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Home My WebLink About2003 Alpine Oil PoolConocoPhillips Alaska, Inc. March 22, 2004 Alaska Oil and Gas Conservation Commission Attention: Mr. John Norman 333 West 7th Ave, Suite 100 Anchorage, AK 99501 Chris Alonzo Alpine Engineering Supervisor Post Office Box 100360 Anchorage, Alaska 99510-0360 Phone (907) 265-6822 Fax: (907) 265-1515 Subject: Annual Surveillance Report for the Alpine Oil Pool of the Collville River Unit Dear Commissioner Norman: ConocoPhillips Alaska, Inc., as Operator and on behalf of the working interest owners of the Colville River Unit submits this, the Annual Surveillance Report for the Alpine Oil Pool of the Colville River Unit. This report is submitted in compliance with Rule 8, of Conservation Order No. 443, and reflects the status of the Alpine Pool of the Colville River as of February 1, 2004. Attachment 1 illustrates the current unit boundary, which was revised in June of 2003. If you have any questions or require additional information, please contact me at ConocoPhillips Alaska, Inc., P. O. Box 100360, Anchorage, Alaska, 99510-0360, Telephone: (907) 265-6822. 1.0 Progress of Recovery Projects 1.1 Average Metrics for the time period of February 2003 through January 2004 - Average oil production rate 97.2 MBOPD - Average gas production rate 113.9 MMSCFD - Average water production rate 884 BWPD - Average gas injection rate 99.2 MMSCFD - Average water injection rate 93.6 MBWPD - Average produced water inj. Rate 449 BWPD Annual Surveillance Repoi, Alpine Oil Pool, Collville River Unit March 22, 2004 1.2 Cumulative Volumes Produced and Injected through January 2004 - Cumulative oil production through January 2004: 108,047,639 STBO - Cumulative gas production through January 2004: 117,105,409 MSCF - Cumulative water production through January 2004: 541,089 STBW - Cumulative gas injection through January 2004: 101,412,960 MSCF - Cumulative water injection through January 2004: 96,152,093 STB 1.3 Surface Facility Update The production facilities installed in 1999-2000 are at full capacity. Crude oil is being processed and transported via pipeline to Kuparuk's Central Processing Facility 2. Produced gas and water is re -injected. Produced gas is blended with natural gas liquids and re -injected for enhanced oil recovery within the Alpine Field. The primary facility maintenance activity during 2003 occurred between July 28 -August 3, when the plant was taken down for annual maintenance. The most significant process change was an upgrade of the condensate pump to increase condensate injection into the MI blend stream. 1.4 Miscible Water Alternating Gas Flood Management during 2003 Development of the Alpine reservoir is based on a Miscible Water Alternating Gas (MWAG) project design. Alpine EOR facilities have been described in previous testimony before the AOGCC. This discussion will provide a narrative update on key reservoir management issues for the time period of February 2003 through January 2004. CD1 Attachment 2 gives an overview of the miscible water -alternating -gas (MWAG) conversion status at CD1 in a tabular form. The MWAG flood has now significantly matured, as shown in Attachment 3. CD1 averages an HCPV throughput of approximately 46%. Two wells have completed the target MI slug of approximately 30% HCPV (CD1-21, CD1-23). Three wells, CD1-01, CD1-02 and CD1-13, are on their 2nd cycle of MI, after having been temporarily converted to seawater injection in order to control rising GOR trends in offset producers. CD1-21 and CD1-31 were also converted to MI service in 2003, mainly for pressure support, in order to make seawater available to other wells requiring conversions to seawater injection. Six MWAG injectors, CD1-03, CD1-23, CD1-26, CD1-37, CD1-39 and CD1-42, have been converted back to their second cycle of seawater injection duty, in order to alleviate rising GOR trends in offset producers. Four wells, CD1-16, CD1-33, CD1-36 and CD1- 45, are on their first cycle of MI, and will be converted to seawater injection according to the response seen in the offset producers. The main drivers behind the rate of maturation of the different