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Home My WebLink About2004 Alpine Oil PoolConocoPhillips Alaska, Inc. Post Office Box 100360 Anchorage, Alaska 99510-0360 Chris Alonzo Alpine Engineering Supervisor Phone (907) 265-6822 Fax: (907) 265-1515 April 5, 2004 Alaska Oil and Gas Conservation Commission Attention: Mr. John Norman 333 West 7th Ave, Suite 100 Anchorage, AK 99501 RECEIVED APR - 7 2005 Alaska Oil & Gas Cons. ComrNssion Anchorage Subject: Annual Surveillance Report for the Alpine Oil Pool of the Colville River Unit 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 Unit as of March 2, 2005. Attachment 1 illustrates the current unit boundary, which was revised in February of 2004. 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) 263-4767. 1.0 Progress of Recovery Projects 1.1 Average Metrics for 2004 - Average oil production rate 98.6 MBOPD - Average gas production rate 122.2 MMSCFD - Average water production rate 2.0 MBWPD - Average gas injection rate 106.6 MMSCFD - Average water injection rate 101.8 MBWPD Annual Surveillance Report for Alp. April 5, 2005 1.2 Cumulative Volumes Produced and Injected through January 2005 Cumulative oil production: Cumulative gas production: Cumulative water production: Cumulative gas injection: Cumulative water injection: 1.3 Surface Facility projects Update 144,582,825 STBO 165,654,470 MSCF 1,410,240 STBW 144,473,450 MSCF 134,613,542 STB The following projects were successfully completed during the course of 2004: - Construction of an ice road and pad - ACX Phase 1 Expansion - ACX Phase 2 Expansion -3 rd Stage Gas Cooler Installation - CD2 Test Separator Installation - Vapor Recovery System Installation - Emergency Power System Upgrade The highest activity level in 2004 occurred between July 19 -August 18, 2004, when the plant was shut down to complete both ACX phase 1 and 2 capacity expansions and perform annual maintenance. The expansions increased Alpine processing capacity by 35,000 bopd, 45,000 bwpd, and 50 mmscfpd. Though essentially complete and operational, the ACX Phase 2 project will be fully completed in July, 2005 with commissioning of the new crude cooler package. Negotiations continue with the village of Nuiqsut and the North Slope Borough toward an agreement regarding operation of a gas -conditioning skid at Alpine's Central Processing Facility. The pre -fabricated skid was installed in April and is designed to condition natural gas for shipment to the village of Nuiqsut. The upgrade of the emergency power system was not completed in 2004. Final construction and functional check-out with start-up and commissioning wrapped up in February, 2005. 1.4 Miscible Water Alternating Gas Flood Management during 2004 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 2004 through January 2005. 2 Annual Surveillance Report for Ali. April 5, 2005 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 50%. Three wells have completed the target MI slug of approximately 30% HCPV (CD1-05, CD1-14, CD1-21). Nine wells have completed or are on their 2"d cycle of MI, after having been temporarily converted to seawater injection in order to alleviate rising GOR trends in offset producers. Two of these wells, CD1-02 and CD1-03, are on their 3rd cycle of MI. Fifteen MWAG injectors have completed or are on their 2nd cycle of seawater injection. Five wells, CD1-01, CD1-02, CD1-03, CD1-13, and CD1-21 have completed or are on their 3rd cycle of seawater injection. Recently drilled wells, CD1-07, CD1-11, CD1-20, and CD1-46 are on their first cycle of seawater and will be converted to MI injection when they approach a target seawater slug size of 15% HCPV. The main drivers behind the rate of maturation of the different patterns are field offtake, local re -pressurization schemes to allow for efficient development drilling, local voidage balance requirements, seawater availability, MI enrichment requirements and the necessity to control GOR within compressor limits. 