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Home My WebLink About2001 West Sak Oil PoolPHI PHILLIPS Alaska, Inc. A Subsidiary of PHILLIPS PETROLEUM COMPANY P.O. BOX 100360 ANCHORAGE, ALASKA 99510-0360 April 1, 2002 Ms. Camille Oechsli Taylor, Commissioner Alaska Oil and Gas Conservation Commission 333 West 7th Ave. Suite #100 Anchorage, Alaska 99501-3539 Stephen V. Bross Supervisor Greater Kuparuk Area Satellite Development ATO - 1126 Phone 265-6083 Fax 265-6133 Re: 2001 West Sak Oil Pool Annual Reservoir Surveillance Report Dear Ms. Oechsli Taylor: RECEIVED APR 12002 In compliance with Rule 11, Conservation Order No. 406, Phillips 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 2001. 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 2001 (Attachment 4). d. Results of production surveys, and any special surveys, taken on the West Sak Oil Pool in 2001 (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 Mavriky Kalugin at (907) 263- 4440, Jordan Wiess at (907) 263-4370, or Bob Christensen at (907) 659-7535 Sincerely, Stephen Bross GKA Satellite Development Supervisor bcc: Central Files ATO — 320 Dan Kruse ATO — 1220 Jordan Wiess ATO — 1156 Mavriky Kalugin ATO — 1158 Bob Christensen NSK — 69 Jason Brink/Ryan Dunn NSK — 69 Jeff Spencer NSK — 69 Mark Stevenson ATO — 1232 Mavriky Kalugin Page 2 4/1/2002 Attachment 1 Kuparuk River Unit West Sak Oil Pool 2001 Annual Reservoir Surveillance Report Summary of the Enhanced Recovery Project Development activities in 2001 focused on West Sak Drill Site DS-1 C. The drilling program consisted of six conventional injectors, three dual-purpose injector/producers, two D-sand only horizontal producers, and two B/D -sand horizontal multi -lateral producers. The multi -lateral wells are conceptually identical to the three multi -laterals that were drilled and completed on DS-1 D in 2000, with the exception that all can be characterized as more difficult due to longer departures, complex trajectories, and increased horizontal section distances. Implementation of the waterflood continued at 1 D and 1 C with producer response noted in the multi -lateral and conventional producers. Allocated production details from West Sak's DS-1 D & 1 C, as of Feb 28, 2002: Oil production rate = 6,309. BOPD Water production rate = 632. BWPD Gas production rate = 1,759. MCFPD Water injection rate = 10,273. BWPD Cumulative production volumes as of December, 31, 2001: Cumulative'.' oil production 5,269. MSTBO Cumulative* water production 781. MSTBW Cumulative* gas production 1,422. MMCF Cumulative* water injection 7,167. MBW Cumulative I/W Ratio 1.184 The average rate from West Sak producers is 275 BOPD including the new multi -laterals (ML) in DS-1 C. Presently, the highest production rate of 1,055 BOPD and 2% watercut is from the 1 D-140 ML, which has a -4,000 foot horizontal lateral in each D & B-sand. The poorest production performance comes from an ESPCP producer, 1 D-117, which produces 107 BOPD and 51 BWPD (see Table 1 and Table 2 for production details). The multi -laterals at DS-1 C are longer than those at DS-1 D, but they currently lack injection support. Increased injection rates are pending completion of the DS-1 C multi -lateral drilling program planned for the 2"d quarter of 2002. Once Excludes prior West Sak Pilot production. Gas production not included in calculation. Page 3 4/1/2002 all of the injectors are online, the production rates from the newest multi -laterals should surpass those at DS-1 D. A number of wells are showing a waterflood response at DS-1 D. This is especially evident in the suppression of the producing GORs and increasing watercuts in a few producers. Throughout the year 2001, the cumulative West Sak watercut has been increasing slightly, from 8.4% to a high of 11.3%, but ended the year at 7.4%. The main reason for the decrease can be attributed to the 1 C multi -laterals coming online and the sidetrack of the most prolific water producer, 1 D-105. Details of the key accomplishments related to the West Sak Pool in 2001 are outlined below: 1) Phase 3 Development Wells @ DS-1 C: 2 multi -lateral horizontal producers. 