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Home My WebLink About2000 West Sak Oil Pool*"`#° PHILLIPS Alaska, Inc. A Subsidiary of PHILLIPS PETROLEUM COMPANY Stephen V. Bross Supervisor Greater Kuparuk Area Satellite Development ATO - 1126 Phone 265-6083 Fax 265-6133 March 29, 2001 Ms. Julie Heusser, Commissioner Alaska Oil and Gas Conservation Commission 333 West 7th Ave. Suite #100 Anchorage, Alaska 99501-3539 Re: 2000 West Sak Oil Pool Annual Reservoir Surveillance Report Dear Ms. Heusser: 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 2000. 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 2000 (Attachment 4). d. Results of production surveys, and any special surveys, taken on the West Sak Oil Pool in 2000 (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 Mavriky Kalugin at (907) 263-4440 or Jordan Wiess at (907) 263-4370. Sincerely, Steve Bross GKA Satellite Development Supervisor RECEIVED MAR 3 0 2001 Alaska Oil & Gas age CCommission bcc: Central Files ATO - 320 Jordan Wiess ATO - 1156 Mavriky Kalugin ATO - 1158 Dunn&Hunt NSK - 69 Ronald Marquez NSK - 69 Mavriky Kalugin Page 2 03/29/01 Attachment 1 Kuparuk River Unit West Sak Oil Pool 2000 Annual Reservoir Surveillance Report Summary of the Enhanced Recovery Project Development activities in 2000 followed the plans as generally described in the Pool Rules. Sidetracking of the two suspended wells (1 producer & 1 injector) went according to plan. Implementation of the waterflood continued with producer response noted in some of the 40-acre patterns. The revised Phase 2 development plan referred to in 1999, was successfully implemented in 2000. This plan included six conventional injectors and three multi -lateral producers. Each producer has two horizontal laterals, one in the West Sak D-sand and another in the West Sak B-sand. Below is a listing of key accomplishments related to the West Sak Pool in 2000: 1. Completed an additional 9 Phase 2 development wells at Drill Site 1 D (3 producers and 6 injectors) in late January, 2001. 2. Two wells, 1 D-110A and 1 D-125A, were successfully sidetracked and placed on production and injection, respectively. 3. Producer 1 D-118 was placed on production after remedial work to isolate the D & B-sands was completed. The Upper West Sak reserves associated with 1 D-118 will be captured by the new horizontal multi -lateral 1 D-140. 4. Drill site facilities have been completed at DS 1 D. Previously, the construction of additional facilities at DS 1 C was brought to an engineered stopping point with approximately 75% of the planned work completed. This work has resumed and approximately $ 3.5 MM (gross) will be required to complete facilities for the 1 C wells. 5. Completed two additional rounds of geochemical splits for the determination of production splits from the D, B, and A- sands. Waterflood response as indicated by GOR suppression and an oil rate increase noted in some patterns. No significant water break- through at this time. 6. Completed a round of West Sak injection profiles on DS-1 D Mavriky Kalugin Page 3 03/29/01 7. Commenced injection step rate testing of each injector to ensue an optimum waterflood. 8. Completed installation of a remedial gravel pack on a failed Frac for Sand Control (FSC) completion. 9. Completed several pump replacements and fill clean -outs, either due to declining pump efficiencies or fill accumulation. 