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Home My WebLink About1999 West Sak Oil PoolARCO Alaska, i Post Office Box 100360 Anchorage Alaska 99510-0360 Telephone 907 276 1215 Stephen V. Bross Supervisor Greater Kuparuk Area Satellite Development ATO-1126 Phone 265-6083 Fax 265-6133 March 27, 2000 Mr. Robert Christenson, Chairman of the Commission Alaska Oil and Gas Conservation Commission 3001 Porcupine Drive Anchorage, Alaska 99501-3120 Re: 1999 West Sak Oil Pool Annual Reservoir Surveillance Report Dear Mr. Christenson: COMMSR hES N(- R E S SP E-NG i NRO, {,-OL. A' ST 2-TAT TECH i rt—..- In compliance with Rule 11, Conservation Order No. 435, ARCO Alaska, 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 1999. 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 1999 (Attachment 4). d. Results of production surveys, and any special surveys, taken on the West Sak Oil Pool in 1999 (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 Judith Abrahams at (907) 659-7061 or Jordan Wiess at (907) 265-4370. Sincerely, Steve Bross GKA Satellite Development Supervisor ARCO Alaska, Inc, is a Subsidiary of Atlantic Richfield Company RECEN MAR 2 9 2000 Nasta oil & Ga��s..}}�Cons. Commission Anchorage AR36-6003-C Attachment 1 Kuparuk River Unit West Sak Oil Pool 1999 Annual Reservoir Surveillance Report Summary of the Enhanced Recovery Project Development activities in 1999 followed the plans as generally described in the Pool Rules. Phase 1 B drilling was completed in January, 1999 with the wells placed on production / injection over the next several months. There was an extensive remedial work effort underway in 1999 to work on failed sand control completions and replace ESP's. Phase 1 drilling was stopped with 30 (17 producers / 11 injectors / 2 suspended) of the planned 50 wells drilled. Sidetracking of the two suspended wells (1 producer & 1 injector) is planned for 2nd Quarter 2000. Implementation of the waterflood continued with producer response noted in some of the 40 acre patterns. Revised development plans have been prepared that focus on a 2000 test of multi -lateral horizontal wells in the West Sak B and D sands. Drilling on the first of 3 planned multi -laterals will be initiated in May, 2000. Below is a listing of key accomplishments related to the West Sak Pool in 1999: 1. Completed an additional 14 Phase 1 B development wells at Drill Site 1 D (8 producers and 6 injectors) in January, 1999. Two wells, the 1 D-110 and 1 D- 118, were suspended during the completion operation; one due to poor cement and the other due to a lost completion fish in the hole. The final completions of these wells will be pursued in 2000. 2. Drill site facilities have been completed at DS 1 D. Construction of additional facilities at DS 1 C has been suspended with approximately 75% of the planned work complete. Approximately $ 3.5 MM (gross) will be required to complete facilities for the twenty 1 C slots. 3. Initiated waterflood surveillance program including first application of geochemical determination of production splits from the D, B, and A sands. Waterflood response as indicated by GOR supression and increase oil rate noted in some patterns. No significant water break -through at this time. 4. Completed installation of remedial gravel packs on 5 failed Frac for Sand Control (FSC) completions. Completed numerous pump replacements and well cleanouts as a result of sand production. Successfully developed operating procedures for replacing and re -starting plugged ESPCP's. As of March 1, 2000, production from Phase 1 @ Drill Site 1D only: • Oil production rate = 3,996. BOPD Water production rate = 581. BWPD Gas production rate = 800. MCFPD Water injection rate = 5,000. BWPD • Cumulative* oil production: 1,964. MSTBO Cumulative* water production 422. MSTBW Cumulative* gas production 634. MMCF Cumulative* water injection: 2752. MBW Cumulative I/W Ratio: 1.10 * Excludes prior West Sak Pilot Production As summary of current producer status: 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 Well # Completion Type Production Rates Oil Water GOR Comments 105 F&P 67 373 200 108 FSC/GP 0 0 0 SI pending Acid Wash (Expected 200 BOPD). 