1 C-102 was completed with 3,907 ft of D-sand and 3,919 ft of B-sand behind sand control screens. The 1 C-109 utilized lower cost slotted liners and was completed with 2,859 ft of D-sand and 2,484 ft of B-sand in the horizontal sections. 2) Phase 3 Development Wells @ DS-1 C: 3 dual-purpose injector/producer wellbores. To capture the A -sand reserves, dual-purpose completions were planned in addition to conventional West Sak injectors. Waterflood injection into the D & B-sands would occur as the A sand is produced from the pattern. It was hoped that this would provide for economic development of the A -sand. The key to the cost effectiveness of the completion was the ability to stimulate the A -sand interval (+100') with a single stage fracture treatment vs. the 2-3 treatments previously required. To mitigate the risk associated with the implementation of this "new" technology on the slope, three of the planned nine dual-purpose completions were drilled early in the program. Only one was completed and tested as a dual well (1 C-123). Multiple aggressive attempts we made at fracturing the A sand in a single stage, but test results indicate that height growth did not occur. The Fracture Height Growth Test on the 1 C-123 confirmed that fractures do not break through the relatively thin shales/mudstones between the West Sak A -sandstone intervals, even at aggressive pumping rates of 40 bpm and the use of 50# cross -linked gel. Results from the test suggest that the dual-purpose completion is not economic, mainly due to incremental costs associated with numerous stimulations that are required to adequately stimulate all of the A -sands to provide an economic production Page 4 4/1/2002 rate. The remaining two dual-purpose wells will be completed as injectors in 2002. Alternate A -sand development strategies are reviewed in Attachment 7. 3) Phase 3 Development Wells @ DS-1 C: 6 vertical injectors. 4) The vertical producer 1 D-105 was successfully sidetracked and completed as 1 D-105A, becoming the first D-sand only (4243' of net pay exposed) horizontal producer in West Sak. The preliminary production results suggest that single D-sand horizontals may be a viable and economic development method in the Eastern periphery of DS-1 C & 1 D, where the B-sand is known to be wet. 5) 1 C-135 was drilled and completed in December 2001 as a grassroots D-sand horizontal producer (4417'). This wellbore was completed with a slotted liner. Completion integrity testing will be performed on this well to determine if a sand control completion is an absolute requirement once water and possible future miscible gas flood break through occurs. 6) A rig workover on the 1 D-141 multi -lateral was completed in an attempt to isolate formation water production from the lower lateral associated with a wet B-sand interval. The workover was unsuccessful and the well has been returned to production, but continues to produce water. 7) Gathered quarterly oil samples for geochemical analysis and used the results in allocating production from the D, B, and A - sands. 8) Completed a round of West Sak injection profiles on DS-1 D. 9) Waterflood break through is evident, by GOR suppression and/or watercut increase, in the 1 D-102 multi -lateral and several other vertical completions. 10)Completed injection step rate testing of each injector to help understand the fracture gradient and optimize the waterflood, especially in the vicinity of the high rate multi -lateral producers. 11)Successfully installed two of the world's first Through Tubing Conveyed Electric Submersible Centrifugal Pumps (TTC-ESP) in 1 C-102 and 1 C-109. 