patterns are field offtake, local re -pressurization schemes to allow for safe development drilling, local voidage balance requirements, seawater availability, MI enrichment requirements and the necessity to control GOR within compressor limits. K Annual Surveillance Report Alpine Oil Pool, Collville River Unit March 22, 2004 CD2 Attachment 4 gives an overview of the MWAG conversion status in a tabular form. Attachment 5 shows the maturity of the different patterns. CD2 is significantly less mature than CD1, with only 8.3% overall throughput. This is due to a combination of factors: production commenced later than at CD1 and offtake rates have been moderated due to the ongoing development drilling. Also, relatively large pattern volumes are common at CD2, and lower rock quality will not allow the same processing rates attained at CD1. Twenty-four MWAG injectors are now in place at CD2. Sixteen of these are still on their first cycle of seawater injection. Seven wells have been converted to their first cycle of MI. One well, CD2 -49, has been converted back to seawater injection after having served as a dry gas and MI injection well during the period from October 2002 until mid-April 2003. The impetus to convert this well to gas injection service at a relatively early stage was to spread dry gas injection throughout the field, and to test the gas flooding potential of the tighter CD2 C sands. The good response observed in offset producers, suggests that CD2 should deliver similar recovery factors to CD1. Overall field response to the MWAG remains excellent. Attachment 6 depicts recovery vs. throughput for all active MWAG patterns, and attests to the effectiveness of the EOR flood at Alpine. 1.5 Injectivity of wells on 2nd MWAG cycle A dozen wells have now been put on seawater injection duty after having served as MI injectors for some period of time. A reduction in injectivity during the second cycle of water following gas injection has been noticed in most wells. While the amount varies from well to well, the loss averages about 50%. This was expected given the fine- grained Alpine sands coupled with low initial water saturations. These relative permeability affects have been accounted for in the reservoir simulator. Two wells, CD1-01 and CD1-02, have seen no or very little reduction in injectivity. This is thought to be due to a higher level of natural fracturing in that particular area of the field. 1.6 MI Enrichment Issues The MI stream consists of lean gas from the field gas production stream (blend gas) and C2+ enriching components extracted from the condensate flash drum and the Joule Thompson Unit. The supply of enriching components is limited to about 15 mmscf/d. Part of the field management strategy focuses on maintaining the MMP of the injected MI lower than the average reservoir pressure. This requires a certain enrichment level of the MI stream that cannot always be achieved by using all the blend gas. Some of the blend gas must therefore be injected into up -structure lean gas wells to ensure adequate composition of the MI stream. For optimal EOR performance, the amount of lean gas injection is kept to a minimum. The CD2 -49 was converted to lean gas injection in October 2002, to reduce the injection requirements in the eastern up - structure lean gas injection wells. As additional low GOR CD2 production has been brought online, the necessity to inject lean gas has been reduced, and CD2 -49 was subsequently converted to MI to improve pattern EOR performance. 3 Annual Surveillance Repor, Alpine Oil Pool, Collville River Unit March 22, 2004 The composition of the injected miscible gas is routinely monitored and adjusted with the miscible gas/lean gas split to ensure miscibility with the reservoir oil. 1.7 Reservoir Management for 2004 In 2004, reservoir management at Alpine will be driven by field wide production offtake, re -pressuring CD1 during the summer shutdown, and local re -pressurization schemes to support development drilling. The plant upgrades that will be implemented during the July/August 2004 field shutdown will allow significantly higher production and injection rates than what is currently