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Home My WebLink About2005 Alpine Oil PoolConocoPhillips Alaska, Inc. Post Office Box 100360 Anchorage, Alaska 99510-0360 Chris Alonzo Supervisor, WINS Base Phone (907) 265-6822 Fax: (907) 265-1515 April 4, 2006 Alaska Oil and Gas Conservation Commission Attention: Mr. John Norman 333 West 7th Ave, Suite 100 Anchorage, AK 99501 RECEIVED APR 0 6 2006 Alaska Oil P Gus Cons. Commission 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 1, 2006. 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. Attachment 1 illustrates the current unit boundary, which was revised in August of 2005. 1.0 Progress of Recovery Projects 1.1 Average Metrics for 2005 - Average oil production rate 120.1 MBOPD - Average gas production rate 135.4 MMSCFD - Average water production rate 5.6 MBWPD - Average gas injection rate 131.4 MMSCFD - Average water injection rate 118.1 MBWPD 1.2 Cumulative Volumes Produced and Injected Through January 2006 Cumulative oil production through January 2006: 188,643,839 STBO Cumulative gas production through January 2006: 215,497,673 MSCF Cumulative water production through January 2006: 3,649,756 STBW Cumulative gas injection through January 2006: 188,035,240 MSCF Cumulative water injection through January 2006: 182,762,373 STB 1.3 Miscible Water Alternating Gas Flood Management during 2005 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 January 2005 through January 2006. CD1 Attachment 3 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 4. CD1 averages an HCPV throughput of approximately 60%. Four wells have completed the target MI slug of approximately 30% HCPV (CD1-05, CD1-14, CD1-21, CD1-23). Fifteen wells have completed or are on their 2nd cycle of MI, after having been temporarily converted to seawater injection in order to alleviate rising GOR trends in offset producers. Six wells, CD1-01, CD1-02, CD1-03, CD1-13, CD1-21, and CD1-31, have completed or are on their 3rd cycle of MI and one well, CD1-03, is on its 4t" cycle of MI. Seventeen MWAG injectors have completed or are on their 2nd cycle of seawater injection. Nine wells have completed or are on their 3rd cycle of seawater injection and five wells, CD1-01, CD1-02, CD1-03, CD1-13, and CD1-21, have completed or are on their 4t" cycle of seawater injection. 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 5 gives an overview of the MWAG conversion status in a tabular form. Attachment 6 shows the maturity of the different patterns. CD2 is significantly less mature than CD1, with only 22% 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. Thirty-one MWAG injectors are now in place at CD2. Twelve of these are on their first cycle of seawater injection. Nineteen wells have completed or are on their first cycle of MI injection. Nine wells have completed or are on their 2nd cycle of MI injection. Thirteen wells have completed or are on their 2nd cycle of seawater injection. One well, CD2 -44, is currently on its 3rd cycle of seawater injection. Six wells (CD2 -02, CD2 -11, CD2 -18, CD2 -54, CD2 -56, and CD2 -59) have been completed in the Alpine A sand. These 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. 2 Overall field response to the MWAG remains excellent. Attachment 7 shows the recovery -throughput relation from all active MWAG patterns, and attests to the effectiveness of the EOR flood at Alpine. 1.4 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 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 an up -structure lean gas well 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. 1.5 Reservoir Management for 2006 In the first half of 2006, reservoir management of the main Alpine field will concentrate on maximizing oil production rate by restoring injection to patterns restricted in 2005 because of offset drilling. To the extent that producing GORs can be reduced, oil rate will be maximized, especially in the summer months when gas compression capacity is reduced by warmer ambient temperatures. In addition, productivity will be increased by hydraulically fracturing up to 6 producers. However, now that Alpine development drilling is completed, its production rate is still expected to decline throughout 2006 from its monthly average peak rate of 130,000 BOPD in November, 2005. In the second half of 2006, Alpine will share the production and injection facilities with Fiord and Nanuq. To the extent that the shared production facilities reach handling limits, rates from the least efficient producers, in any of the developments, may have to be limited. However, this will maximize overall oil production rate from the combined developments. The satellite fields are anticipated to need up to 20,000 BWPD of injection water in 2006. Alpine water production is expected to rise during the year, bringing the volume of water available for injection (produced water plus imported water from GKA) close to the available water injection capacity (150,000 BWPD). Diversion of some of this injection water to the satellites may result in less water injection than required for full voidage replacement in the Alpine reservoir. Reservoir pressure management practices will be followed to ensure pattern pressures are maintained to achieve maximum MWAG recovery. 