12)Completed several pump replacements and fill clean -outs, either due to declining pump efficiencies, pump failures, or fill accumulation. Page 5 4/1n002 Table 1: Producer Summary for all West Salk Completions at Drillsites 1 D FSC - Frac for Sand Control using PropLoc FSC / GP - Failed Initial Completion w/ Remedial Gravel Pack F&P - Frac and Pack using Carbolite®Tm Frac with Screen PN/GP - PropNet Frac with Gravel Pack Screen FTP - Frac then Pack MUPPS - Multi -lateral with pre -packed screens MUBS - Multi -lateral with Baker Excluder ® Screens MUS - Multi -lateral with slotted liner DP - Dual -Purpose wellbore, with gravel pack SH/BS - Single horizontal with Baker Excluder® Screens SH/S - Single horizontal with slotted liner Well # Completion Type Production Rates Oil Water GOR Comments 1 D-102 MUPPS Offline Offline Offline D&B Horizontal Multilateral ofline, Pump failure. Temporary gas lift. Need pressure support. High GOR, I" 1 D-105A SH/BS 293 2 870 single D-sand horizontal 1 D-108 FSC/GP 159 13 163 1 D-110A FTP 407 18 181 ESP failed, temporarily on gas lift. 1 D-112 FSC/GP 220 16 148 1 D-113 FSC/GP 195 21 166 Successful dilute HF acid wash. 1 D-115 FSC/GP 262 19 191 1 D-116 PN/GP 444 23 185 New pump installed in March 2002. 1 D-117 FSC/GP 107 51 131 1 D-118 F&P 117 13 228 B & D Sand isolated w/ WO. A -sand production only. 1 D-121 FSC 260 79 157 1 D-123 PN/GP 306 5 208 1 D-124 F&P 281 23 189 1 D-126 FSC 244 23 201 1 D-127 FSC Offline Offline Offline Awaiting pump change out. 1 D-129 FSC/GP 371 12 140 1 D-131 FSC 163 57 137 1 D-133 F&P 347 46 110 1 D-134 FSC 219 25 162 1 D-135 F&P 163 103 97 Still flowing back acid from HCl wash. Ramping up. 1 D-140 MUPPS 1055 24 181 D&B Horizontal Multilateral online in Nov-2000. Unsuccessful Workover attempted. 1 D-141 MUPPS 166 144 74 Page 6 4/1/2002 Table 2: Producer Summary for all West Salk Completions at Drillsites 1 C FSC - Frac for Sand Control using PropLoc FSC / GP - Failed Initial Completion w/ Remedial Gravel Pack F&P - Frac and Pack using Carbolite®Tm Frac with Screen PN/GP - PropNet Frac with Gravel Pack Screen FTP - Frac then Pack MUPPS - Multi -lateral with pre -packed screens MUBS - Multi -lateral with Baker Excluder ® Screens MUS - Multi -lateral with slotted liner DP - Dual -Purpose wellbore, with gravel pack SH/BS - Single horizontal with Baker Excluder® Screens SH/S - Single horizontal with slotted liner Production Rates Well # :ompletion Oil Water d0R Comments Type 1 C-102 MUBS 600 10 899 2001 Well. Injection support ramping. 1 C-123L DP 181 24 69 2001 Well. A sand only production 1 C-109 MUS 461 25 1155 2001 Well. Injection support ramping. 1 C-135 SH/S Offline Off line ffline Pending facility hook-up. Page 7 4/1/2002 Attachment 2 Kuparuk River Unit West Sak Oil Pool 2001 Annual Reservoir Surveillance Report Produced Fluid Volumes MO YR OIL STB GAS MSCF WATER BBL CUM OIL STB CUM GAS MSCF CUM WATER BBL 1 2001 173,899 53,375 15,928 3,445,034 1,044,730 587,097 2 2001 152,847 42,651 13,979 3,597,881 1,087,381 601,076 3 2001 177,492 40,806 19,466 3,775,373 1,128,187 620,542 4 2001 162,112 34,496 14,900 3,937,485 1,162,683 635,442 5 2001 178,347 37,384 17,602 4,115,832 1,200,067 653,044 6 2001 172,572 33,066 18,837 4,288,404 1,233,133 671,881 7 2001 175,203 33,414 20,128 4,463,607 1,266,547 692,009 8 2001 171,576 33,394 19,888 4,635,183 1,299,941 711,897 9 2001 155,063 29,344 19,300 4,790,246 1,329,285 731,197 10 2001 132,444 25,075 15,796 4,922,690 1,354,360 746,993 11 2001 135,958 24,175 17,369 5,058,648 1,378,535 764,362 12 2001 210,474 43,130 16,913 5,269,122 1,421,665 781,275 2001 TOTAL 1,997,987 210,106 430,310 Year 2000 Cumulative Production: 3,271,135 991,355 571,169 Page 8 4/1/2002 Attachment 3 Kuparuk River Unit West Sak Oil Pool 2001 Annual Reservoir Surveillance Report Injected Fluid Volumes MO YR WATER GAS NGLS STB MSCF MSCF CUM