possible. It is estimated that Alpine production rates will gradually reach 115,000 to 120,000 bopd after the shutdown. These rates will be balanced with a projected seawater import rate of 133,000 bwpd. Under this scenario, it is anticipated that average reservoir pressure will increase. Some seawater injection will be maintained during the summer shutdown. Most CD1 injectors will be converted to seawater injection prior to the summer shutdown, to allow re -pressurization of this part of the field, since it is more depleted than CD2, and higher rates are achievable from the eastern area of the field than from the tighter western sands. Based on expected water and gas injection rates, five or six wells at the CD2 pad are likely to reach their seawater pre-injection target of 10-15% HPCV in 2004. Conversions from MI back to seawater will occur based on local field performance. 2.0 Alpine Production and Injection by Month CPAI is planning minor revisions to produced gas volumes based on ongoing metering studies. We expect to finalize and restate gas production during 2004. M Total Month Oil Gas Water Wtr Inj Gas Inj MI Inj Gas Inj MSTBO MMSCF MSTBW MSTBW MMSCF MMSCF MMSCF 02/28/03 2,764.3 3,223.5 20.9 2,673.7 553.7 2,235.5 2,789.2 03/31/03 3,256.0 3,380.7 25.7 2,995.3 773.0 2,146.0 2,919.1 04/30/03 3,121.3 3,343.4 24.0 2,922.1 580.3 2,329.5 2,909.8 05/31/03 3,234.9 3,736.6 29.4 2,891.3 462.8 2,820.1 3,282.9 06/30/03 3,045.7 3,563.0 37.7 2,945.8 422.9 2,711.1 3,134.0 07/31/03 2,482.4 2,678.2 29.0 2,907.0 414.3 1,924.0 2,338.3 08/31/03 2,840.8 3,233.2 33.4 2,878.7 354.1 2,470.6 2,824.7 09/30/03 3,149.0 3,828.0 34.1 2,963.8 738.4 2,623.7 3,362.1 10/31/03 2,772.5 3,760.0 29.2 2,189.6 499.1 2,820.9 3,320.0 11/30/03 3,090.0 3,879.4 20.7 2,887.5 381.8 3,017.0 3,398.8 12/31/03 2,732.1 3,086.4 23.5 3,048.2 307.8 2,300.4 2,608.2 01/31/04 3,251.7 3,678.8 30.2 2,990.7 358.6 2,774.8 3,133.5 CPAI is planning minor revisions to produced gas volumes based on ongoing metering studies. We expect to finalize and restate gas production during 2004. M Annual Surveillance Repoi, Alpine Oil Pool, Collville River Unit March 22, 2004 3.0 Survey Results 3.1 Reservoir Pressure Monitoring During 2003, numerous pressure surveys were conducted in newly drilled and shut in development wells. The Annual Reservoir Pressure Report was submitted to the AOGCC on January 28, 2004 (Form 10-412), it documents all subsurface pressure measurements (interpreted as stable) for Alpine during 2003. The Alpine reservoir is continuously managed to allow for local pressure build up in areas of development drilling while maintaining average pattern pressures at or above the level required for stable production and optimum EOR performance in the rest of the field. Reservoir pressures are estimated from the Alpine full field simulation model as well as from inflow performance relation analysis on all drilled producers. Both approaches are calibrated with actual reservoir pressure measurements collected from static surveys taken in development wells as well as continuous pressure data from the dedicated observation wells when available. Since injector CD2 -35 was redrilled to the 2-35A location, the pressure gauge in Alpine 1 B has been of limited value. The distance between the CD2 -35A wellbore path and the Alpine 1 B bottom hole location is approximately 250 ft. Thus, the pressure observed in 1 B is heavily influenced by choke changes in 2-35A. The gauges in Bergschrund 2A, were not functional during 2003. Work is currently underway to determine the cause of the gauge malfunction, and the necessary steps to repair it. Additional pressure surveys are planned for development wells in the Bergschrund 2A area. Drilling problems, perhaps related to low reservoir pressures in the target area were encountered in five wells during the course of 2003. These occurred in the form of lost circulation events and differential sticking. There are indications that low pressure, when present, is not always ubiquitous throughout the entire pattern volume, but rather local heterogeneity results in low pressure areas due to differential depletion. 