3 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 were 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 pressure is continuously being managed at or above the level required for stable production and optimum EOR performance. 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. Continuous pressure data from the dedicated Alpine 1 B and Bergschrund 2A observation wells was no longer considered necessary with the development completion of Alpine. The gauges in the Bergschrund 2A, were not functional during 2003 and 2004. Plug and abandonment operations were successfully completed on these two wells in 2005. Most of the drilling problems related to low local reservoir pressures in 2003 were eliminated in the 2004 and 2005 drilling programs due to more diligent reservoir pressure management. The Annual Reservoir Pressure Report for Alpine was issued to the AOGCC on January 23, 2006, and contains all reservoir pressure data gathered during the course of 2005. 3.2 Well Surveillance Twenty-six Alpine wells had reservoir pressures measured either directly via static pressure surveys or calculated from surface pressure fall off tests during 2005. A number of these pressures were captured during the completion phase of the wells .19 Total Month Oil Gas Water Wtr Inj Gas Inj MI Inj Gas Inj MSTBO MMSCF MSTBW MSTBW MMSCF MMSCF MMSCF 2/28/2005 3,341.7 3,887.1 174.9 3,891.6 324.4 3,021.4 3,345.8 3/31/2005 3,699.1 4,247.5 214.4 4,304.5 364.1 3,308.2 3,672.3 4/30/2005 3,476.1 3,808.9 171.8 3,904.3 338.7 2,942.4 3,281.1 5/31/2005 3,699.7 4,068.6 164.2 4,345.1 335.8 3,186.8 3,522.6 6/30/2005 3,327.2 3,472.6 154.5 3,677.2 267.5 2,714.3 2,981.8 7/31/2005 2,941.1 3,019.5 128.9 3,559.4 238.7 2,335.9 2,574.6 8/31/2005 3,877.0 3,880.8 115.6 3,422.1 313.8 3,036.0 3,349.8 9/30/2005 3,815.4 4,473.1 159.9 3,897.7 240.7 3,720.0 3,960.7 10/31/2005 3,971.2 4,870.7 168.3 4,298.3 101.9 4,246.6 4,348.5 11/30/2005 3,920.6 4,767.6 186.6 4,134.5 148.4 4,112.4 4,260.8 12/31/2005 4,027.1 4,765.0 246.2 4,360.3 200.9 4,015.0 4,215.9 1/31/2006 3,964.8 4,581.8 354.2 4,351.3 124.0 3,921.2 4,045.2 CPAI has completed minor revisions to produced volumes as a result of metering studies and well test corrections. The finalized volumes were 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 pressure is continuously being managed at or above the level required for stable production and optimum EOR performance. 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. Continuous pressure data from the dedicated Alpine 1 B and Bergschrund 2A observation wells was no longer considered necessary with the development completion of Alpine. The gauges in the Bergschrund 2A, were not functional during 2003 and 2004. Plug and abandonment operations were successfully completed on these two wells in 2005. Most of the drilling problems related to low local reservoir pressures in 2003 were eliminated in the 2004 and 2005 drilling programs due to more diligent reservoir pressure management. The Annual Reservoir Pressure Report for Alpine was issued to the AOGCC on January 23, 2006, and contains all reservoir pressure data gathered during the course of 2005. 3.2 Well Surveillance Twenty-six Alpine wells had reservoir pressures measured either directly via static pressure surveys or calculated from surface pressure fall off tests during 2005. A number of these pressures were captured during the completion phase of the wells .19 drilled in 2005. Prior to performing any gas lift optimization work, several wells had gauge ring runs performed to verify that no scale build up existed in the tubulars. A workover on the CD2 -51 well was performed in November, 2005 due to Annular communication between the 7" x 4-1/2" annulus and the 4-1/2" tubing. The completed work made the CD2 -51 well capable of MI injection. 4.0 Field Development 4.1 Development Wells Drilled as of March 31, 2006 104 wells drilled total: o 21 CD1 producers o 22 CD1 injectors o 28 CD2 producers o 31 CD2 injectors o 2 Disposal wells 4.2 Development Drilling Completed in 2005 In the Alpine Field, seven new wells and one horizontal extension were drilled and completed in calendar year 2005. Attachment 8 shows a map of the Alpine Participating Area with wells completed to date. This is one well and one extension less than was forecast in the 2005 plan of development. All of the Alpine wells in 2005 were drilled from the CD2 pad, four wells were injectors, three were producers. The extension was of an existing injector. A total of 33,670 feet of horizontal section was drilled in the Alpine Reservoir in 2005. Fifty-nine wells at CD2 and forty-three wells at CD1 have been drilled and completed as of January 31, 2006. Attachment 2 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. The wells drilled in the Alpine reservoir during 2005 were located along the northern and