WATER* CUM GAS CUM NGLS STB MSCF MSCF 1 2001 253,459 4,322,150 2 2001 239,212 4,561,362 3 2001 278,951 4,840,313 - 4 2001 265,049 - 5,105,362 - 5 2001 216,923 - 5,322,285 - 6 2001 237,893 - - 5,560,178 - - 7 2001 247,825 - - 5,808,003 8 2001 249,646 - - 6,057,649 - 9 2001 257,956 - - 6,315,605 - - 10 2001 254,528 - - 6,570,133 - 11 2001 247,947 - - 6,818,080 - - 12 2001 349,024 - - 7,167,104 - - 2001 TOTAL 3,098,413 * Excludes pre -development injection Year 2000 Cumulative Injection: 4,068,691 0 0 Page 9 4/1/2002 Attachment 4 Kuparuk River Unit West Sak Oil Pool 2001 Annual Reservoir Surveillance Report Reservoir Pressure Surveys Rule 8 Format Follows for 1 st 2nd, 3rd, and 41h Quarters STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION ANNUAL RESERVOIR PRESSURE REPORT - 2001 Name of0perator Address Phillips Alaska Inc. P 0 Box 100360, Anchorage, AK 99510-0360 Unit or Lease Name Field and Pool Kuparuk River Field Datum Reference Oil Gravity Gas Gravity Kuparuk River Unit West Sak Oil Pool -3500' SS 1.06 0.57 Final Pressure Test Data Production and Test Data Tool Final Production Rates VVI. of Wt of Pressure API 0.0 Shut-in Number or Date Shut-in Tubing Depth B H Observed (BblslDay) (Mcfd) Liquid Liquid Gas Casing at Oil Water Gas Wall Name Sand WI Tested Time Press. tv1D Temp. Pressure Gradient Column Column Press. Daturn 1 C-102 8.D 500292303700 0 10124101 99999 0 5785 70 1593 0 0 0 1565 1 C-109 B+D 500292304700 0 12102/01 9999 1 5878 70 1592 0 0 0 1514 10-111 B+D 500292302900 0 08/26101 9999 7 6340 75 1560 0 0 0 1491 1 C-121 A+B+D 500292301500 0 11105101 9999 3 6690 80 1777 0 0 0 1591 1 C-125 A+B+D 500292304400 0 12128f01 9999 3 6900 75 1705 0 0 0 16622 1C-131 B+D 500292304100 0 12M 5f01 99999 3 5250 76 1628 0 0 0 1542 1D-101 A«B.D 500292298600 WI 01123f01 99999 15 5800 77 1773 0 0 0 1613 1D-107 A+B+D 500292298300 WI 0112XI31 9999 9999 6000 75 1662 0 0 0 15'2 1D-113 A+B+D 500292291700 0 03A 10'1 2208 210 6090 66 1505 181 12 =i2 1682 1D-140 B+D 500292297400 0 11it3f01 930 200 3502 70 1193 0 0 0 1262 1 hereby certify that the foregoing is true and correct to the best of my knowledge. Signed Title 00 Satellites Supervisor Date Form 1 D-412 Submit in Duplicate Rev 7 1 80 Page 10 4/1/2002 Attachment 5 Kuparuk River Unit West Sak Oil Pool 2001 Annual Reservoir Surveillance Report Production Logs and Special Surveys Geochemical Production Splits: 02/10/01 02/28/01 03/09/01 06/10/01 06/10/01 0&20/01 09/01/01 09/08/01 09/09/01 09/11/01 09/14/01 09/17/01 12/20/01 Well Interval % % % % % % % % % % % % % 10-102 A 0 3 5 2 B 62 75 76 71 D 38 22 19 27 1D-108 A 37 25 22 48 B 49 48 36 26 D 14 27 43 26 1D-110 A 43 27 B 37 33 0 20 40 1D-112 A 25 19 21 29 B 64 42 46 44 D 12 38 33 27 1D-113 A 41 38 44 B 23 25 22 D 36 37 34 1D-115 A 38 47 43 57 B 42 35 35 29 D 20 19 22 14 1D-116 A 45 41 43 42 B 40 59 44 46 D 15 0 13 12 1D-117 A 2 3 0 -3 B 4 21 4 8 D 95 77 96 95 1D-118 A 95 70 70 64 B -1 2 0 11 D 7 28 30 2 1D-121 A 45 37 20 37 B 25 37 29 21 D 31 27 51 42 1D-123 A 58 60 55 9 B 42 35 44 7 0 -1 5 10-124 A 50 51 32 41 B 36 45 44 47 D 14 3 23 12 1D-126 A 59 55 57 7 B 42 43 42 21 D 0 2 1 5 11D-127 A 49 66 58 57 B 31 25 27 23 D 20 9 15 21 1 D-1 9 A 48 59 49 49 B 45 38 45 47 D 7 3 6 4 1D-131 A 50 58 48 62 B 46 43 52 36 D 4 -1 0 1 1D-133 A. 66 71 50 37 B 18 23 38 54 0 16 7 11 1D-134 A 60 61 56 67 B 22 33 32 12 D 19 7 12 21 1D-135 A 14 0 0 B 26 37 23 D 60 62 77 10-140 A 7 1 0 1 B 56 78 65 62 D 37 21 36 37 10-105 A 9 2 0 9 B 8 2 6 12 D 83 96 94 80 1D-141 A 6 4 B 4 9 D 90 86 10102 1 29 70 1 C-109 2 33 4 Page 11 4/1/2002 Injection Profiles and Interpreted Splits: Well Name Date %D %B %A 1D-101 06/21/01 25 25 50 1 D-106 06/01/01 81 11 8 1D-107 06/24/01 30 42 28 1D-114 08/14/01 29 14 57 1D-122 08/14/01 18 51 31 1D-125A 01/04/01 14 39 47 1D-125A 07/20/01 10 42 48 1 D-128 07/06/01 12 64 24 1D-130 07/19/01 15 18 67 1 D-132 09/20/01 24 60 16 1D-137 05/31/01 