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 14% overall throughput. This is due to a combination of factors: Production started up later than at CD1, and the offtake and throughput rates at CD2 have been slower due to the ongoing development drilling. Also, larger reserves are present at CD2, and the lower rock quality will not allow the same production rates as seen at CD1. Twenty-seven MWAG injectors are now in place at CD2. Thirteen of these are on their first cycle of seawater injection. Thirteen wells have completed or are on their first cycle of MI injection. Two wells, CD2 -17 and CD2 -44, are on their 2nd cycle of seawater injection. The good response observed in offset producers, suggest that CD2 ought to deliver similar recovery factors as seen at CD1. Three wells (CD2 -18, CD2 -54, and CD2 -56) have been completed in the Alpine A sand. These three wells are on their 1St cycle of seawater injection. No problems with injectivity have been observed and the good response to offset producers that are completed in the A sand suggest that the A sand should also deliver similar recovery factors as seen in the C sand. Overall field response to the MWAG remains excellent. Attachment 6 shows the recovery -throughput relation from all active MWAG patterns, and attests to the effectiveness of the EOR flood at Alpine. 1.5 Injectivity of wells on 2"d MWAG cycle Previous observations pointed to approximately 50% decrease in seawater injectivity following gas injection. The loss in injectivity was expected and the magnitude is in line with original estimates. Further studies will improve our knowledge on this matter. It is 3 Annual Surveillance Report for Alp. April 5, 2005 not anticipated that the decrease in seawater injectivity will pose any significant problems to the long term offtake plans at Alpine. 1.6 M/ 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 has grown from 15 mmscf/d to 20 mmscf/d, as a result of commissioning a second condensate pump. Installation of this pump was a part of the facility expansion work during the summer. 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 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 2005 In 2005, reservoir management at Alpine will be driven by field wide production offtake and local re -pressurization schemes for development drilling. The plant upgrades that were implemented during the July/August 2004 field shutdown allow significantly higher production and injection rates than what was available in the past. It is estimated that Alpine production rates will average 115,000 bopd before the annual summer shutdown, scheduled for July. Alpine production rates are predicted to ramp up to 125,000 bopd after the annual shut -down. Offtake rates will be voidage-balanced with anticipated seawater import rates of 129,000 — 132,000 bwpd for the purpose of building reservoir pressure. Based on MWAG optimization studies and expected water and gas injection rates, a greater number of MWAG conversions will be performed in 2005 than in 2004. Eight to ten wells at CD1 and CD2 pads are likely to reach their seawater pre-injection target of 10-15% HPCV in 2005. Similarly, conversions from MI back to seawater will occur based on local field performance, in an effort to maximize oil throughput under current facility gas constraints. 4 Annual Surveillance Report for Alp April 5, 2005 2.0 Alpine Production and Injection by Month CPAI has completed minor revisions to produced volumes as a result of metering studies and well test corrections. The finalized volumes will be formally resubmitted in 2Q 2005. 3.0 Survey Results 3.1 Reservoir Pressure Monitoring Numerous pressure surveys have been conducted both in new wells as well as in wells that were shut in for reservoir pressure management issues. The reservoir is continuously being managed to allow for local pressure build up in areas of development drilling whilst 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. During the Summer 2004 facilities expansion project shutdown, nearly all producer and injector static pressures were taken either by pressure fall-off tests (injectors) or running bottomhole pressure gauges. Continuous pressure data from the dedicated Alpine 1 B and