3.2 Well Surveillance As documented in the previous annual report, we continue to work with contractors to refine the design of a coil tubing conveyed packer flow meter to improve reliability. These devices offer the best technology to quantitatively evaluate horizontal well injection and production profiles in Alpine development wells. The packer flow meter tool was redesigned in early 2003 to increase the durability of the inflatable packer element. The new tool has been successfully deployed in three injectors and one producer since the redesign with good results. Usable data was recovered from a producer packer flow meter profile for the first time in 2003. In the coming months, we plan to repeat injection profiles on wells receiving water - following -gas cycles to determine if the profile has changed. Injector logging typically consists of a packer flow meter profile and one to two temperature -based logging runs to qualitatively assess the horizontal injection profile. We continue to be encouraged by the generally favorable injection profiles we see in the Alpine Field. Annual Surveillance Report Alpine Oil Pool, Collville River Unit March 22, 2004 4.0 Field Development 4.1 Development Wells Drilled as of February 1, 2004 - 83 wells drilled total: 0 18 CD1 producers 0 18 CD1 injectors 0 21 CD2 producers 0 24 CD2 injectors 0 2 Disposal wells 4.2 Development Drilling Completed in 2003 Sixteen wells were drilled and completed in calendar year 2003, two more than expected. Twelve wells were injectors, 4 were producers. A total horizontal section of 75,226 ft was drilled. Forty-three wells have now been drilled and completed at CD2 as of January 31, 2004. Attachment 7 lists the Alpine producers and injectors drilled to date and their NAD27, ASP4 completion coordinates, for both the beginning and end of the horizontal productive interval in the Alpine sand. Wells drilled in 2003 were located along the northern and southern periphery and the western margin of CD2. Drilling peripheral wells equates to greater offsets and longer wells than have been drilled historically. Operational challenges during 2003 were locally lower reservoir pressures encountered while drilling the western row of injectors (CD2 -55, CD2 -40, and CD2 -30). Circulation was lost during the 7" casing cement jobs in both CD2 -55 and CD2 -30. Both wells were suspended for evaluation and remedial work before returning and drilling to TD. In CD2 -40, low pressures resulted in differentially stuck drill pipe in the Alpine C Interval and loss of a drilling bottom hole assembly (BHA). The well was sidetracked around the BHA and drilled to completion. Drilling along the northern periphery at CD2, the Alpine C Interval thins but maintains good reservoir quality. Well CD2 -06 successfully drilled 7,008 feet (93% in zone) of horizontal section in approximately 20 ft sand with about 100 ft of structural relief. The southern periphery at CD2 is the more distal margin of the Alpine C Interval. Reservoir quality decreases and the interval begins to "shale -out" to inter -bedded sands and silts. This makes it more challenging to keep the horizontal well bore in reservoir quality sand. This is evident in both CD2-36PB1 and CD2 -36. The drilling schedule is continually optimized to allow re -pressurization in areas of development drilling while maintaining sufficient pressure elsewhere to maintain field deliverability and an efficient EOR process. Annual Surveillance Report Alpine Oil Pool, Collville River Unit March 22, 2004 4.3 Development Drilling in 2004 All remaining wells to be drilled at Alpine are located along the periphery of the field. Twelve development wells and one "delineation" well are scheduled to be drilled during 2004. Seven of the wells are planned along the southern margin of CD1, one of which has already been drilled (CD1-07). Five wells are planned at CD2, two along the southern periphery and three along the western margin. One of the wells along the western margin has already been drilled this year (CD2 -43). In addition to the planned development drilling, a delineation well on the northwestern periphery of CD2 is being evaluated. If drilled, this well will assist with a decision to drill