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Home My WebLink About1998 West Sak Oil PoolARCO Alaska, Inc. Post Office Box 100360 Anchorage, Alaska 99510-0360 Telephone 907 276 1215 " Steven V. Bross Supervisor 1 Greater Kuparuk Area Satellite Development w ATO 48 Phone Phonee 26 Fax 265-6133 L April 1, 1999 Mr. Robert Christenson, Commissioner Alaska Oil and Gas Conservation Commission r 3001 Porcupine Drive Anchorage, Alaska 99501 Re: 1998 West Sak Oil Pool Annual Reservoir Surveillance Report Dear Mr. Christenson: In compliance with Rule 11, Conservation Order No. 406, 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 1998. The following is an outline of the information provided: a. A summary of the enhanced recovery project (Attachment 1). b. Voidage balance, by month, of produced and injected fluids (Attachment 2, Attachment 3). c. Analysis of reservoir pressure surveys taken in 1998 (Attachment 4). d. Results of production surveys, and any special surveys, taken on the West Sak Oil Pool in 1998 (Attachment 5). e. Results of well allocation and test evaluation for Rule 7(f) and any other special monitoring (Attachment 6). f. Future development plans (Attachment 7). If you have any questions concerning this data, please contact Mike Beck at (907) 276-1215 x7285. Sincerely, o Scet-eve Bross GKA Satellite Development Supervisor ARCO Alaska, Inc. is a Subsidiary of AtlanticRichfieldCompany Attachment 1 West Sak Oil Pool 1998 Annual Reservoir Surveillance Report Summary of the Enhanced Recovery Project Development and exploration activities in 1998 followed the plans described in the Pool Rules. Below is listing of key accomplishments related to the West Sak Pool in 1998: 1. Completed the Phase 1 A drilling and completion in April, 1998, with all but one production well being brought on line. 2. Initiated injection of produced water DS 1 D in January, 1998. 3. Initiated drilling of Phase 1 B on DS 1 D in June, 1998. 4. Completed drilling phase 1 B on DS 1 D in October, 1998. There were Ten Production wells and 6 injection wells drilled in Phase 1 B 5. Initiated production phase 1 B wells from DS 1 D in December, 1998. Attachment 2 West Sak Oil Pool 1998 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 1998 13562 2040 6346 769203 344714 2121918 2 1998 24473 2373 13999 793676 347087 2135917 3 1998 42627 13595 23960 836303 360682 2159877 4 1998 44624 28257 23793 880927 388939 2183670 5 1998 60372 26844 26183 941299 415783 2209853 6 1998 54446 22847 22778 995745 438630 2232631 7 1998 59623 14265 21061 1055368 452895 2253692 8 1998 54246 12497 19450 1109614 465392 2273142 9 1998 45497 12232 7399 1155111 477624 2280541 10 1998 44705 13079 10794 1199816 490703 2291335 11 1998 55488 17596 10512 1255304 508299 2301847 12 1998 64724 23978 16362 1320028 532277 2318209 1998 TOTAL 483725 158332 171595 Attachment 3 West Sak Oil Pool 1998 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 1998 3428 0 0 3428 0 0 2 1998 18440 0 0 21868 0 0 3 1998 38833 0 0 60701 0 0 4 1998 34554 0 0 95255 0 0 5 1998 61500 0 0 156755 0 0 6 1998 58528 0 0 215283 0 0 7 1998 60088 0 0 275371 0 0 8 1998 101926 0 0 377297 0 0 9 1998 88002 0 0 465299 0 0 10 1998 95192 0 0 560491 0 0 11 1998 103912 0 0 664403 0 0 12 1998 101567 0 0 765970 0 0 1998 TOTAL 765970 0 0 * Excludes pre -development injection W V C O .0 IL 1- 3 a (AD W W E U m 6 m � � C n m c$ O Y m m {m{pp L a m e 0. 9 y n 0 N N N N2 ' N 0 in N N N - - N N a U9QQ �i Oi N y N N N N Q N N CJ F N N N N N N N a A i0 0 y N N t2 ' 7 �i ' m a a P. a> 0 m oa O m m N a t0 n A N p Oi O b N M A V. O O A A A A A A A A A y m LN 0i in m m Yq YWW Yqq Yqq Yqq Yqq YWW qmq Y Yqq Yqq Yqq Yqq Y Yqq Yryry Yqq Yqq 2 S S S S S S 2 2 2 2 2 S 2 2 2 2 2 n O O N N n N N N N N N CNI t�i 3 a a a a a e d a d e a b e d e e e e O a W V U) tC > i 4- d .