 � U a R O C O E > ttl > D U 3 E > s o > J (7 U O D_ E N Q � J O 0 0 In O O O O O O oo O O O N R O Q) N O m ~ ro D 0 0 c0 V In O c0 M m O Ln N O V M V p N V V O O NLnv'It r V V V Lo N c0 c0 O n N ti 3 N 0 O` N a0i d m 1 o' 0 o o (nD o 0 0 0 0 o Lo o n o o moo v d \ w Q ti p MN N r r r r o E a' o O a m o rn � N m Z y rn Y Q O LD r Lo o In O N o^ m co N� O O(p o� N o. LL n d 11) O' O O N W c00 N (D 0 aMD 'R 7� M Or m M M a 0 O a d 2 E U N C N Q O Ln m m Lo o Ln Lo Lo m Ln (D (D O CO o r r m Lo In m Lo O o 0 0 o r D R m H r O W N r r Q o oo N LL LL °°00�oo0oaoCD L O 'tco °no o M N p (o m t Ln Lo v Lo v (D v .Z n � Y r p) 0 N t Lo r Lo O Lo'It o) M N V N N V w Ln V cD in 7 0 m o N 7 co 0 0 0) Ln jy L 7 r N 0 N O (0 r T r r N R -,I-r N M (near d o w` LL S E000r m o m o m ma �cco,)�co E E. ^ N rru^i N r N .0 a~ m O) N M N Q LL N a IT � p N N N N N N N N N N N N N N N N N N N O o 0 0 09 09 0 0 0 0 0 0 0 0 0 0 0 LU y 3 M I- r O N n m N N r N m m N m c0 Lo o o r r N M N N N? r o r o o N r O N N y H w m m Lo Ln Ln m Ln N m N r N N Nv m N N O o 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 o 0 �.Q E Y o (7 y CT 0 3 0 0 0 0§ 0 0 0§ 0 0 H O O O O O O O O O O r O r O 0 0 0 0 0 0 O O o 0 0 0 0 0 o 0 0 0 0 0 0 0 0 0 0 U E Z5 a cc c0 I- m'T Lo V M 0 M N O r '7 c0 O Ln c0 N N� N M N 7 N N O V M 0 coo00ooco)mooRmo)mm-00000 E Z M M M M M M M M N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N 0) 0) 0) m 0) 0) 0) 0 0 0) 0) 0) O 0) 0) 0) 0) 0) 0) N j N N N N N N N N N N N N N N N N N N N 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 .0 o 0 0 0 0 0 o 0 0 0 o 0 o 0 0 0 0 0 0 Lo Lo Lo Lo Lo M Lo In Ln to Lo Lo to Lo Lo Lo Lo Lo Lo p) �� OOOO�OOUO'o > + + + + + + + + . . + + + 0 0 0 0 0 m m m m m m m m m m m m m N 2 + + + + + + + + + + + + + + + + + + m m m m m a a a a 0 a a a a a a a¢ a O O c EY M N � Z N l p N _a - - O Q E a Q p J ltl Z V V 0) r Q) Lo M Ln O O O r r N N M O 0 0 r r r r d p z a D Attachment 5 Kuparuk River Unit West Sak Oil Pool 2002 Annual Reservoir Surveillance Report Production Logs and Special Surveys O O '[t Co N LO M O N O O (0 O O 't O O O N CO 00 O rl- O T O O ZO N r O 't 0')N CO (O (D N H \ U Ca U a z � � H z o z Z U m ++ m m¢ m m¢ m m¢ m m¢ m¢ o w m + + + + + N F z H ¢ ¢ ¢ ¢ ¢ z 0 H N Q N N N N a w m w m m m m 0 U a' LL LL LL LL LL w O O O O Q O w o w x o H a co _ (6 (U _ (6 _ f0 0 _ co 0 0 0 a s c c c c LL c F o x H a a F q E F-i Qx o 44 H w\ m m m m m m w O 9 r w LLI LU W LLl w w H W H fk o U E" H> w a Z Z Z Z Z Z Z Z Z Z Z Z x a F h 9 a U a a. EL EL � � z a z �zj Q a U) cn cn cn (n cn FC .D x H W ] 4 co ro x U N w \ G w} N O N O N O N O N O N O r OW a O N 00 O O p; CHT+ r r m o a> cfl r; r- Q w O O O O O z 0 o H H H W O O O O O O F H Q H O r r r O O O O O O O �t Ln Cl) Cl) N x O O O O O O N N Cl) N N Cl) O m O 0) O O <c z Ln 0 0 0 0 0 0 a w a7 O N LO CMM M co w r r r r r r p z U 0 0 U U 0 O Ln O O O O O N It O LO 00 O r Cfl O Cfl N O O O Ln �t O Ln O I- O Cfl � O Ln It Ln ZO Ln r Ln r N r m 0 Ln N ` N r O t H ] F w v a v w m z � � H z v o z 2 U m m Q m m Q m m Q m m Q m m Q m m Q O K� w + + + + + + V F z Q Q Q Q Q Q H z 0 H (1) v v (1) v v a w rn o a H 3 _H co co cn m cn cn 0 v a o CL 0- a a a a W� 0 a 0 0 0 0 0 0 w w H FC a O O O O O O a G4 a w a LL LL LL LL LL LL 0 a H C4 H a LL H H rx 0 a H a OC m m CE OC m w O > w r w > a> LU LiJ L1J LU LL LU w z H El Z Z Z Z Z Z x> 0 u � w 0z Z Z Z Z Z Z x a h h zF, a m a d Ca a CO Cn Cl) Cl) Cn CO FC a H .D < U N x a z z o x v w N w 0 O O 0 0 0 a ] 0 H 4 N 0o C� 4 4 a E n N O r r N O o Cn 0 C 0 0 0 Q w 0 14 H rn 0)o O H Q 0 0 w H ON O N Cl) O O El rUj Q H O O O O O O O O O O O O O O O O O Ch OD 4 O 66 co O O O Ln Ln NC\j NC\j N W NC\l NC\j NC\j K4 z Ln 0 0 0 0 0 0 x Q a w a C O - Ln N 00 N Lo m r` C`) w r r r r r r a z 0 0 0 0 Attachment 5 Kuparuk River Unit West Sak Oil Pool 2002 Annual Reservoir Surveillance Report Production Logs and Special Surveys Geochemical Production Splits: Well Name Date Split Gas Split Water Split Oil Split Layer Name 1 C-102 10-02-02 64% 64% 64% D 1 C-102 10-02-02 36% 36% 36% B 1 C-102 10-02-02 0% 0% 0% A 1 C-104 08-19-02 0% 0% 0% D 1 C-104 08-19-02 100% 100% 100% B 1 C-104 08-19-02 0% 0% 0% A 1 C-104 10-02-02 50% 50% 50% D 1 C-104 10-02-02 50% 50% 50% B 1 C-104 10-02-02 0% 0% 0% A 1 C-104L1 08-19-02 100% 100% 100% D 1 C-104L1 08-19-02 0% 0% 0% B 1 C-104L1 08-19-02 0% 0% 0% A 1 C-119 04-15-02 50% 50% 50% D 1 C-119 04-15-02 50% 50% 50% B 1 C-119 04-15-02 0% 0% 0% A 1 C-119 09-05-02 77% 77% 77% D 1 C-119 09-05-02 23% 23% 23% B 1 C-119 09-05-02 0% 0% 0% A 1 C-121 01-20-02 16% 16% 16% D 1 C-121 01-20-02 48% 48% 48% B 1 C-121 01-20-02 36% 36% 36% A 1 C-123 10-02-02 21 % 21 % 21 % D 1 C-123 10-02-02 52% 52% 52% B 1 C-123 10-02-02 27% 27% 27% A 1 C-125 09-11-02 53% 53% 53% D 1 C-125 09-11-02 16% 16% 16% B 1 C-125 09-11-02 31 % 31 % 31 % A 1 C-131 06-18-02 88% 88% 88% D 1 C-131 06-18-02 12% 12% 12% B 1 C-131 06-18-02 0% 0% 0% A 1 C-131 07-08-02 74% 74% 74% D 1 C-131 07-08-02 26% 26% 26% B 1 C-131 07-08-02 0% 0% 0% A 1 C-133 07-05-02 66% 66% 66% D 1 C-133 07-05-02 34% 34% 34% B 1 C-133 07-05-02 0% 0% 0% A 1 C-135 05-09-02 100% 100% 100% D 1 C-135 05-09-02 0% 0% 0% B 1 C-135 05-09-02 0% 0% 0% A