10. Worked over one producer due to an electrical fault downhole. Production details from Phases 1A, 1 B & 2 at Drill Site 1 D only, as of Feb 1, 2001: Oil production rate = 5,610. BOPD Water production rate = 514. BWPD Gas production rate = 1,722. MCFPD Water injection rate = 8,176. BWPD Cumulative* oil production 3,476. MSTBO Cumulative* water production 588. MSTBW Cumulative* gas production 1050. MMCF Cumulative* water injection 4,322. MBW Cumulative I/W Ratio 1.064 Excludes prior West Sak Pilot production. * Gas production not included in calculation. Mavriky Kalugin Page 4 03/29/01 Producer Summary FSC - Frac for Sand Control using PropLoc FSC / GP - Failed Initial Completion w/ Remedial Gravel Pack F&P - Frac and Pack using Carbolite Frac with Screen PN/GP - PropNet Frac with Gravel Pack Screen FTP - Frac then Pack ML&S - Multi -lateral with pre -packed screens Well # Completion Type Production Rates Oil Water GOR Comments 102 ML&S 667 1 450 1) 11 Horizontal Mullilateral online in July 2000. 105 F&P 69 206 36 Troijbie pushing; fluids to surl'<ace. likely will retire soon. 108 FSC/GP 220 10 185 110A FTP 301 68 186 Sidetracked in 2000. 112 FSC/GP 265 10 175 0 0 0 Paanila failed, awaiting acid wash and replacement. (h.Apected 225 113 FSC/GP 1101,D) 115 FSC/GP 258 11 186 116 PN/GP 302 9 193 117 FSC/GP 150 86 125 118 F&P 107 2 174 B & 1) Sand isolated «/ WO. A -sand production only. 121 FSC 233 56 182 123 PN/GP 297 1 249 124 F&P 248 12 155 126 FSC 252 6 240 127 FSC 166 12 287 129 FSC/GP 402 1 129 '.tiew putrip, ramping rap. 131 FSC 218 36 313 133 F&P 304 11 323 134 FSC 183 20 422 135 F&P 107 25 107 140 ML&S 889 1 379 D&B Horizontal Multilateral online in Nov-2000. 141 ML&S 484 327 312 i)&B horizontal Nfultilateral online in Oct- 2000. Operating at reduced Hz due to ongoing well diagnostics. Mavriky Kalugin Page 5 03/29/01 Attachment 2 Kuparuk River Unit West Sak Oil Pool 2000 Annual Reservoir Surveillance Report Produced Fluid Volumes OIL GAS WATER CUM OIL CUM GAS CUM WATER Month Year STB_ MSCF _BBL BBL_ MSCF BBL_ 1 2000 111,275 23,460 19,336 1,431,303 556,737 2.337,545 2 2000 101,139 20,030 16,203 1 ,532 ,442 575,767 2 ,363 ,748 3 1 2000 122,304 24,440 16,752 1 ,654 ,746 600,207 2 ,370 ,500 4 2000 116,228 24,316 15,285 1 ,770 ,974 624,523 2 ,386 ,785 5 2000 106,976 24,719 15,191 1,877,950 649,242 2,400,976 6 2000 106,259 27,100 15,255 1 ,984 ,209 676,342 2 ,416 ,231 7 2000 105,733 26,102 13,593 2 ,089 ,942 702,444 2 ,429 ,824 8 2000 165,757 41,929 13,379 2,255,699 744,373 2,443,203 9 2000 116,033 36,508 10,214 2 ,373 ,732 780,881 2 ,453 ,417 10 2000 146,469 46,305 16,378 2 ,520 ,201 827,186 2 ,469 ,795 11 2000 165.432 53,503 17,515 2,685,633 880,689 2,487,310 12 2000 184,557 67,367 16.667 2 ,870 ,190 938,056 2 ,503 ,977 2000 TOTAL: 1,550,162 185,768 405,779 Mavriky Kalugin Page 6 03/29/01 Attachment 3 Kuparuk River Unit West Sak Oil Pool 2000 Annual Reservoir Surveillance Report Injected Fluid Volumes WATER GAS NGLS CUM WATER' CUM GASCUM NGLS Month Year (STB) (MSCF) (BBL) (BBL) (MSCF BBL 1 2000 168,830 2 ,621 ,419 2 2000 144,156 2 ,765 ,57d 3 2000 136,046 2 ,901 ,620 4 2000 83,245 2 ,984 ,865 - 5 2000 32,726 3 ,017 ,591 6 2000 27,073 _ 3 ,044 ,664 7 2000 97,145 3,141,809 8 2000 151,704 3.293,513 9 2000 159,114 3 ,452 ,627 10 _ 2000 190,890 3,643.617 - 11 2000 212,129 3,855,646 12 2000 213,045 4.068.691 - 2000 TOTAL 1616102 0 0 Excludes pre -development injection Cumulatives from Dec (last report): 2,452,589 0 0 Mavriky Kalugin Page 7 03/29/01 Attachment 4 Kuparuk River Unit West Sak Oil Pool 2000 Annual Reservoir Surveillance Report Reservoir Pressure Surveys Rule 8 Format Follows for 1st 2nd 3rd and 4th Quarters STATE OF ALASKA — ALASKA OIL AND GAS CONSERVATION COMMISSION ANNUAL RESERVOIR PRESSURE REPORT - 2000 Name of Operator Address Phillips Alaska Inc. P.0 Box 100350,Anchorage,AK99510-0360 Unit or Lease Name Field and Pool Kuparuk River field Datum Reference Oil Gravity Gas Gravity Kuparuk River Unit West Sak Oil Pool -3500'33 1.06 0.57 Final Pressure Test Data Production and Test Data API O,G Shut-in Tool Final Production Rates Wt. of