additional wells in the area, which is outside the scope of the original 94 well development program. Attachment 8 lists those wells scheduled for 2004, and Attachment 9 is an Alpine net pay map with all wells drilled to date and those planned for the remainder of 2004. In addition, the two remaining wells out of the 94 well development program at CD1 and seven potential peripheral candidate well locations are also identified on Attachment 9. These wells will be further evaluated based on 2004 drilling results for potential drilling in 2005. This plan is subject to change as the drilling schedule is optimized throughout the course of the year. There will be a break in the drilling schedule for approximately two months in the March -April 2004 timeframe, to allow for exploration drilling use of the Alpine drilling rig. Other future breaks in the drilling schedule are also possible. 4.4 Facilities Expansion Evaluation Currently the combined well productivity from all CD1 and CD2 wells exceeds plant capacity. Numerous wells are choked back to limit the field oil production rate. Facility expansions are required to increase the oil production rate. Along with expansion of the oil train, expansion of the water injection system is required to support the higher offtake. These projects will add additional reserves to the EOR project by increasing gas injection rates, water handling limits and the water injection capacity. Two capacity expansion projects; ACX Phase I and ACX Phase II, have been approved by the Alpine PA working interest owners. Additional expansion projects are being studied. The approved expansions are can be summarized as follows. ACX Phase 1 The Alpine Capacity Expansion Project Phase 1 (ACX1) was approved by the Alpine working interest owners in April 2003. Equipment is being transported over this winter's ice road and will be tied into the Alpine facilities during the 2004 summer shutdown. Startup will occur in late 2004. The current Alpine oil production of approximately 100 Mbopd (annual average) is limited by the processing plant capacity and by water injection available for voidage replacement. The ACX1 Project would increase oil production rates by 5,000 bopd (gross). The project consists of adding or upgrading equipment to increase the oil processing capacity and the gas processing capacity, and installing equipment to allow re-injection of produced water into the Alpine formation. Produced water is currently re- injected into the Alpine zone in limited quantities. Without ACX1 the produced water would be disposed of in the Sadlerochit formation as water volumes increase. The II Annual Surveillance Report Alpine Oil Pool, Collville River Unit March 22, 2004 project would increase the capacity of the produced water handling system from the current 10 Mbwpd to 100 Mbwpd. The gas processing capacity will be increased from 130 mmscfd to 160 mmscfd. ACX Phase The ACX2 project will improve the Alpine recovery process. The ACX2 expansion of the seawater injection system allows higher throughput rates and increases cumulative water injection. This results in increased incremental recovery. ACX2 expansion of the gas handling system increases the volume of miscible injectant available for the MWAG flood. This results in a larger cumulative volume of miscible injectant in the reservoir, which results in incrementally higher EOR recovery from the MWAG process. Conclusion Alpine reservoir performance remains strong. Development drilling while maintaining high production rates has been technically challenging, but accomplished with relatively small impact on development expenditures or material affect on long term production capacity or reserves. Surveillance tools and techniques are continuing to improve. We foresee no significant obstacles to continued successful exploitation of the resource at this time. Sincerel , Chris lonzo Alpine Engineering Supervisor cc: Mr. Mark Meyer, Director Alaska Department of Natural Resources Division of Oil & Gas 550 W. 7th Avenue, Suite 8000 Anchorage, Alaska 99501-3560 Ms. Teresa Imm, Resource Development Manager Arctic Slope Regional Corporation 301 Arctic Slope Avenue, Suite 300 