� C — 3 M m0cn'� E�LQ V N cc U) i ca � �a c co T O O O O O O N I� r- M CO N 0 r Co r p � a C r > > r 00 N � � T O O O O O O r T Cl) T M r- r 00 0 O L N 0 T _ N yQ 7 CV) r CO O N r In O Lo O co 0 0 0 0 0 0 T N N CO T N T r Ln r O 0 Co 1 i L Q +� C6 T m > Ln N co CA r co r co 0 0 0 0 0 0 0 0 0� o� Cn N d' CA m r O CO O O L.L m CO :_> r co 0 0 0 0 0 0 000000 Ln LL 0 O r co o cz c6co N m CA N r c co co It CO _ a)(ll cz . od C O C O C •O C O CU (6 U N U N U N U N C C C C Attachment 6 West Sak Oil Pool 1998 Annual Reservoir Surveillance Report Well Allocation and Test Evaluation Summary West Sak production was initiated in late December, 1997. Overall, the process monitoring and production reporting system functioned adequately with active engineering intervention. Problem areas were addressed by observation and manual correction. Trouble spots were: • The advanced monitoring systems we constructed utilized beta version software at several layers. Debugging these systems proved troublesome. Since the middle of February `99, overall system performance has improved dramatically. • Integration of newer computer systems with legacy database and production reporting systems has been challenging. It appears the major problems associated with connecting the monitoring systems to the database and reporting systems have now been overcome. • West Sak gas production was metered too low for all wells in the September to November 1998 timeframe. • Microwave hardware provided intermittent service from the drillsite to the central data gathering system (Setcim) from December'98 through early February 1999. The net effect was to reduce or slow data transfer. Test quality was not impacted. The difficulties encountered with the newer systems for the most part increased the manpower required to obtain and report quality test data. Except for the gas measurement problem noted above, basic meter performance has been very good. Test results reported for crude oil production appear accurate and representative of well and reservoir performance based on fundamental engineering principles and analysis. For 1999, we plan to continue tuning and optimization of the drillsite data acquisition system (Delta V) and enhance the communication and control link from Delta V to the central data gathering and storage system (Setcim). A new Kuparuk wide production allocation package will be commissioned in Setcim during April 1999. Overall, most major system changes are now complete and functioning well. From an allocation standpoint, tuning efforts have already reduced manual intervention. Planned enhancements should further reduce the intervention required in the coming calendar year. Although West Sak separator utilization is quite high at this time, our goal is to increase the total number of well tests conducted. Attachment 7 West Sak Oil Pool 1998 Annual Reservoir Surveillance Report West Sak Development Plan Following are summaries of key activities that have either already occurred in the first quarter of 1999, or are planned at this time. Completion of Phase 1 B - From January 1, 1999 through March 31, 1999 the remaining completions of the West Sak producers was finished. All production wells have been brought on line except 2. The 1 D-110 well has been suspended, as a remedial cent job is required prior to the completion. The 1 D- 108 well failed to start and is being worked on. Final completion and facility commissioning work on the six Phase 1 B injectors is ongoing. Three of these 1 D-122, 128 and 132 are projected to be online by the end of March. The other three will be started up early in the 2nd quarter of 1999. FIVE YEAR DEVELOPMENT PLAN • PHASE 1 DEVELOPMENT PLAN Consistent with the 1997 Five Year Plan, Phase 1 development of the West Sak reservoir at Kuparuk Drill Sites 1 C and 1 D is underway. Phase 1 as proposed consisted of approximately 50 wells (31 producers and 19 injectors). A producer - bounded five-spot pattern configuration and forty (40) acre well spacing is employed. The drive mechanism is waterflood. The five-spot pattern is oriented to yield a north -south staggered line drive configuration. This allows for rapid communication between injectors and better sweep to producers if the regional stress field has influence on permeability horizontal plane. 