I Wt. of I Pressure Number or Date Shut-in Tubing Depth B.H. Observed (Bbls0ay) (Mcfd) Liquid Liquid Gas Casing at Pressure I Oil Waterl Gas ;Well Name Sand WI Tested Time Press. MD Temp. Gradient Column Column Press.1 Datum 1D-106 Z 500232284700 WI 03130100 191 790 4628' 74' 2347'' 0' 840 0' 2248 1D-106 Z 500292284700 WI 04118100 118 769 4670 89 2369 0 778 D 2254 10-119 Z 500292283600 WI 04/21100 75' 897I 4000 79' 2391 0 214 0 2327 1D-120 Z 500292283500' WI 03130100' 358' 840 4031' 74' 2186' 0 710 0 2095 I hereby certify that the foregoing is true and correct to the best of my knowledge. - - - - - Signed Title OKA Satellites Supervisor Date Form 10-412 Submit in Duplicate Rev 71 80 Mavriky Kalugin Page 8 03/29/01 Attachment 5 Kuparuk River Unit West Sak Oil Pool 2000 Annual Reservoir Surveillance Report Production Logs and Special Surveys West Sak Well Number: 1D-102 1D-102 1D-102 1D-102 1D-105 1D-105 1D-108 ID-110A 1D-112 1D-113 1D-113 1D-115 1D-115 1D-116 1D-116 1D-116 1D-121 1D-121 1D-123 Sand Member D (% Oil Production) 31 35 39 38 86 92 19 40 6 29 23 17 21 15 15 4 25 34 8 Sand Member B (%Oil Production) 68 66 1 59 1 58 14 4 38 1 26 1 64 38 1 48 45 1 37 47 47 1 50 45 1 31 41 Sand Member A (%Oil Production) 0 0 2 4 0 4 42 35 30 33 29 39 43 38 38 46 30 35 51 Sample Number 2912T 23127 23127 23144 25233 23133 23845 29846 25300 25301 29130 25302 23133 25303 25303 29128 25304 23141 25305 Sample Collection Date 10119100 10119100 10119000 11110100 Apr-00 10124100 11118100 1W0100 Apr-00 Apr-00 10121100 Apr-00 IO128/00 W10199 Apr-00 10119100 Apr 00 10?29100 Apr-00 Analysis Date Nov-00 Nov-00 Nov-00 Nov-00 Apr-00 Nov-00 Nov-00 Nov-00 Apr-00 Apr-00 Nov-00 Apr-00 Nov-00 Nov-99 Apr 00 Nov-00 Apr-00 Nov-00 Apr-00 West Sak Well Number: 1D-123 1D-124 1D-126 1D-127 1D-127 1D-129 1D-129 1D-131 1D-133 1D-134 1D-134 1D-135 1D-140 1D-140 1D-141 1D-141 1D-141 1D-141 1D-141 Sand Member D (%Oil Production) 3 13 14 18 13 24 13 10 12 25 23 67 60 57 94 94 94 93 96 Sand Member B (%Oil Production) 42 44 1 39 53 49 1 29 44 1 53 24 23 1 32 28 1 33 34 1 4 4 5 1 7 3 Sand Member A (%Oil Production) 55 43 47 29 38 47 43 36 64 52 45 5 7 10 2 1 0 0 1 Sample Number 29847 23137 25306 25307 23140 25308 29138 29134 29135 25310 25131 23132 23848 29849 29142 23142 23143 29143 29143 Sample Collection Date W19100 1012V00 Apr-00 Apr-00 1012NOO Apr-00 1012R00 10125100 10126100 Apr-00 10122100 10123100 1112000 11120100 WN00 WNW 1109100 WSM 1119100 Analysis Date Nov-00 Nov-00 Apr -DO Apr-00 Nov-00 Apr-00 Nov-00 Nov 00 Nov-00 Apr00 Nov-00 Nov-00 Nov-00 TN7. Nov-00 Nov-00 Nov-00 Nov-00 Nov 00 Mavriky Kalugin Page 9 03/29/01 Attachment 6 Kuparuk River Unit West Sak Oil Pool 2000 Annual Reservoir Surveillance Report Wells Allocation and Test Evaluation Summary The West Sak production process monitoring and reporting system functioned as expected in 2000. 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" 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. • Integration of newer computer systems with legacy database and production reporting systems came to fruition in 2000. 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 2000. 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 2000 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. West Sak separator utilization is high and our intent is to maintain or increase utilization through continued operations, engineering, and optimization efforts. Test results reported for crude oil production appear accurate and representative of well and reservoir performance based on fundamental engineering principles and analysis. Mavriky Kalugin Page 10 03/29/01 Attachment 7 Kuparuk River Unit West Sak Oil Pool 2000 Annual Reservoir Surveillance Report Future Development Plans FIVE YEAR PLAN OF DEVELOPMENT • PHASE 1 BACKGROUND INFORMATION Consistent with the original 1997 five-year Plan and POD, Phase 1 development of the West Sak reservoir was initiated at Kuparuk Drill Sites 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. The five-spot pattern was to be oriented to yield a north south staggered line drive configuration. This would allow for rapid communication between injectors and a more efficient sweep to producers if the regional stress field had influence on horizontal permeability. Approximate well depths are 4200' TVD. 