4 55 41 1D-138 05/13/01 28 72 0 Page 12 4/1/2002 Attachment 6 Kuparuk River Unit West Sak Oil Pool 2001 Annual Reservoir Surveillance Report Wells Allocation and Test Evaluation Summary The West Sak production process monitoring and reporting system functioned as expected in 2001. Fluid samples were obtained on a regular basis and water cut corrections were applied to well test are required based on the subsequent lab analysis. West Sak production was applied an allocation factor of 1.0 for 2001. In 2002, the new "Floating Allocation Factor" methodology will be applied to production as outlined in the Department of Revenue "Advance Meltwater ELF Ruling" dated November 7, 2001. Problem areas cited in previous reports have been addressed with good results: Automated test scheduling implemented in 2000 has allowed us to maximize the utilization of our testing systems. The "Delta V," "Moore," and "SETCIM" systems implemented in the past few years have continued to offer functionality and efficiency. These implementations have continuously improved our ability to troubleshoot well and system performance and to control submersible pumps. Continuous improvement has been seen in the areas of well testing and submersible pump diagnostics. • The field -wide production allocation system is functioning well. Installation of a restrictive orifice in the Accuflow liquid leg (implemented in 1999) continues to be effective for year 2001. The restriction enables the separator to tolerate gas production surges better, resulting in relatively infrequent gas "blow through" on the liquid leg. Gas blow through events result in unusable test data. DS 1 D microwave hardware initially provided intermittent service from the drill site to the central data gathering system (SETCIM). Efforts to debug hardware problems have been successful, and year 2001 results saw further improvement over 1999's results. Communication down time has been decreased considerably and is comparable to other drill sites. The above -mentioned efforts have greatly reduced the need for manual intervention to correct tests. Test results reported for crude oil production appear accurate and representative of well and reservoir performance based on fundamental engineering principles and analysis. West Sak separator utilization is high and our intent is to maintain or increase utilization through continued operations, engineering, and optimization efforts. Page 13 4/1/2002 Attachment 7 Kuparuk River Unit West Sak Oil Pool 2001 Annual Reservoir Surveillance Report Future Development Plans • BACKGROUND INFORMATION Consistent with the original 1997 five-year Plan and POD, Phase 1 development of the West Sak reservoir was initiated at Kuparuk Drillsites 1 C and 1 D. As proposed, Phase 1 was to consist of 50 wells (31 producers and 19 injectors). A producer -bounded five-spot pattern configuration on forty (40) acre well spacing was envisioned with waterflood as the drive mechanism. Phase 1 drilling at DS-1 D was divided into two drilling periods, the first of which commenced in the fourth quarter of 1997 (Phase 1A). The second drilling period (Phase 1 B) commenced near the end of the second quarter of 1998. Phase 1 A consisted of nine producers and five injectors. Phase 1 B consisted of ten producers and six injectors for a total of 19 producers and 11 injectors. First production was achieved in December 1997 with production ramping up into 1999. Phase 1 producers are completed in the West Sak D, B and A - Sands with a mix of multiple stage fracturing/gravel packing (FP) operations or fracturing for sand control (FSC) using an epoxy resin. Electrical submersible pumps (ESP's) and electrical submersible progressing cavity pumps (ESPCP's) are employed as the artificial lift mechanism. Phase 1 drilling at DS-1 C (originally referred to as Phase 1 C) was to commence in early 1999, but