Bergschrund 2A observation wells is no longer considered necessary with the near development completion of Alpine. The gauges in the Bergschrund 2A were not functional during 2003 and 2004. Plug and abandonment operations are underway on these two wells and will be completed before the end of ice road season. The drilling problems related to low local reservoir pressures in 2003 were eliminated in the 2004 drilling program due to more diligent reservoir pressure management. The Annual Reservoir Pressure Report for Alpine was issued to the AOGCC on January 19, 2005, and contains all reservoir pressure data gathered during the course of 2004. Total Month Oil Gas Water Wtr Inj Gas Inj MI Inj Gas Inj MSTBO MMSCF MSTBW MSTBW MMSCF MMSCF MMSCF 02/29/04 3,032.5 3,528.8 33.6 2,816.4 313.7 2,697.1 3,011.8 03/31/04 3,342.0 4,161.5 72.9 2,954.7 252.5 3,394.8 3,647.3 04/30/04 3,166.5 3,945.6 74.5 2,930.9 399.2 3,061.2 3,460.3 05/31/04 3,300.8 3,842.6 48.3 2,063.7 346.0 3,019.8 3,365.8 06/30/04 3,085.9 3,778.2 23.0 2,312.9 477.5 2,809.4 3,287.0 07/31/04 1,679.3 2,204.9 9.5 2,917.8 407.3 1,475.3 1,882.6 08/31/04 1,360.1 1,462.6 20.5 3,930.2 142.0 1,012.1 1,154.0 09/30/04 3,282.9 4,673.5 86.5 4,024.4 553.5 3,612.4 4,165.9 10/31/04 3,513.6 4,593.7 90.2 3,766.2 485.7 3,607.9 4,093.6 11/30/04 3,485.8 4,383.8 123.3 2,662.5 472.5 3,433.1 3,905.6 12/31/04 3,593.6 4,494.4 133.2 3,878.1 473.9 3,452.1 3,926.0 01/31/05 3,701.0 4,171.6 153.7 4,173.4 442.9 3,152.8 3,595.7 CPAI has completed minor revisions to produced volumes as a result of metering studies and well test corrections. The finalized volumes will be formally resubmitted in 2Q 2005. 3.0 Survey Results 3.1 Reservoir Pressure Monitoring Numerous pressure surveys have been conducted both in new wells as well as in wells that were shut in for reservoir pressure management issues. The reservoir is continuously being managed to allow for local pressure build up in areas of development drilling whilst 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. During the Summer 2004 facilities expansion project shutdown, nearly all producer and injector static pressures were taken either by pressure fall-off tests (injectors) or running bottomhole pressure gauges. Continuous pressure data from the dedicated Alpine 1 B and Bergschrund 2A observation wells is no longer considered necessary with the near development completion of Alpine. The gauges in the Bergschrund 2A were not functional during 2003 and 2004. Plug and abandonment operations are underway on these two wells and will be completed before the end of ice road season. The drilling problems related to low local reservoir pressures in 2003 were eliminated in the 2004 drilling program due to more diligent reservoir pressure management. The Annual Reservoir Pressure Report for Alpine was issued to the AOGCC on January 19, 2005, and contains all reservoir pressure data gathered during the course of 2004. Annual Surveillance Report for All, April 5, 2005 3.2 Well Surveillance The coil tubing conveyed packer flow meter was run in 4 wells in early 2004 (3 injectors, 1 producer) to help further develop an understanding of the horizontal open hole fiowiinjection contributions. 4.0 Field Development 4.1 Development Wells Drilled as of February 1, 2005 98 wells drilled total: o 21 CD1 producers o 22 CD1 injectors o 26 CD2 producers o 27 CD2 injectors o 2 Disposal wells 4.2 Development Drilling Completed in 2004 Fifteen wells were drilled and completed in calendar year 2004, one more than expected. Seven wells were injectors, eight were producers. A total horizontal section of 59,523 ft was drilled. Fifty-three wells at CD2 and forty-three wells at CD1 have now been drilled and completed as of January 31, 2005. 