Anchorage, Alaska 99518-3035 Mr. Isaac Nukapigak, President Kuukpik Corporation PO Box 187 Nuiqsut, Alaska 99789-0187 Mr. Bill Esco Anadarko Petroleum Corporation PO Box 1330 Houston, Texas 77251-1330 1: Attachment 1 — CRU Boundary as of June, 2003. Colville River Unit Colville Delta Area, Alaska. June, 2003 Unit Boundary Lease Boundary - - - - - - - - Tract Boundary �3 Tract Number 2 4 WLES 0 1 2 4 6 RR04ETERS 01061302A05 Attachment 2 - MWAG conversion status at CD1 CD1-21 5Yv 3J1020p1 17 1'- IJI t 1;', 2001 25.5 k is Tft9r2003 1-[4-2001 FII 1 NTi200 Converted to 141 in Jlune2002 WAG Converted back to SW in CDi-03 SS'd r1 r,2rg1 14.07, Lr, 6xnpn2 15.2 ro :, v 771Jt21tt3 6"i?L 2.1 service as part of strategy. CDi-23 5;V "rcr2CC1 19. t % MI x, -rc1_002 2i 6°, 5'iv Zt2pr2gg3 6 i-e� Converted to MI service in April 2002 as part of WAG strategy. Converted back to SW in Ju 2003 to m6gate rein GOR in offset (CD1-24' July 2003 to mitgate rsing GOR in offset (CDt-10) CDi-261. + 12920C 1 16.6'6 j MI 7262002 120% 5'.V gitSt2003 2 %.°t I Intially a dry gas disposal well until condensate flash drum became functional (January CD 1-05 Dry Gas 12=000 0.3% 6 ?SV 5°20.200- 22.3 6 2001), then on hil injection to maximize recovery. Converted to SW duty in June 2002 to mitigate rising GOR in offsets (CE)1-04 and Cl and since it was estimated that little incremental EOR reserves would be recovered as result of additional Idl injection. CD1-O6 Drf Gas 12 132CC0 87.2°6 permanent upstructure dry gas injector- also used as black -out fuel source Converted to MI service in November 2D01 as part of WAG strategy. Converted back to SIA, CDi-13 SSV 12612rI1 i',r3$b hil 11 222001 20.7% 5`N 1 Vt'r12002 ts.'._n.Ct Gil 10-30;2003 2.2°z duty in November 2002 to mitigate rising GOR in offset(01-111)). Converted back to MI in 2003 as part of WAG strategy. CD1-14 Dry Gas 914!2C01 2`ti MI 9/102001 2= c t C v >as 2B =GG_ €0 -C Irry gas injector. MI injector from September 2001 through January 2002. CDi-16 59V 3ie,2001 14.9°6 tdl eutsfz-0p2 I 11.2% 1 Converted to first cycle MI in November 2002 as part of WAG strategy. CD1-21 5Yv 3J1020p1 17 1'- IJI t 1;', 2001 25.5 k is Tft9r2003 1-[4-2001 FII 1 NTi200 Converted to MI seryice in November 2001 as part of WAG strategy. Converted to chase SW in July 2003 after target slug of 30% HCPV MI was reached- Converted back to MI for 1pressure -Vi 9r1;20tt3 _pct 111 22 16.3% 5Yv 3tt9+2003 2.1 support in October 2003 as SW was required elsewhere. CDi-23 5;V "rcr2CC1 19. t % MI x, -rc1_002 2i 6°, 5'iv Zt2pr2gg3 6 i-e� Converted to MI service in April 2002 as part of WAG strategy. Converted back to SW in Ju 2003 to m6gate rein GOR in offset (CD1-24' CDi-261. + 12920C 1 16.6'6 j MI 7262002 120% 5'.V gitSt2003 2 %.°t I Converted to h1I service in July 2002 as part of WAG strategy. Converted back to SW in 2003 to mitigate rising GOR in offset CDt-27 CD 1-31 IPrYGasI MI I 'l:J2001 I 75.=% 11_ 1tr:><r_rr1T 29.7% CDi-33 5!V I 21MC01 1 Idl 11t5.� CD1-36 svv I 1262cc1 t7.3%I Ml I�.1=6 CDi-37 CD1-39 CD1-d2 SYV 2212001 16.3'ro MI 1f.i°!e ^'<ti I T,2. 20103 3 S'iV 1-[4-2001 25.N'.i MI 2..6% -Vi 9r1;20tt3 _pct 111 22 16.3% 5Yv 3tt9+2003 2.1 CD145I SU I 2i 1F2^k All conversions that occurred in 2003 are underlined in bold Nomenclature: Sea water injection Miscible gas injection 00IMP,Dry gas injector Converted back to MI in 2003 as part of WAG Converted back to MI in 2003 as part of WAG Converted back to Win 2003 as part of WAG Converted to MI seryice iJune 2012 as part Df WAG strategy. Converted back to SW in Ju " 2DD3 to m ate ricinn GOR in offset CDt-36 Converted to hil service in June 2002 as part of WAG strategy. Converted back to SW in 2003 to mitigate rising GOR in offset CD1-38 Converted to MI service in February 2002 as part of WAG strategy. Converted back to SW N September 2003 to mitigate rising GOR in offset CD1A4 Converted back to MI in October 2003 as part of WAG strategy. Attachment 3 - MWAG maturity CD1 CD1 MWAG STATUS CD1-45 CD1-42 SW MI CD1-39 LG CD1-37 CD1-36 CD1-33 CD1-31 CD1-26 CD1-23 CD1-21 CD1-16 CD1-14 CD1-13 CD1-06 CD1-05 CD1-03 CD1-02 CD1-01 0.00 15.00 30.00 45.00 60.00 75.00 90.00 105.00 CUM HCPVI (%) Attachment 4 - MWAG conversion status at CD2 - Alpine MWAG Status - CO2 ELL HPCV injected Comments CD2 -D8 CD2 -12 CD2 -15 CD2 -16 CD2 -17 CD2 -18 CD2 -22 1st Irujection cycle 2nd Injection cycle 3rd Injection cycle 4th trajection cycle Service I Conversion I HPCVI Service I Conversion I HPCV I I Service I Conversion I OEsd SeTvicel Conversion I HPCV CD2 -06 sw I tsrtn+2no3 1 - 1,4% CD2 -D8 CD2 -12 CD2 -15 CD2 -16 CD2 -17 CD2 -18 CD2 -22 SW I 3,'26t20D',� 3Vr 6 [tn;= 7.6'1:, Yv >�i4^Or7 F.,� Gov 7115CZCV.2 1_ 5;'v 1gt3n EtD3 r. ~+_. Sod 6,?,n{IO2 t CD2 -26 CD2 -29I CD2 -32 CD2 -35 �,'u 2•=>+2rr% t � � ; sw 1G'v2C,11 :vv 3r.t�lr:r% > t ls� Ss'v 4J2n126n;: .s �'<. CD2 -36 r'%v 4'2_ r'2,7gs t.:,r-G CD2 -38 SPi 1rni:2r[s2 e<- GD2-k4 CD2 d6 3';r `+711112rx. CD2 -d8 '%i 71[472nG2 t 7° CD2 -4S CD2 -51 6IV 2172.TVT2 4.5% ;i 714_ rlt 4.1 CD2 -55 vs'd t [t.2% 9122'2003 7;232003 3 1011012003 Ell RI2312003 Dry Gas 1011120C2 'v1C-5?b All conversions that occurred in 2003 are underlined in bold Nomenclature: Sea water injection Miscible gas injection Dry gas Dry gas injector Converted to first cycle MI in August 2003, as part of WAG strategy. Converted to first cycle MI in December 2003, as part of WAG strategy. Converted to first cycle MI in October 2003, as part of WAG strategy. Converted to first cycle MI in September 2003, as part of WAG strategy. Converted to first cycle MI in July 2DD3, as part of WAG strategy. Converted to first cycle MI in October 2003, as part of WAG strategy. Converted to first cycle MI in March 2003, as part of WAG strategy. Converted temporarily to dry gas in Oct. 2002, to releave pattern CDt-DF and allow proper MI enrichment. and to test gas flooding potential of tighter CD2 sand. Converted to hill in 20 n3, as Tess dry gas disposal was required field -woe. Converted back to SW in October 2003 as art of WAG strafe Attachment 5 - MWAG maturity at CD2 CD2 MWAG STATUS CD2 -55 CD2 -51 SW CD2 49 Ml LG CD2 -48 CD2 -46 CD2 -44 CD2 -40 CD2 -38 CD2 -36 CD2 -35 CD2 -32 CD2 -29 CD2 -26 CD2 -22 CD2 -18 CD2 -17 CD2 -16 CD2 -15 CD2 -12 CD2 -08 CD2 -06 0 15 30 45 60 CUM HCPVI (%) Attachment 6 — Recovery - throughput response at Alpine TPM Alpine Pattern Performance o sw bt in TPM through 1/31/2004 ♦ gas bt in TPM 100 ♦ CD1 ♦ CD2 90- 80 70 a U = w 60 0 0 50 Z > 40 �- o L ♦ •� 30 • ♦ 20 10- 0 0 0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8 0.9 1 Qtinj [fraction HCPVI] Attachment 7 - All Wells Drilled as of February 1, 2004 Surface Well Name Bottomhole Well Name Well Information Well Service 7" Csg Shoe Start of Completion End of Completion X start I Y start I TD I X end I Y end C D1-01 3 Injector 7752 386223 5977665 10289 384975 5979854 CD1-02 14 Injector 8217 388914 5978054 12773 386773 5982084 CD1-03 21 Injector 7816 387030 5975876 10897 388335 5973121 CD1-04 24 Producer 9444 390285 5979213 13977 392388 5975199 CD1-05 27 Injector 10633 392060 5979100 14515 393833 5975653 C D1-06 82 Injector 13500 395935 5978137 16024 397053 5975880 CD1-09 78 Producer 11894 393604 5979398 15350 395153 5976312 CD1-10 22 Producer 7909 387919 5977328 11693 389639 5973962 CD1-13 23 Injector 8841 389954 5976715 11300 391036 5974524 CD1-14 83 Injector 14073 397422 5974748 18939 399750 5970479 CD1-16 34 Injector 9595 391456 5973711 12600 392819 5971035 C D1-17 77 Producer 13181 395639 5975431 18590 398233 5970693 CD1-21 4 Injector 9049 381897 5979207 11087 380663 5981642 CD1-22 7 Producer 8430 387229 5978470 9236 385833 5981196 CD1-23 36 Injector 11473 394166 5974982 14477 395504 5972306 C D1-24 35 Producer 10771 392946 5974121 13706 394333 5971538 CD1-25 33 Producer 8887 390067 5973033 12147 391614 5970167 CD1-26 32 Injector 8554 388736 5972327 11134 389928 5970058 C D1-27 31 Producer 8500 387434 5971701 11492 388804 5969032 CD1-28 20 Producer 7449 385825 5974800 10468 387228 5972131 CD1-30 10 Producer 9520 380597 5978488 12850 379073 5981447 CD1-31 16 Injector 10388 379306 5977679 14364 377530 5981235 C D1-32 37 Producer 11128 378022 5977019 14353 376466 5979841 CD1-33 19 Injector 7878 384479 5974142 10854 385846 5971484 CD1-34 18 Producer 8410 383109 5973412 11190 384448 5970977 CD1-35 1 Producer 8158 384636 5977159 13450 382165 5981835 CD1-36 2 