Geochemical Production Splits: Well Name Date Split Gas Split Water Split Oil Split Layer Name 1 C-135 10-02-02 95% 95% 95% D 1 C-135 10-02-02 4% 4% 4% B 1 C-135 10-02-02 1% 1% 1% A 1 D-102 10-02-02 19% 19% 19% D 1 D-102 10-02-02 81 % 81 % 81 % B 1 D-102 10-02-02 0% 0% 0% A 1 D-105 02-16-02 100% 100% 100% D 1 D-105 02-16-02 0% 0% 0% B 1 D-105 02-16-02 0% 0% 0% A 1 D-105 04-14-02 100% 100% 100% D 1 D-105 04-14-02 0% 0% 0% B 1 D-105 04-14-02 0% 0% 0% A 1 D-107 09-24-02 61 % 61 % 61 % D 1 D-107 09-24-02 39% 39% 39% B 1 D-107 09-24-02 0% 0% 0% A 1 D-108 04-14-02 24% 24% 24% D 1 D-108 04-14-02 38% 38% 38% B 1 D-108 04-14-02 38% 38% 38% A 1 D-108 10-02-02 42% 42% 42% D 1 D-108 10-02-02 45% 45% 45% B 1 D-108 10-02-02 13% 13% 13% A 1 D-110 10-02-02 46% 46% 46% D 1 D-110 10-02-02 30% 30% 30% B 1 D-110 10-02-02 24% 24% 24% A 1 D-110A 02-17-02 32% 32% 32% D 1 D-110A 02-17-02 58% 58% 58% B 1 D-110A 02-17-02 10% 10% 10% A 1 D-110A 04-14-02 27% 27% 27% D 1 D-110A 04-14-02 52% 52% 52% B 1 D-110A 04-14-02 21 % 21 % 21 % A 1 D-112 04-14-02 19% 19% 19% D 1 D-112 04-14-02 55% 55% 55% B 1 D-112 04-14-02 26% 26% 26% A 1 D-112 10-02-02 20% 20% 20% D 1 D-112 10-02-02 57% 57% 57% B 1 D-112 10-02-02 23% 23% 23% A 1 D-113 04-14-02 32% 32% 32% D 1 D-113 04-14-02 13% 13% 13% B 1 D-113 04-14-02 55% 55% 55% A 1 D-113 10-02-02 44% 44% 44% D 1 D-113 10-02-02 16% 16% 16% B 1 D-113 10-02-02 40% 40% 40% A 1 D-115 04-12-02 15% 15% 15% D 1 D-115 04-12-02 26% 26% 26% B 1 D-115 04-12-02 59% 59% 59% A 1 D-115 10-02-02 10% 10% 10% D 1 D-115 10-02-02 35% 35% 35% B 1 D-115 10-02-02 55% 55% 55% A Geochemical Production Splits: Well Name Date Split Gas Split Water Split Oil Split Layer Name 1 D-116 04-12-02 15% 15% 15% D 1 D-116 04-12-02 36% 36% 36% B 1 D-116 04-12-02 49% 49% 49% A 1 D-116 10-02-02 32% 32% 32% D 1 D-116 10-02-02 30% 30% 30% B 1 D-116 10-02-02 38% 38% 38% A 1 D-117 04-12-02 98% 98% 98% D 1 D-117 04-12-02 2% 2% 2% B 1 D-117 04-12-02 0% 0% 0% A 1 D-118 01-12-02 31 % 31 % 31 % D 1 D-118 01-12-02 19% 19% 19% B 1 D-118 01-12-02 r 50% 50% 50% A 1 D-118 04-12-02 34% 34% 34% D 1 D-118 04-12-02 3% 3% 3% B 1 D-118 04-12-02 63% 63% 63% A 1 D-118 10-02-02 23% 23% 23% D 1 D-118 10-02-02 2% 2% 2% B 1 D-118 10-02-02 75% 75% 75% A 1 D-121 04-12-02 34% 34% 34% D 1 D-121 04-12-02 33% 33% 33% B 1 D-121 04-12-02 33% 33% 33% A 1 D-122 07-17-02 22% 22% 22% D 1 D-122 07-17-02 41 % 41 % 41 % B 1 D-122 07-17-02 37% 37% 37% A 1 D-123 03-05-02 0% 0% 0% D 1 D-123 03-05-02 7% 7% 7% B 1 D-123 03-05-02 93% 93% 93% A 1 D-123 04-12-02 0% 0% 0% D 1 D-123 04-12-02 46% 46% 46% B 1 D-123 04-12-02 54% 54% 54% A 1 D-123 10-02-02 8% 8% 8% D 1 D-123 10-02-02 46% 46% 46% B 1 D-123 10-02-02 46% 46% 46% A 1 D-124 04-12-02 11 % 11 % 11 % D 1 D-124 04-12-02 44% 44% 44% B 1 D-124 04-12-02 45% 45% 45% A 1 D-124 10-02-02 5% 5% 5% D 1 D-124 10-02-02 51 % 51 % 51 % B 1 D-124 10-02-02 44% 44% 44% A 1 D-126 10-02-02 3% 3% 3% D 1 D-126 ...:...... 