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. Eight of the wells drilled in 2004 were located along the northwestern, southern and western margins of CD2. Seven wells were located along the southern margin of CD1. Drilling along the southern periphery of CD1 demonstrated that the Alpine C interval thins dramatically in this area but maintains very good reservoir quality to the edge of the reservoir. Several of the southern CD1 wells tested the southern limit of the Alpine C Interval. Alpine wells CD2 -53 and CD2 -57 filled in the existing patterns along the southern row of CD2. Wells drilled along the southern periphery at CD2 typically encounter the more distal facies of the Alpine C Interval. Reservoir quality generally decreases in this area as the interval begins to "shale -out" to inter -bedded sands and silts. Five wells were drilled along the western periphery of CD2 including CD2 -31, the first dedicated horizontal MWAG producer in the Alpine A sand. This well was drilled as the offset to injector CD2 -18 drilled in 2003 which was later deemed to have been drilled primarily within the Alpine A interval. This well pair has proven the commerciality of the Alpine A interval along the western margin of the field. The current stabilized production rate for CD2 -31 is approximately 2,500 bopd. Four additional wells (CD2 -05, CD2 -43, no Annual Surveillance Report for Alp. April 5, 2005 CD2 -54, and CD2 -56) drilled along the western margin have targeted the sands in the Alpine A interval as well as the Alpine C interval which thins to the west over the stratigraphically lower Alpine A interval. Wells CD2 -05 and CD2 -56 were drilled as multi- lateral wells to capture both Alpine C and Alpine A reserves. Well CD2 -09 was the first well drilled as part of the NW -peripheral program outlined last year. This well tested the limits of the Alpine C interval and is completed as a producer in both the Alpine C and A intervals. Drilling peripheral wells equates to greater offsets and longer wells than have been drilled historically. Continued 2005 drilling along the western periphery will develop the limits of the reservoir that can be reached from CD2. Beyond 2005, future development of the Alpine A interval will require drilling from the CD -5 pad location as part of the proposed Alpine West development program. 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. In addition, the 2005 drilling schedule has been optimized to begin development drilling of the Fiord and Nanuq satellite fields. 4.3 Fracture stimulations in 2004-2005 Three fracture stimulations have been performed in the past year. CD2 -37 was the first fracture stimulation performed in March, 2004 to enhance the well's productivity. Two additional fracture stimulations, CD2 -24 and CD2 -33B, were performed in February, 2005 to expand on the success of CD2 -37 and determine the applicability of horizontal fracture technology at Alpine. To date, CD2 -24 and CD2 -3313 are performing well. If the wells continue to perform favorably, additional stimulations will be considered for the 2006 ice road season. 4.4 Development Drilling in 2005 The majority of the remaining wells to be drilled at Alpine are located along the periphery of the field. Eight peripheral development wells and two horizontal extensions are scheduled to be drilled in 2005; all drilled from the CD2 pad. Five of the wells are planned in the Northwest area; two of the wells (CD2 -03 and CD2 - 04) will target the Alpine C interval as penetrated in offset wells CD2 -06, CD2 -12 and CD2 -20. The remaining four wells (CD2 -02, CD2 -11, CD2 -21 and CD2 -59) target the Alpine A Sand interval penetrated in offset wells CD2 -18 and CD2 -31. Along the Southwestern margin, CD2 -60 will be drilled to provide injection support to offset Alpine C producer CD2 -37 located to the east. This well will include a pilot hole and if the Alpine A is present, a multilateral leg in the Alpine A interval to provide support for current and potential future offset Alpine A production to the west. The remaining peripheral well planned to be drilled in 2005 is CD2 -01. This well is a planned producer located east of the CD2 -08 injector and Alpine #3 exploration well. 7 Annual Surveillance Report for All., April 5, 2005 Extensions are planned for existing horizontal wells CD2 -17 and CD2 -34. When these wells were originally drilled, both wells were TD'd early due to severe lost circulation attributed to a combination of