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 drilled to date. First production was achieved in December 1997 with production ramping up into 1999. The original 40-acre pattern development has been utilized. However, the Phase 1 development plan in the 1 D area was modified slightly due to encountering water in the middle of the A sand interval of the 1 D-105 producer. Remaining Phase 1 drilling has continued to focus in up -dip areas, with little risk of encountering water. Future development of the B and D sands above the wet A interval remains a future option. 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. Although they are 75% complete, construction of Drill Site 1 C facilities was brought to an "engineered" stopping point that allowed for future low cost completion of the facilities. Mavriky Kalugin Page 11 03/29/01 WELL COMPLETIONS AND ARTIFICIAL LIFT Phase 1 producers are completed in the West Sak D, B and A -Sand 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. ESP's were initially utilized in FP wells where screens provide positive sand control while ESPCP's were utilized in FSC wells. PCP's utilizing both single lobe and higher rate multi -lobe pump sections have been employed. In solids producing wells, there is now a trend to utilize single lobe pumps due to their lower plugging tendency and ease of re -start. During Phase 1, a problem was identified in the proppant coating system, which resulted in non -uniform resin coatings and subsequent proppant flowback. A joint AN / vendor evaluation resulted in significant blending and application modifications that were utilized in the remaining 7 Phase 1 B FSC applications. Initial results from the Phase 1 B, show improved resin -coating performance and reduced proppant flowback potential. Reference SPE Paper 54628: Hydraulic Fracturing for Sand Control in Unconsolidated Heavy Oil Reservoirs, authored by Mark Wedman, Keith Lynch, and Jim Spearman. Although the resin coating of the proppant was improved, a secondary issue manifested itself in 1999 with the Phase 1 B FSC wells. It appears that in highly deviated wells, a limited number of perforations failed to accept resin coated proppant and subsequently allowed formation sand to flow into the wellbore and plug pumps. Although ESPCP type pumps are designed to handle solids loading, the sand volume appears to be too great and the pumps are going down on low suction pressure. The producer 1 D-115 (FSC) had the pump removed and gravel packed screen placed in the wellbore due to repeated sand plugging and subsequent pump failures. The pump was re -run and the well returned to production at 315 BOPD. This type of workover was subsequently performed on several additional candidates exhibiting this failure mechanism (see Summary Table, Attachment 1). To improve sand mobility out of the FSC well bores, single lobe pumps are being utilized and a "viscous pill" sweep pumped down the backside to remove solids has been tested. Additionally, a coil tubing clean -out procedure has been effectively used to re -start plugged pumps. Injectors are single monobore completions open to all zones, except 1 D-138, which is not open in the A -sands. There