10-02-02 50% 50% 50% B 1 D-126 10-02-02 47% 47% 47% A 1 D-128 05-12-02 31 % 31 % 31 % D 1 D-128 05-12-02 41 % 41 % 41 % B 1 D-128 05-12-02 28% 28% 28% A 1 D-129 03-05-02 4% 4% 4% D 1 D-129 03-05-02 47% 47% 47% B 1 D-129 03-05-02 49% 49% 49% A Geochemical Production Splits: Well Name Date Split Gas Split Water Split Oil Split Layer Name 1 D-129 04-10-02 5% 5% 5% D 1 D-129 04-10-02 49% 49% 49% B 1 D-129 04-10-02 46% 46% 46% A 1 D-129 05-03-02 2% 2% 2% D 1 D-129 05-03-02 36% 36% 36% B 1 D-129 05-03-02 62% 62% 62% A 1 D-129 10-02-02 3% 3% 3% D 1 D-129 10-02-02 53% 53% 53% B 1 D-129 10-02-02 44% 44% 44% A 1 D-131 03-05-02 1% 1% 1% D 1 D-131 03-05-02 36% 36% 36% B 1 D-131 03-05-02 63% 63% 63% A 1 D-131 04-10-02 7% 7% 7% D 1 D-131 04-10-02 48% 48% 48% B 1 D-131 04-10-02 45% 45% 45% A 1 D-131 10-02-02 7% 7% 7% D 1 D-131 10-02-02 49% 49% 49% B 1 D-131 10-02-02 44% 44% 44% A 1 D-133 05-03-02 10% 10% 10% D 1 D-133 05-03-02 24% 24% 24% B 1 D-133 05-03-02 66% 66% 66% A 1 D-133 10-02-02 16% 16% 16% D 1 D-133 10-02-02 36% 36% 36% B 1 D-133 10-02-02 48% 48% 48% A 1 D-134 04-10-02 8% 8% 8% D 1 D-134 04-10-02 41 % 41 % 41 % B 1 D-134 04-10-02 51 % 51 % 51 % A 1 D-134 05-03-02 7% 7% 7% D 1 D-134 05-03-02 38% 38% 38% B 1 D-134 05-03-02 55% 55% 55% A 1 D-135 04-10-02 71 % 71 % 71 % D 1 D-135 04-10-02 24% 24% 24% B 1 D-135 04-10-02 5% 5% 5% A 1 D-135 10-02-02 62% 62% 62% D 1 D-135 10-02-02 33% 33% 33% B 1 D-135 10-02-02 5% 5% 5% A 1 D-136 09-24-02 38% 38% 38% D 1 D-136 09-24-02 43% 43% 43% B 1 D-136 09-24-02 19% 19% 19% A 1 D-137 01-04-02 5% 5% 5% D 1 D-137 01-04-02 71 % 71 % 71 % B 1 D-137 01-04-02 24% 24% 24% A 1 D-140 10-02-02 33% 33% 33% D 1 D-140 10-02-02 67% 67% 67% B 1 D-140 10-02-02 0% 0% 0% A 1 D-141 03-14-02 0% 0% 0% D 1 D-141 03-14-02 5% 5% 5% B 1 D-141 03-14-02 95% 95% 95% A Geochemical Production Splits: Well Name Date Split Gas Split Water Split Oil Split Layer Name 1 D-141 04-10-02 0% 0% 0% D 1 D-141 04-10-02 21 % 21 % 21 % B 1 D-141 04-10-02 79% 79% 79% A 1 D-141 10-02-02 85% 85% 85% D 1 D-141 10-02-02 14% 14% 14% B 1 D-141 10-02-02 1 % 1 % 1% A Attachment 6 Kuparuk River Unit West Sak Oil Pool 2002 Annual Reservoir Surveillance Report Wells Allocation and Test Evaluation Summary The West Sak production process monitoring and