intersected faults/fractures and low reservoir pressure. Since that time, we have demonstrated that fluid loses in fault and fracture zones can be mitigated by increased reservoir pressure. This has been proven by successfully re- entering and extending other wells TD'd early due to similar circulation issues at CD2 (CD2 -45). Both these planned extensions will target sands in the Alpine C interval. Attachment 8 lists those wells scheduled to be drilled in 2005, and Attachment 9 is an Alpine net pay map with all wells drilled to date and those planned for the remainder of 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 three months in the February -May, 2005 timeframe, to allow for exploration drilling use of the Alpine drilling rig and to commence drilling at the CD3 drillsite (Fiord). The proposed Alpine drilling program is expected to be completed by early November, 2005 with possible extensions to select wells based on updated mapping and reservoir simulation. 4.4 Facilities Expansion Evaluation Results and Update Prior to the summer of 2004, the combined well productivity from CD1 and CD2 regularly exceeded the plant's capacity. Various wells were choked from time to time to manage the oil production rate. Major facility expansion was required to increase the oil rate. Concurrent with expansion of the oil train, expansion of the seawater injection system was needed to support higher offtake rates. The 2004 expansions added additional reserves from the EOR project by increasing gas and water injection rates. The ACX Phase I and Phase II projects have now been essentially completed. One additional major plant modification, ACX3, has recently been funded, and upgrades to the plant emergency power system are close to completion as of this report. The status of these facility expansions are discussed below. ACX Phase 1 The Alpine Capacity Expansion Project Phase 1 (ACX1) was approved by the Alpine working interest owners in April 2003. The expansion project was completed during the month-long 2004 summer shutdown. The ACX1 Project increased oil production rates by 5,000 bopd (gross). The project increased oil and gas processing capacity, and enabled re-injection of produced water into the Alpine formation. ACX1 increased the produced water handling system from 10 Mbwpd to 100 Mbwpd, and gas processing capacity from 130 mmscfd to 160 mmscfd. Annual Surveillance Report for All April 5, 2005 ACX Phase 2 The Alpine Capacity Expansion Project Phase 2 (ACX2) was approved by the Alpine working interest owners in February 2004. Building on ACX1, the ACX2 project consisted of adding or upgrading equipment to increase the oil processing capacity to 140 Mbopd rate (at watercuts less than 1 %), added another 20 MMcfd of gas processing capacity (to 180 mmscfd total), and expanded the seawater injection capacity to 133 Mbwpd (from 98 Mbwpd). The ACX2 seawater expansion upgrades planned for 2004 were completed during the summer shutdown in August, 2004. The final oil capacity upgrades will not be fully implemented until June, 2005 with installation of the crude oil trim coolers. The trim coolers will be shipped to the site during the winter ice road season and final hook-ups will be completed during the summer maintenance shutdown. The ACX2 project enhances the Alpine recovery process. The seawater injection system allows higher throughput rates and increases cumulative water injection which results in increased incremental recovery. ACX2 expansion of the gas handling system increases the volume of miscible injectant available for the MWAG flood which results in a larger cumulative volume of miscible injectant in the reservoir and therefore incrementally higher EOR recovery from the MWAG process. ACX Phase 111 In January 2005, the Alpine working interest owners approved the Alpine Capacity Expansion Project Phase 3 (ACX3). The ACX3 project will install a stabilizer column, fired heater, reflux drum, overhead condenser, reboiler, and a feed/bottoms exchanger at the Alpine Central Facility. The primary purpose of the stabilizer and associated equipment is to optimize