a decision was made to defer additional drilling due to changes in the business environment. Engineering assessments of Phase 1 B indicated that drilling costs were near the optimum and that only minor savings could be expected through further optimization of the current completions (fracturing). Additionally, it was believed that the 30 wells drilled to date provided an adequate number of penetrations to assess costs and performance associated with the conventional cased and fractured completions being pursued. Conceptual studies initiated in 1999 indicated that horizontal multi -lateral wells held significant promise in reducing overall development costs while significantly increasing reservoir performance and recovery. Thus, in an effort to develop a "step change" reduction in West Sak development costs and improve low price environment margins, a detailed engineering evaluation of horizontal multi -lateral well designs was initiated. Beginning in the 2nd Quarter of 2000, 3 multi -lateral producers were drilled with 6 support injectors at DS-1 D. These wells were completed in the B and D intervals only. A completion design having an A -sand "tag" originating in the lower lateral was determined to be overly expensive and uneconomic at this time. Page 14 4/1/2002 West Sak Multi -lateral TAM L Level 4 MechanicaIIntegrity it W est Sak "D" Sand �. W est Sak "B" Sand West Sak "A" Sands (Not Initially Targeted) 3000' Target Length per Lateral Positive Sand Control - Sized Pre -packed Screens This multi -lateral design has greatly influenced 2001 development drilling at West Sak and replaced the previously planned Phase 1 C development using conventional wells. Initially, the 2001 plan included four horizontal multi - laterals, nine dual-purpose wells, and ten conventional West Sak injectors. However, due to changing business and co-owner priorities, numerous scope changes reduced the program to two multi -laterals, one dual-purpose completion, and six conventional injectors (shown in Green below). ®Phase 1 (1997-1999) o Phase 2 (2000) ® Phase 3 (2001) Page 15 00 C 3s 102 t A Al t t 1 1 1 00 1� 1 40 t 0 1 t t KI AA t 1 - t 4 0 120 t t' 3 0 01 i 4/1/2002 • WELL COMPLETIONS AND ARTIFICIAL LIFT All future producers are still planned to have positive sand control completions. However, performance data resulting from 2001 Development Drilling Program may alter the completion design in the future. Specifically, 1 C-135 is a slotted liner horizontal completion, which will be produced to establish a baseline production level. Water injection will then be established in the well prior to returning the well to production while continuously monitoring oil, water, gas, and solids production. Following this period, a similar injection/production test will be performed with Miscible Injectant. The objective of this test is to determine the formation and wellbore integrity during mature secondary and tertiary reservoir depletion methods. This should provide valuable insight to our future producer performance, completion integrity, and potential for sand control optimization. After an extensive Artificial Lift Study was completed by John Patterson, et. al., the conclusion is to use Through Tubing Conveyed Electric Submersible Pumps (TTC-ESP) in all future West Sak multi -lateral completions, based on a discounted cost basis and the higher production rates from the current waterflood forecast. • RESERVOIR MANAGEMENT Waterflood operating philosophy to date has been to not inject above reservoir rock parting pressure or inject volumes sufficiently greater than voidage resulting in significant increases in average reservoir pressure. This was originally established to keep the reservoir pressure at a controllable and drillable level with concurrent KRU drilling operations in the DS-1 D area. With the completion of Kuparuk development drilling in