110 PN/GP 0 0 0 Rig Sidetrack in March. (Expected 300 BOPD) 112 FSC/GP 187 2 168 Acid Wash Pending (Expected 250 BOPD) 113 FSC/GP 173 6 228 115 FSC/GP 253 10 203 116 PN/GP 309 1 223 117 FSC 0 0 0 SI for pump replacement (Expected 160 BOPD) 118 F&P 0 0 0 Rig Workover in June (Expected 200 BOPD - A Sand only) 121 FSC 511 95 199 123 PN/GP 287 1 291 124 F&P 267 12 126 126 FSC 233 1 261 127 FSC 317 6 194 129 FSC/GP 521 11 129 131 FSC 228 13 281 133 F&P 359 9 199 134 FSC 164 23 211 135 F&P 118 18 113 Attachment 2 Kuparuk River Unit West Sak Oil Pool 1999 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 1999 80,379 23,569 15,717 1,400,407 555,846 2,333,926 2 1999 71,529 31,583 14,042 1,471,936 587,429 2,347,968 3 1999 87,520 36,842 14,869 1,559,456 624,271 2,362,837 4 1999 110,524 45,112 14,359 1,669,980 669,383 2,377,196 5 1999 114,433 44,275 18,253 1,784,413 713,658 2,395,449 6 1999 109,496 39,576 16,431 1,893,909 753,234 2,411,880 7 1999 106,640 36,541 17,501 2,000,549 789,775 2,429,381 8 1999 104,936 32,615 18,191 2,105,485 822,390 2,447,572 9 1999 98,137 27,088 17,406 2,203,622 849,478 2,464,978 10 1999 93,983 23,612 16,756 2,297,605 873,090 2,481,734 11 1999 101,949 22,237 16,686 2,399,554 895,327 2,498,420 12 1999 107,729 22,355 14,944 2,507,283 917,682 2,513,364 1999 TOTAL 1,187,255 385,405 195,155 Attachment 3 Kuparuk River Unit West Sak Oil Pool 1999 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 1999 97,441 0 0 863,411 0 0 2 1999 105,858 0 0 969,269 0 0 3 1999 93,775 0 0 1,063,044 0 0 4 1999 123,643 0 0 1,186,687 0 0 5 1999 148,126 0 0 1,334,813 0 0 6 1999 143,706 0 0 1,478,519 0 0 7 1999 166,664 0 0 1,645,183 0 0 8 1999 170,908 0 0 1,816,091 0 0 9 1999 161,354 0 0 1,977,445 0 0 10 1999 157,720 0 0 2,135,165 0 0 11 1999 159,778 0 0 2,294,943 0 0 12 1999 157,646 0 0 2,452,589 0 0 1999 TOTAL 1,686,619 0 0 * Excludes pre -development injection Attachment 4 Kuparuk River Unit West Sak Oil Pool 1999 Annual Reservoir Surveillance Report Reservoir Pressure Surveys Rule 8 Format Follows for 1st 2nd 3rd and 4th Quarters 0 W W N N W IL Fh 25 0 i W N W C 0 a W W N N W CL d 0 W N Im 0 a W W N N W C a oe O N W 0 W W N N W GL d GL 0 C W N W Attachment 5 Kuparuk River Unit West Sak Oil Pool 1999 Annual Reservoir Surveillance Report Production Logs and Special Surveys West Sak Wells Sand Members 1 D-111 1 D-114 1 D-122 1 D-128 1 D-130 1 D-132 D 15% 17% 15% 8% 18% 21 % B 43% 33% 40% 51% 20% 64% A4 21% 10% 8% 0% 14% 6% A3 7% 14% 9% 15% 17% 6% A2 14% 26% 28% 26% 24% 3% At 0% 0% 0% 0% 7% 0% Average Survey Conditions Date & RIH time 1/4/00 11:15 1/4/00 16:25 1/6/00 9:15 1/6/00 14:50 1/7/00 9:00 1/12/00 9:00 Injection fluid Water Water Water Water Water Water Injection pressure 1100 psi 1100 psi 1250 psi 1100 psi 1000 psi 1300 psi n ection tem erature 142 de F 142 de F 142de F 142 de F 142 de F 142 de F njection rate 500 BWPD 460 BWPD 700 BWPD 775 BWPD 500 BWPD 600 BWPD ( Based on Schlumberger field analysis of spinner surveys) Attachment 6 Kuparuk River Unit West Sak Oil Pool 1999 Annual Reservoir Surveillance Report Wells Allocation and Test Evaluation Summary The West Sak production process monitoring and reporting system functioned as expected in 1999. Problem areas cited in previous reports have been addressed with good results: • The functionality created by coupling the drill site level "Delta V" and field level "Setcim" systems has significantly improved our ability to troubleshoot well and system performance and control submersible pumps. Inappropriate pump shut downs have decreased with improved control. • Integration of newer computer systems with legacy database and production reporting systems has been completed. The new field -wide production allocation system is functioning well. • Well test efficiency was improved by installation of a restrictive orifice in the Accuflow liquid leg. 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. 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 automated test scheduling in 2000. This feature should enable the automation system to route wells through the test separator according to a rule or operator defined order without manual intervention. Test results reported for crude oil production appear accurate and representative of well and reservoir performance based on fundamental engineering principles and analysis. Attachment 7 Kuparuk River Unit West Sak Oil Pool 1999 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 better sweep to producers if the regional stress field had influence on permeability horizontal plane. Approximate well depths are 4200' TVD. Phase 1 drilling at IDS 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 develop 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. 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 (Phase 1 C) was to commence 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. • WELL COMPLETIONS AND ARTIFICIAL LIFT Phase 1 producers are completed in the West Sak D, B and A Sand with both multiple stage fracturing/gravel packing (FP) operations and fracturing for sand control (FSC) utilizing 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 that resulted non -uniform resin coatings and subsequent proppant flowback. A joint AAI / 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 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 manifest 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 allow 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. After repeated pump failures due to plugging, the 1 D-115 (FSC), had the pump removed and a gravel packed screen placed in the wellbore. The pump was re -run and the well returned to production at 315 BOPD. This type of workover was subsequently performed on four additional candidates which exhibited this failure mechanism (see Summary Table). 