reporting system functioned as expected in 2002. In 2002, the new "Floating Allocation Factor" methodology was applied to production, with the monthly 2002 allocation factors shown below. Additional metering work is planned in the coming year: • A accuflow modifications are anticipated in 2003. The restrictive orifice installed in 1999 enables the separator to tolerate gas production surges better, but may not be optimally sized. In addition, the 6" gas meter will be replaced with a 4" meter in an effort to better measure more moderate gas flow rates that are below the threshold of the 6" meter. • In 2003, a multiphase meter test will be conducted at IDS 1 C, with multiphase meter volumes compared to those of the existing Accuflow. Should the test prove successful, permanent installation of a multiphase meter at IDS 1 D may be pursued. 2002 allocation factors: Oil Gas Water Jan-02 0.9709 1.0000 1.0000 Feb-02 0.9693 0.9637 1.0931 Mar-02 0.9756 0.9645 1.0773 Apr-02 0.9731 0.9647 1.0703 May-02 0.9727 0.9812 1.0716 Jun-02 0.9713 0.9423 1.1051 Jul-02 0.9500 0.9264 1.0771 Aug-02 0.9503 0.9114 0.9936 Sep-02 0.9511 0.9217 0.9834 Oct-02 0.9589 0.9356 0.9807 Nov-02 0.9565 0.9827 1.0099 Dec-02 0.9859 0.9758 1.0010 Attachment 7 Kuparuk River Unit West Sak Oil Pool 2002 Annual Reservoir Surveillance Report Future Development Plans • 1 C/1 D DEVELOPMENT DRILLING Development drilling planned for the 1 C/1 D pad area for 2003 includes four wells, which are summarized below: Name Well Type 1 C-190 Horizontal 1 C-174 Horizontal 1 C-178 Multilateral 1 C-172 Horizontal Target Inj/Prod D Only Injector D/B Sand Injector D/B Sand Producer A Sand Producer Two to six additional wells in the 1 C/1 D pad area are possible in 2003. • 1J PAD DEVELOPMENT Working to progress development plan on 1J Pad Development. If this project is approved by the Working Interest Owners in 4th quarter 2003, then development drilling would begin 1st quarter 2004. Delineation wells are being evaluated to test the southern limits of the West Sak reservoir south of 1 J Pad. Several wells are possible in the 1st quarter of 2004. These wells would either be drilled off of ice pads or from the 1 J Pad. • WEST SAK FOR PILOT PROJECT PLANS An enriched hydrocarbon miscible gas FOR pilot is planned for DS-1 C. The enriched hydrocarbon miscible gas for this project will come from the existing Kuparuk River Unit ("KRU") enriched hydrocarbon miscible gas supply. Startup is planned for 3rd quarter 2003. Facility modifications have been installed on DS-1 C to include the West Sak wells slated for such service.