Alpine, Fiord CD3, Nanuq CD4 and any future WNS enhanced oil recovery projects. In addition, the stabilizer will add value and reserves by recovering and selling heavier condensate components that would otherwise be re -injected into the reservoir as part of the MI. ACX3 is expected to startup in mid -2006 with initial incremental production of 4MBOPD. Emergency Power Upgrade Construction and tie-in is underway to replace the original emergency power generators at Alpine. In 2000, dual Cummins Wartsilla diesel generators were placed in service at Alpine to provide emergency black start power. With plant power demands increasing in response to the upgrades described above, it became necessary to replace the diesel units with higher capacity turbine generator packages. On the 2004 ice road, dual Solar turbines were shipped over to Alpine. Construction commenced following the summer shutdown which focused on ACX1 and ACX2 construction. Work is now wrapping up and the new units began service in March. The original power packages will be taken out of service during the commissioning phase of the project. Conclusion Alpine reservoir performance remains strong. Development drilling will be completed in 2005 with possible extensions to follow in 2006. Surface facility projects have provided additional capacity to Alpine. The MWAG EOR project will continue throughout 2005 based on the excellent response seen to date. Maintaining high production rates has been technically challenging, but accomplished with relatively small impact on 0 Annual Surveillance Report for Alp.. April 5, 2005 development expenditures or material affect on long term production capacity or reserves. We foresee no significant obstacles to continued successful exploitation of the resource at this time. Sincere 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 10 Attachment 1 — CRU Boundary as of February, 2004 ConocoPhillips Alaska, Inc. Exibit B Colville River Unit Colville Delta Area, Alaska. July 20, 2004 1T �i7 an zuwn� ±s4.ar x.74; (i 73 (t 72) 108 ME „ 11 it _ "1t I 1 11 R5E T 13 �N 3i 17 6 11 85 1 84 70 0 Y03 88 ® I 1 arxa.�s -y�n 10 1T�7? 16 '-^ arisar�,n ansxs>9 10) 12 _ R3E 17 189V 21 79 117 18 I Y6 „ 13 12 N 38 1 37 aDi]BT)'.2 A[M. a�Ly@]090 a01�'uu`.9 :?515r A[kJl'nfE aIX..90�1': 42 ® 40 ® (.451) 63 51 52 nxxw;e aa.msssv ,.,_�r ate, 23 5 57 76 741 72 Q I ® 1 ® ® 87 1 77 78 ® 81 av rn a�r�aun I 11 i78 l 2 izs eo.x+xaz 12 1 i 128 Unit Boundary -",;�d7 a�,��, ao , R4E Lease Boundary - - - - - - - - Traci Boundary Tract Number 0 1 I 4 WLES 0 I 2 4 6 KAOMETEFS 04072001A00 11 Attachment 2 - MWAG conversion status at CD1 Alpine MWAG Status - CD1 CDt-01 SW HPCV Injected T7% 11 [H] 1st Injection cycle 2nd injection cycle 3rd Injection cycle Injection cycle 5th Injection cycle 6th Injection gcie Service Conversion HPCV Conversion HPCV Conversion HPCVnversion HPCV Service Pica ff4tCh. Conversion HPCV Conversion HPCV Service -9 Date In ed Date In ted Date in acted Date in ed Date in Service Date in d CDt-01 SW 1/25/2001 1 T7% 11 MI 10%19/2001 1 5 59-° 11 SW 1 4/4/2002 1 9.5% 11 MI 720;2003 J -9 SW 6/11/2004 1 5.9% CDt-02 SW 2/7/2001 14.3% MI 12i2112001 15.8% SW 7/19/2002 14.5°!o MI 10130/2003 9.39% SW 7/3/2004 5.8% MI 11/23/2004 1.6% CDt-03 SW 4/10/2001 14.4°!° MI 6/5/2002 16 4 % SW 7/19/2003 7.0% MI 12/19/2003 4.8 % SW 4/29/2004 6.1 % MI 11/23/2004 1.0% CD1-05 Dry Gas 12/22/2000 0.2% MI 1/1/2001 1 47.1 % SW 6/23/2002 33.8% CDi-06 Dry Gas 12/13/2000 150.7% CD1-07 SW 7/13/2004 Z9% CD1-13 SW 1/25/2001 10.1 % MI 11/2212001: SW 1 11/17/2002 11.8% 11 MI 10/30/2003 4.9°/ SW 6/12/2004 3.2% CDi-14 Dry Gas 9/412001 0.2% MI 9/10/2001 _ Dry Gas 1 1/29/2002 85.89/6 CD1-16 SW 3/8/2001 13.6% MI 11116/2 SW 7/3/2004 24% CD1-21 SW 3/10/2001 19.0% MI 11/7/2 SW 7/19/2003 6.4% MI 12/17/2003 6.7% SW 6/12/2004 2.3% CD1-23 SW 3/30/2001 15.0% MI 4/312 SW 7/20/2003 1 10.9% 1 MI 10/312004 2.6% CDt-26 SW 1/252001 14.1% MI 7/26/2002 1 1AW I I SW 1 9/19/2003 10.3% CDt-31 Dry Gas 12/7/2000 44% MI 3/3/2001 11 3% SW 10/6/2001 20.4% MI 10/2112003 2.7 % SW 4/29/2004 4 2°6 CDi-33 SW 2/18/2001 147% MI 11/2912002 13.8% SW 