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. Waterflood operating philosophy is to not inject above reservoir rock parting pressure nor inject volumes sufficiently greater than voidage resulting in significant increases in average reservoir pressure. The goal is to keep reservoir pressure at a level controllable with normal KRU surface hole mud weights. • WELL PERFORMANCE The average rate from West Sak producers is 259 BOPD including the expected rate from the wells currently shut-in. This is below our target initial rate of 300 BOPD/well. A significant portion of the shortfall may be attributed to two poor performing wells, 1 D-135 (poor A Sand fracture stimulation) and 1 D- 105 (A Sand water encountered). Production rates from several of the Phase 1 B producers now exceed 350 BOPD and a number of wells are beginning to show waterflood response. Due to complications during completion operations and limited capital availability, two West Sak completions at Drill Site 1 D were suspended. The 1 D-110 was suspended due to a poor cement job requiring significant remedial work and the 1 D-118 was suspended with a completion fish still in the hole. Drilling of a sidetrack replacement well for the 1 D-110 should begin in March, 2000. The well will be fraced then gravel packed (F&P) for sand control. Fishing and completion work on the 1 D-118 will begin in June, 2000. Upon removal of the fish, plans are to utilize the well as an A sand only producer in the pattern. A multi -lateral horizontal well is planned for the B and D sands in the 118 pattern. A remedial sidetrack of the 1 D-125 injector is also planned for 2000. The well was originally suspended in 1999 due to poor initial cement. The well supports one of the better West Sak patterns. • 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:I) ratio is 1: 1. This ratio may vary slightly as a result of trying to maintain a producer -bounded development. As the phased development approaches the ultimate full field configuration, 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. This determination can only be accomplished with evaluation of actual field data. With the exception of the 1 D-125, all planned injectors are on-line and the overall voidage replacement ratio is now at 1.1 • 2000 DRILLING AND SUBSEQUENT PHASES In 1999, the overall evaluation of Phase 1A & 1B 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 fracs and refrac 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 (fracs). 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 fraced 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. The resulting plan is to drill 3 multi -lateral producers with 4 support injectors at Drill Site 1 D beginning in the 2"d Quarter of 2000. These wells will be completed in the B and D intervals only (see figure). Future wells could include an additional tag for an 'A' sand completion. Pending the results of these wells, the long range plan including additional drilling at Drill Site 1 C will be modified to reflect completion of the remaining Phase 1 wells over a 3 year period beginning in 2001. TAM L Level 4 Mechanical Integrity West Sak "U' Sand West Sak `B" Sand West Sak "A" Sands (Not Initially Targeted) 3000' Target Length per Lateral Positive Sand Control - Sized Pre -packed Screens If economically viable, the multi -lateral design could take the place of the previously planned Phase 1 C conventional wells. Furthermore, the long range West Sak Plan for development of the core area would be revised to reflect the horizontal well application. As horizontal wells are evaluated, both the current waterflood and future FOR potential will be retained. As noted previously, the pace of subsequent phases as described by groups of wells or annual drilling plans, has been significantly reduced. This is due to both changes in the business environment as well as a desire to pursue alternate technologies that potentially yield significant upside. In previous development plans, we assumed drilling in years 1999 and 2000 to continue at a 32 well per year pace with 1999 drilling at 1 D and 2000 drilling at 1 C. This has been delayed pending results of the 2000 multi -lateral drilling program and any subsequent revision to the long range development plan. Drilling beyond the 50 Phase 1 wells is still expected to occur at a new drill site to the south, perhaps at the West Sak Pilot Pad (WSPP), but may utilize a new well design. The performance of the first 30 wells will be used to better evaluate the long term cost structure including workovers, waterflood performance, and reservoir management plans. ® — Possible Phase 1A 0 Phase 1B 0 Suspended 2000 Drilling • 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 2000 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.