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 1 A). The second drilling period commenced near the end of the second quarter of 1998 (Phase 1 B). Phase 1 A consisted of nine producers and five injectors. Phase 1 B consisted of ten producers and six injectors. First production was achieved in December 1997. The Phase 1 development plan has been modified slightly due to encountering water in well 1 D-105. Remaining Phase 1 drilling has been focused in up -dip areas, with little risk of encountering water. With the downturn in the oil price, and industry activity, the West Sak development has been significantly scaled down. Only two horizontal test wells are being evaluated for potential drilling at DS-1 D in 1999. One horizontal is planned in each of the "B" and "D" sands, and will be tied into existing infrastructure. The remainder of the Phase 1 drilling on the DS-1 C pad is currently planned for 2000 and beyond. Additional drilling will be a function of oil price and Phase 1 results. • WELL PERFORMANCE The average initial rate from the eight West Sak producers on line at the time of this report is 250 BOPD/well. This is below our target initial rate of 300 BOPD/well. The shortfall is predominantly caused by two under -performing wells, 1 D-135 (unsuccessful A Sand fracture stimulation) and 1 D-105 (a wet A Sand member was encountered). Average production from the six other wells is 296 BOPD. As our experience in well completions and fracture stimulation grows, we expect all completions to meet or exceed the 300 BOPD target rate. • WELL COMPLETIONS AND ARTIFICIAL LIFT Producers are completed in the West Sak D, B and A Sand intervals with both multiple stage fracturing/gravel packing operations and fracturing for sand control utilizing an epoxy resin. Completions in the first drilling block at DS 1 D employed multi -stage frac-pack operations (FP) in five producers and fracturing for sand control (FSC) in four producers. Encouraging results from FSC have led to the planned expansion of this completion type Phase 1 B. The ultimate goal is to settle on the completion type that yields superior rate, cost and sand control performance. Electrical submersible pumps (ESPs) and electrical submersible progressing cavity pumps (ESPCPs) are employed as the artificial lift mechanism. ESPs are utilized in FP wells while ESPCPs are utilized in FSC wellslnjectors are single monobore completions open to all zones. Waterflood operating philosophy is to not 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. A typical injector well design is included as Attachment 6. • SUBSEQUENT PHASES Subsequent phases describes groups of wells or annual drilling plans implemented after the initial 50 well development referred to as Phase 1. Drilling beyond Phase 1 is currently undefined and will be a function of Phase 1 results and the oil price environment. Phase 2 subsequent development begins by continuing drilling at Drill Sites 1 C and 1 D to capture the benefit of well hookup pre -investment. For this Development Plan document we have assumed drilling in years 2000 and 2001 (remaining Phase 1 drilling) to continue only through the 20 Phase 1 wells. Drilling in 2002 is expected to occur at a new drill site to the south, perhaps at the West Sak Pilot Pad (WSPP). Wells for Subsequent phases are shown to be split evenly between producers and injectors, although a true producer/injector split is yet to be determined. 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. Proposed developments in this plan show P:I ratios as high as 1.5:1. This is the result of trying to maintain a producer - bounded development. As the phased development approaches the ultimate fullfield configuration, the overall ratio should approach 1:1. However, differences in actual vs. expected injectivities and productivities may dictate changes in the planned producer to injector ratio. This determination can only be accomplished with evaluation of actual field data. It is unlikely a change in pattern configuration will be implemented in Phase 1 as insufficient data will exist to decision any change.