are no producers with open A -sands in the vicinity to benefit from this injector. Waterflood operating philosophy is to Mavriky Kalugin Page 12 03/29/01 not inject above reservoir rock parting pressure or inject volumes sufficiently greater than voidage resulting in significant increases in average reservoir pressure. This will keep the reservoir pressure at a controllable level with concurrent KRU drilling operations at Drillsite 1 D. • WELL PERFORMANCE The average rate from West Sak producers is 286 BOPD including the new multi -laterals (ML). Presently, the highest production rate of 889 BOPD at 0% watercut is from the 1 D-140 ML, which has a -4000 foot horizontal lateral in each D & B-sand. The poorest production performance comes from an ESP producer, 1 D-105, which produces 70 BOPD and 206 BWPD. A number of wells are showing waterflood response, this is especially evident in the suppression of the production GOR's. The success of the three horizontal D & B-sand multi -laterals at IDS 1 D, both, in the application of technology and the subsequent increase in production rates has allowed a step change in future West Sak development. The three suspended West Sak completions in Phase 1, 1 D-110, 1 D-118, and 1 D-125, were successfully worked over or sidetracked in 2000 and brought online. Injection step rate testing has been completed on over half of the injectors in an effort to optimize injection and production, especially in the vicinity of the high rate multi -lateral producers. • RESERVOIR MANAGEMENT As mentioned above the recovery mechanism is waterflood. Given the stated injection philosophy, the studies done to date suggest the economic optimum for producer to injector (P: 1) ratio is 1:1. This ratio may vary slightly as a result of trying to maintain a producer -bounded development. This is especially true with the addition of three multi -laterals drilled in year 2000. As the phased development approaches full field completion, the overall ratio should approach 1: 1. However, differences in actual vs. expected injectivity and productivity may dictate changes in the planned producer to injector ratio. Suspending the program at 30 of 50 planned wells have left some unbounded patterns that may require support injectors drilled as part of future programs. Higher than expected production rates of the multi -laterals may also require additional injectors. This determination will be accomplished with the ongoing acquisition and detailed evaluation of actual field data. All planned injectors are on-line with the cumulative injection to withdrawal ratio presently at 1.06. • 2001 DRILLING AND SUBSEQUENT PHASES Mavriky Kalugin Page 13 03/29/01 In 1999, the overall evaluation of Phase 1 A & 1 B indicated that drill and complete costs were approximately 15% higher than expected and production rates were 15% lower than expected. Although drilling cost were within targets and a good learning curve was established, completion costs continued to be highly variable with significant overruns due to failed fractures and refracture attempts. Operating cost were much higher than targets due to the failed FSC completions and the subsequent pump replacements and workovers. 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 2"d Quarter of 2000, 3 multi -lateral producers were drilled with 6 support injectors at Drill Site 1 D. These wells were completed in the B and D intervals only (see Figurel ). A completion design having an A -sand "tag" originating in the lower lateral was determined to be overly expensive and Figure 1: West Sak Multi -lateral TAM L Level 4 Mechanical Integrity West Sak"M Sand 3000' Target Length per Lateral Positive Sand Control - West Sak `B" Sand / I Sized Pre -packed Screens West Sak "A" Sands (Not Initially Targeted) uneconomic at this time. Mavriky Kalugin Page 14 03/29/01 uneconomic at this time. 