the 1 C/1 D area and the potential expansion of West Sak development into areas lacking deeper targets, higher pressure injection is being evaluated. Higher rate injection in conventional monobore injectors could increase producer: injector ratios in future development areas and improve oil rates and recoveries. Single and multiple well injection tests are planned for 2002. Testing will evaluate injectivity, offset productivity, and flood conformance. Additional testing of alternate injector designs is also planned for 2002 (see 2002 Drilling). Miscible gas based FOR evaluations are also planned for 2002. Single well gas injectivity testing is planned as part of the completion stability testing previously noted. Additional plans are to implement a small scale miscible FOR flood on DS-1 C, which would include converting up to 12 water injection wells into MWAG injection wells. The primary targets are the B and D-sands as produced in offset multi -lateral producers. A -sand off -take in the area is very limited. Start-up is expected by September 2002. Total MI injection rates are expected to start at - 3 MMSCF/D. Incremental recovery is estimated at 5-8% OOIP. Both IWAG and MWAG (including CO2 blends) field evaluations remain part of the 5-year development evaluation and may be included in multi -lateral well development assessment. Page 16 4/1/2002 • 2002 DRILLING AND SUBSEQUENT PHASES The success of the DS-1 D & 1 C multi -lateral wells has influenced the long range West Sak Plan of Development, including additional drilling at DS-1 C in 2002 and DS-1 J West Sak Pilot Pad (planned for 2003 & 2004). As horizontal wells continue to be evaluated and optimized, the current waterflood and future FOR potential will be retained. Development drilling at DS-1 D initiated in Phase 1 (1997) is essentially complete. With the completion of planned drilling at DS-1 C in 2002, development of this area as initially envisioned for Phase 2, is finished. Additionally, one ultra -extended reach horizontal multi -lateral (D/B sand) pattern remains from 1 C. Following the 2002 development drilling program, remaining West Sak development will have to occur from new or existing Kuparuk drill sites. Planning continues for the sanction of the 1 J development area (old West Sak pilot) in 2003. Pending changing business conditions, plans are to seek project sanction in the 4'" quarter of 2002 with start of drilling from 1 J in 2003. In the event 1 J sanction does not occur, West Sak development drilling from existing Kuparuk drill sites (1 E, 1 H, 1 B) is a potential. The preliminary production results from 1 D-105A, the sidetrack of 1 D-105, suggest that single D-sand horizontals may be a viable and economic development method in the Eastern periphery of DS-1 C & 1 D, where the A&B- sands are known to be wet. A few D-sand only horizontal patterns remain as upside opportunities from drill sites 1 D and 1 C. Within the DS-1C drilling program, several options are being evaluated to economically develop the A -Sand reserves, which could change the well count and program duration. The option with the most promise is the Horizontal Undulating Producer (HUP) that undulates through the multiple A -sand intervals. Modeling estimates that this completion will provide A -sand only production rates of 600-700 BOPD. The biggest risk is the ability to drill and complete this type or a wellbore (see Figure 5). One such grassroots well is planned for drilling in 2002 from DS-1 C. Page 17 4/1/2002 Another similar wellbore completion replaces three vertical injectors with one Horizontal Undulating Injector (HUI), as shown in Figure 6, that has tremendous cost savings potential at DS-1 J. This wellbore will inject into the D&B-sands and may traverse the intervals 3-7 times. This well type is also planned for 2002 drilling and evaluation from DS-1 D. Page 18 4/1/2002