7/5/2004 CDt-36 SW 125/2001 16.5% MI 7/19/2003 CDt-37 SW 2/20/2001 16.7% MI 6/23/2002 1569% SW 7/21/2003 6.7% CDt-39 SW 1/252001 22.1% MI 6/25/200 22.0% SW 9/19/2003 10.0% MI 10;31/2004 CD7-42 SW 1/25/2001 1 10.8% 1 MI 2/28/2002 18.2% SW 9/19/2003 6.3% MI 10/31,2004 0.796 CDi-45 SW 2/2/2001 16.7% MI 2/10/2003 10.2% SW 7/6/2004 2.8% CD1-46I SW J 8/28/2004 1 1.440 Nomenclature: SW Sea water injection Miscible gas injection D s Dry gas injector 12 Attachment 3 - MWAG maturity CD1 CD1 MWAG STATUS CD1-46 SW C01-45 mommlimm MI CD1-42 ! �jm LG Col -3s CD1-37 CD1-36 CD1-33 CD1-31 CD1-26 CD1-23 CD1-21 C01-20 CD1-16 CD1-14 CD1-13 CD1-11 CD1-07 CD1-06 CD1-05 CD1-03 CD1-02 CD1-01 0.00 15.00 30.00 45.00 60.00 75.00 90.00 105.00 120.00 135.00 150.00 165.00 CUM HCPVI(%) 13 Attachment 4 - MWAG conversion status at CD2 Alpine MWAG Status - CD2 WELL Service 1st Injection cycle Conversion HPCV Date injected Service HPCV injected 2nd Injection cycle Conversion HPCV Date injected Service 3rd Injection cycle4th Injection cycle Conversion HPCV Conversion HPCV Date injected Service Date injected CD2 -06 SW 11/10/2003 17.2% SW 2/6/2004 13.4% SW 3/25/2003 13.5% SW 6/25/2003 20.5% SW 2/24/2002 9.8% SW 9/25/2002 12.1% SW 3/5/2002 15.6% SW 10/3012003 8.5% SW 6/8/2002 12.4% SW 2/22/2002 121% SW 1/8/2004 5.5% SW 10/30/2002 8.3% SW 2/3/2004 4.5% SW 3/31/2002 12.4% IF SW 4/26/2003 12.1% SW 4/28/2003 7.4% SW 10/17/2002 11.4% SW 9/20/2003 3.5% SW 10/22/2002 9.6% SW 5/30/2002 1 11.5% SW 7/19/2002 1 11.2%IF MI MI MI MI MI MI MI MI MI MI MI MI MI 10/30/2004 3/28/2004 10/3/2004 8/6/2003 12/19/2003 10/30/2003 9/22/2003 7/23/2003 10/10/2003 9/23/2003 1 9/21/2003 1 6/10/2004 1 10/2/2004 1 3.0% 12.3% 5.7% 10.4% 11.8% 9.8% SW 13.0% 10.8% 11.6% 6.4% 7.7% SW 4.3 % 1.3°% 10/3012004 7/9/2004 0.9% 5.2% CD2 -07 CD2 -08 CD2 -12 CD2 -15 CD2 -16 CD2 -17 CD2 -18 CD2 -22 CD2 -26 CD2 -27 CD2 -29 CD2 -30 CD2 -32 CD2 -35 CD2 -36 CD2 -38 CD2 40 CD2�14 CD2 46 CD2 -48 CD2 49 SW 1 2/22/2002 1 4.6% 1 D Gas 10/11/2002 1 4.6% JF Lull 4/17/2003 1 20% SW 1 10/22/2003 J 3.6% CD2 -51 SW SW SW SW SW 7/4/2003 11/24/2004 12/2312003 11/19/2004 6/23/2004 10.5% 3.8% 2.1% 1.3% 2.9% CD2 -54 CD2 -55 CD2 -56 CD2 -57 14 Attachment 5 - MWAG maturity at CD2 CD2 MWAG STATUS CD2 -56 SW CD2 -55 MI CD2 54 LG CD2 -51 CD2 -49 CD2 -48 CD2 -46 CD2 -44 CD2 -40 CD2 -38 CD2 -36 CD2 -35 CD2 -32 CD2 -30 CD2 -29 CD2 -27 CD2 -26 CD2 -22 CD2 -18 CD2 -17 CD2 -16 CD2 -15 CD2 -12 CD2 -08 CD2 -07 CD2 -06 0.00 15.00 30.00 45.00 60.00 CUM HCPVI (9/4 15 Attachment 6 — Recovery - throughput response at Alpine 16 TPM Alpine Pattern Performance o sw bt in TPM through 12/31/2004 • gas bt in TPM 100 ♦ CD1 ♦ CD2 90 80 5, 70 IL U Z 60 e C c�a 50 w_ c 40 ♦ ami e 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] 16 Attachment 7 - All Wells Drilled as of February 1, 2005 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 CD1-01 3 Injector 7752 386226 5977666 10289 384975 5979854 CD1-02 14 Injector 8201 388914 5978054 12773 386773 5982084 CD1-03 21 Injector 7816 387016 5975903 10897 388337 5973122 CD1-04 24 Producer 9444 390285 5979213 13977 392388 5975199 CD1-05 27 Injector 10633 392065 5979111 14515 393810 5975646 CD1-06 82 Injector 13500 395921 5978194 16024 397043 5975933 CD1-07 107 Injector 13477 395838 5971680 17542 397737 5968095 CD1-08 106 Producer 12515 394559 5970944 15837 396092 5967999 CD1-09 78 Producer 11894 393604 5979402 15350 395153 5976315 CD1-10 22 Producer 7909 387919 5977328 11693 389639 5973962 CD1-11 105 Injector 12293 393432 5969790 15057 394737 5967356 CD1-12 123 Producer 11656 392008 5969456 12912 392582 5968340 CD1-13 23 Injector 8841 389949 5976723 11300 391036 5974524 CD1-14 83 Injector 14073 397423 5974752 18939 399752 5970483 CD1-16 34 Injector 9595 391456 5973711 12600 392819 5971035 CD1-17 77 Producer 13181 395639 5975431 18590 398233 5970693 CD1-18 103 Producer 11382 389206 598235 15056 390928 5964996 CD1-20 104 Injector 10634 389768 5969450 16114 392499 5964709 CD1-21 4 Injector 9049 381896 5979206 11087 380972 5981020 CD1-22 7 Producer 8430 387229 5978470 9236 386794 5979148 CD1-23 36 Injector 11473 394161 5974990 14477 