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. The 2001 plan includes 4 horizontal multi -laterals, 9 dual- purpose wells (see Figure 2), and 10 conventional West Sak injectors. The multi -laterals are very similar to those differences being the multi -lateral junction and horizontal length. The Multi -laterals access only the D & B-sands. To capture the A -sand reserves, dual-purpose completions are planned in addition to conventional West Sak injectors. Essentially, by injecting into the D & B- sands and concurrently producing from the A -sand in the same wellbore, we will not be altering the waterflood pattern for the D & B-sands. However, we will be increasing the flooding pattern for the A -sands (see Figure 3), but, due to favorable oil mobility of that formation, we will still capture the associated reserves. To mitigate the risk associated with the implementation of this "new" technology on the slope, three dual - at Drillsite 1 D, with the major Figure 2 Dual Purpose 'A' Sand Injector/ D Sands B Sands A Sands Figure 3: West Sak 40 Acre Pattern, with 80 Acre Flood Pattern (Dashed Rectangle) purpose completions are to be • 10 10 410 • drilled early in the program. This Q Q allows for evaluation before the remainder of the dual-purpose • • wells are drilled and completed. The success of the Drillsite 1 D ;. ;,; ; ,, . _ _ __ _ _• multi -lateral wells has influenced the long range West Sak Plan of Development, including the • ..... ........... • planned drilling at Drill Site 1 C and Drillsite 1J. For reference, Drillsite 1 J is the old West Sak Pilot pad. • ` ' • As horizontal wells continue to be evaluated and optimized, the Dual BID Sand Horizontal Producers Purpose 'A' Sand Injector/Producer current waterflood and future FOR potential will be retained. In previous development plans, we assumed drilling in years 1999 and 2000 to Mavriky Kalugin Page 15 03/29/O1 continue at a 32 well per year pace with 1999 drilling at 1 D and 2000 drilling at DS 1 C. Unfavorable economic and other factors delayed the 1 C development to year 2001. As previously mentioned, the results of the 2000 multi -lateral drilling program have revised the pace and the long-range development plan. Drilling beyond the original 50 Phase 1 wells is still expected to occur at a new drill site to the south, referred to as Drillsite 1J, previously known as West Sak Pilot Pad (WSP). The DS-1J development will be predicated on a B/D ML program, with associated water support wells, with the drilling program anticipated to occur from 2002 -2005. Simultaneous to the DS-1 c program, several options are U FRI 'A� Existing: 19 Producers 11 Injectors —2000 Drilling • Phase 1A O Phase 1B O Suspended Planned 2001/2002 Drilling being evaluated to economically develop the A -Sand reserves, which change the well count and program duration. Mavriky Kalugin Page 16 03/29/01 • FOR EVALUATION Conceptual screenings are now underway on miscible injection based processes as an enhanced recovery mechanism (EOR) for West Sak. The ultimate reservoir development plan as re -determined following the implementation and evaluation of the year 2000 multi -lateral horizontal test wells will be critical. Conceptual screening of small-scale immiscible WAG processes (IWAG) using lean gas to evaluate injectivity has also been completed. Pilot or small scale gas injection testing could be included in post 2001 plans. Even so, both IWAG and MWAG (including CO2 blends) field evaluations remain part of the 5-year development evaluation and will be included in multi -lateral well development assessment. Mavriky Kalugin Page 17 03/29/01