Injector 7654 383593 5975934 10654 382249 5978602 CD1-37 30 Injector 9095 386288 5970673 12134 387689 5967992 CD1-38 29 Producer 9170 384766 5970331 12240 386136 5967662 CD1-39 28 Injector 10288 383465 5969470 13298 384820 5966793 C D1-40 80 Producer 12042 382644 5967952 15438 384185 5964949 CD1-41 9 Producer 8333 382239 5975219 11170 380948 5977745 CD1-42 15 Injector 9054 380940 5974591 11608 379708 5976828 C D1-43 64 Producer 10065 380436 5972089 12921 381823 5969594 CD1-44 44 Producer 10070 379572 5973840 12811 378333 5976283 CD1-45 17 Injector 9032 381806 5972745 11950 383138 5970171 CD2 -06 70 Injector 9672 371097 5980654 16680 367815 5986842 CD2 -07 72 Injector 10733 373703 1 5981992 1 10868 373652 5982116 CD2 -08 74 Injector 12242 377301 5981635 18050 374588 5986767 CD2 -10 71 Producer 10578 372182 5981985 10702 372141 5982101 Annual Status Update to the , IUnit Plan Colville River Unit Agreement February 20, 2002 Surface Well Name Bottomhole Well Name Well Service 7" Csg Shoe Well Information Start of Completion End X start Y start TD of Completion X end Y end CD2 -12 68 Injector 8677 368888 5978304 13632 366637 5982712 CD2 -13 73 Producer 10595 376177 5980472 14575 374339 5983995 CD2 -14 41 Producer 7671 371963 5975571 11056 370410 5978577 CD2 -15 66 Injector 9610 366147 5977039 14161 364157 5980881 CD2 -16 38 Injector 9529 375990 5977319 12500 374782 5980013 CD2 -17 40 Injector 8184 373143 5976621 8756 372880 5977129 CD2 -18 65 Injector 12112 362842 5975883 18019 360196 1 5981157 CD2 -19 46 Producer 8769 1 375572 5975100 11714 376897 5972473 CD2 -20 69 Producer 9163 369916 5979552 14570 367451 5984361 CD2 -22 42 Injector 7845 370575 5975090 11134 369051 5978002 CD2 -23 67 Producer 9676 367151 5978350 13438 365445 5981699 CD2 -24 76 Producer 10811 364768 5976380 14301 363212 5979501 CD2 -25 43 Producer 8722 369286 5974237 11994 367790 5977144 CD2 -26 47 Injector 8619 374207 5974408 11238 375406 5972081 CD2 -27 125 Injector 12341 377882 5967149 12659 378052 5966887 CD2 -28 39 Producer 8695 374897 5976522 13200 372799 5980502 CD2 -29 45 Injector 9556 376873 5975841 12560 378234 5973167 CD2 -30 55 Injector 11481 365208 5971300 15700 363297 5975058 CD2 -32 50 Injector 8723 367954 5973557 11720 366579 5976218 CD2 -33B 52 Producer 9982 366697 5972759 13078 365223 5975475 CD2 -34 48 Producer 7802 372917 5973731 8755 373367 5972891 CD2 -35A 61 Injector 9063 1 375633 5971746 13500 377673 5967818 CD2 -36 98 Injector 13523 372734 5964056 17663 374637 5960382 CD2 -37 139 Producer 14162 371724 5963070 17085 373037 5960467 CD2 -38 59 Injector 9209 373424 5969394 13010 375164 5966020 CD2 -39 55 Producer 9122 374692 5970192 12651 376369 5967087 CD2 -40 56 Injector 11208 365766 5970205 14250 367107 5967479 CD2 -41 58 Producer 9532 372019 5968832 13024 373637 5965742 CD2 -42 54 Producer 9633 367542 5970978 13138 369171 5967884 CD2 -43 130 Producer 12978 364372 5968348 13106 364410 5968226 CD2 -44 63 Injector 11319 378889 5972087 14555 380338 5969198 CD2 -45 62 Producer 9972 377360 5971508 13402 378988 5968490 CD2 -46 49 Injector 7879 371539 5973093 11000 372970 5970320 CD2 -47 126 Producer 10840 369515 5967325 14580 371256 5964017 CD2 -48 57 Injector 10074 370711 5968227 13622 372304 5965058 CD2 -49 53 Injector 8890 368809 5971733 11874 370200 5969094 CD2 -50 51 Producer 7906 370190 5972559 11624 371794 5969207 CD2 -51 81 Injector 13246 380600 5968569 17320 382495 5964971 CD2 -52 124 Producer 12897 379311 5967805 16881 381146 5964274 CD2 -55 127 Injector 12210 367567 5966559 15238 368970 5963878 CD2 -58 97 Producer 12129 373889 5965219 16389 375844 5961443 Attachment 8 - Planned Wells for 2004 Well Surface Bottom Hole Well Well Type Count Location Location Service Completed: Horizontal 81 CD2 -43 130 Producer Horizontal 82 CD1-07 107 Injector Horizontal To Be Drilled: 83 CD1-46 102 Injector Horizontal 84 CD1-08 106 Producer Horizontal 85 CD2 -57 96 Injector Horizontal 86 CD2 -31 134 Producer Horizontal 87 CD2 -53 95 Producer Horizontal 88 CD2 -05 132 Producer Horizontal CD2-NW-Periph Delineation 89 CD1-11 105 Injector Horizontal 90 CD1-12 123 Producer Horizontal 91 CD1-15 103 Producer Horizontal 92 CD 1-47 104 Injector Horizontal