395504 5972306 CD1-24 35 Producer 10771 392946 5974121 13706 394333 5971538 CD1-25 33 Producer 8887 390067 5973033 12147 391614 5970167 CD1-26 32 Injector 8554 388729 5972343 11134 389929 5970059 CD1-27 31 Producer 8500 387429 5971694 11492 388770 5969018 CD1-28 20 Producer 7449 385822 5974801 10468 387229 5972131 CD1-30 10 Producer 9520 380597 5978488 12850 379073 5981447 CD1-31 16 Injector 10388 379306 5977679 14364 377530 5981235 CD1-32 37 Producer 11128 378022 5977019 14353 376466 5979841 CD1-33 19 Injector 7878 384485 5974129 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 383597 5975923 10654 382248 5978601 CD1-37 30 Injector 9095 386283 5970682 12134 387689 5967992 CD1-38 29 Producer 9170 384724 5970395 12240 386139 5967673 CD1-39 28 Injector 10288 383468 5969466 13298 384825 5966783 CD1-40 80 Producer 12042 382637 5967963 15438 384188 5964948 CD1-41 9 Producer 8333 382239 5975220 11170 380948 5977745 CD1-42 15 Injector 9054 380961 5974612 11608 379729 5976849 CD1-43 64 Producer 10065 380436 5972089 12921 381823 5969594 CD1-44 44 Producer 10070 379572 5973840 12811 378333 5976283 CD1-45 17 Injector 9032 381802 5972763 11950 383139 5970169 CD1-46 102 Injector 11334 387838 5967599 15187 389598 5964174 CD2 -05 132 Producer 13712 363517 5970008 17816 361616 5973641 CD2 -06 70 Injector 9672 371098 5980645 16680 367816 5986833 CD2 -07 72 Injector 10857 373650 5982084 14977 371786 5985755 CD2 -08 74 Injector 12242 377278 5981611 18050 374565 5986743 17 CD2 -09 Producer 12617 365177 5982158 16094 363562 5985233 CD2 -10 71 Producer 10702 372139 5982079 14475 370284 5985362 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 9830 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 362855 5975882 18019 360209 5981156 CD2 -19 46 Producer 8769 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 12461 377930 5967068 18250 380637 5961965 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 365217 5971303 15700 363306 5975062 CD2 -31 134 Producer 13598 361069 5974966 18131 358947 5978966 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 1 9063 375633 5971746 13500 377673 5967818 CD2 -36 98 Injector 1 13523 372731 5964073 17663 374634 5960399 CD2 -37 139 Producer 14162 371721 5963095 17085 373038 5960491 CD2 -38 59 Injector 9209 373424 5969394 13010 375164 5966020 CD2 -39 55 Producer 9122 374692 5970192 12651 376369 5967087 CD2 -40 56 hector 11208 365775 5970211 14250 367117 5967484 CD2 -41 58 Producer 9532 372019 5968832 13024 373637 5965742 CD2 -42 54 Producer 9633 367542 5970978 13138 369171 5967884 CD2 -43 130 Producer 13106 364417 5968231 19040 367196 5962998 CD2 -44 63 Injector 11319 378889 5972087 14555 380338 5969198 CD2 -45 62 Producer 9972 377360 5971508 13402 378989 5968491 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 7909 370191 5972556 11624 371794 5969207 CD2 -51 81 Injector 13246 380577 5968583 17320 382471 5964985 CD2 -52 124 Producer 12897 379292 5967820 16881 381127 5964289 CD2 -53 95 Producer 12394 376772 5966066 16985 378960 5962036 CD2 -54 Injector 14378 361169 5970560 18250 359460 5974033 CD2 -55 127 Injector 12210 367573 5966569 15238 368976 5963888 CD2 -56 In ector 14391 362859 5967271 19554 365279 5962714 CD2 -57 96 Injector 12642 375598 5965124 16433 377321 5961749 CD2 -58 97 Producer 12129 373883 5965245 16389 375838 5961468 W Attachment 8 - Planned Wells for 2005 Well Surface Well Well Type Count Location Service Completed February, 2005: 98 CD2 -21 Producer Horizontal To Be Drilled: 99 CD2 -59 Injector Horizontal 100 CD2 -60 Injector Horizontal 101 CD2 -03 Producer Horizontal 102 CD2 -11 Injector Horizontal 103 CD2 -02 Injector Horizontal 104 CD2 -01 Producer Horizontal 105 CD2 -04 Injector Horizontal To Be Extended CD2 -17x Injector Horizontal CD2 -34x Injector Horizontal 19 Attachment 9 - Alpine Development: drilled and planned wells Wells drilled in 2004 are indicated as thick dark green (producers) and thick dark blue (injectors) lines. The wells planned for 2005 are those drawn up as red lines. Wells drilled prior to 2004 are indicated as thin dark green (producers) and thin dark blue (injectors) lines. 20