western margins of CD2. Two of the wells (CD2 -01 and CD2 -03) are producers targeting the peripheral Alpine C interval along the northern margin of CD2. The extension (CD1-17a) was of an existing injector in the Alpine C interval which was originally completed with only -600 ft of horizontal section due to loss of fluids as a result of encountering a fault and associated conductive fractures while drilling. The extension added over 3000 ft of horizontal section and completed the existing pattern to support the offset producers. The remaining five Alpine wells drilled during 2005 targeted the Alpine A interval along the western periphery of CD2. Of the five wells, one (CD2 -21) is a producer within the Alpine A interval. The remaining four wells (CD2 -59, CD2 -02, CD2 -11, and CD2 -60) where drilled as injectors to support existing producers drilled within the Alpine A interval. Drilling peripheral wells resulted in greater offsets and longer wells than have been drilled historically. Drilling along the western periphery during 2005 developed the limits 5 of the reservoir that can be reached from CD2. 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. In addition to development drilling completed in the Alpine Field, development drilling was started at both CD3 (Fiord) and CD4 (Nanuq) satellite developments during 2005. 4.3 Fracture Stimulations in 2005 Two fracture stimulations were performed in 2005 on CD2 -24 and CD2 -33B that resulted in appreciable production rate increases and reserve adds. Based on these results, plans are to stimulate four to six additional wells in 2006. 4.4 Development Drilling in 2006 All Alpine wells planned for development of the main field have been drilled and completed as of November 2005. Further study may identify other opportunities to drill new wells on the periphery of the field, or extend existing wells, but none are planned for 2006. 4.5 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. 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 2 140 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 were fully implemented during the July 2005, summer maintenance shutdown with the installation of the crude oil trim coolers. 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 III 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. Construction work is ongoing at the CD1 pad and ACX3 is expected to startup in August 2006 with initial production of 4 MBOPD. Emergency Power Upgrade Construction and tie-in has been completed 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 in 2004 following the summer shutdown which focused on ACX1 and ACX2 construction. Installation work has been completed and the new units were placed in service in February 2005. The original power packages are in the process of being removed from service and this work is expected to be completed during March 2006. Conclusion Alpine reservoir performance remains strong. All Alpine wells planned for development of the main field have been drilled and completed as of November 2005. Further study may identify other opportunities to drill new wells on the periphery of the field, or extend existing wells, but none are planned for 2006. Surface facility projects have provided additional capacity to Alpine. The MWAG EOR project will continue throughout 2006 based on the excellent response seen to date. We foresee no significant obstacles to continued successful exploitation of the Alpine resource at this time. 7 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. Chris Alonzo Supervisor, WNS Base cc: Mr. Bill Van Dyke, Acting 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. John Rathmann Anadarko Petroleum Corporation PO Box 1330 Houston, Texas 77251-1330 M Attachment 1 — CRU Boundary as of August 15, 2005 Unit Boundary Tract Boundary APG Cm Tract Number ° APC, CPN O�` ACL36a470, AOL34447 1 _ A C,CPI-, ® 32 Ant388x4 ao�Meuso3 AOL3aaso2 1 _ ^ _ 83 ��AOL3�aan � PPC. CPA' APC, GPA APC. CPAI 17 I AO1388a, _ _ 1 _ 768 i8c 76 10 'C CPAI 5 i ; msO Arc, CPI F ® AVC. CPN —,CIA 1 a 170 Ag' 16 10 _10 88 ®�c c® 99 I _ ® _ _ _ ._ _ AOL388465 'TCi388463 L3gc3aq ADL38Gry.� Cv vA Ax. wee ADL.172105 AD072IN AUL3P2103 CP (� '° '' llcs✓7 ua � 1 64 98 .8 1 �.. .CPN i 9� APC, CPAI APC,CPN APC, CPAI -- -- —L3169 o, noin2ss2s _ ! 2 q� 20 . CPN A .PI ' m 025529-0'25538 ACL37�2t01 Ao 37 ofi C'A 27 8 7B26 CP 27 ' APC, CPAI APC ]CPA AW LAPC, 22 CPa ---_ — 34 aPC i 37 , 33 AXW72I2 AGL AD�EOG9fi ADL 5558 AG1V155; AD.372108 N0,384214 /➢j I- ( APC. CPN ., APc. CPAI APC, GPA APC. CPAI APC. PAI 23 40 A6PCNPPM2 , 1 L - 1 ,, 48 7 62 A® CL380075 AXW-9 NO,ki)2095 APC. (Fa A w c CPAI PN PN CPA © I 56 AM390074 N]t37N1BE Colville Riveruan74� { 7: oL� a® �Pg 0�7 0 0 Unit Boundary - __ _ .67 �r 78 76 �7 c APc cPI ® � APG, GPA 99 nw ,5o�.vy.,w Aoi3eari Aoi3ewes 7202 A ,CPN 726 APC CPAI (14 ASRCNp(iA02 Oi AC388903 AM 0081 APC, CPN APC,�PN 1® 0 0 4 8 SCALE IN MILES z Attachment " - All Wells Drilled as of February " 2006 Surface Well Information Well Name Well Service 7" Csg Shoe Start of Completion X start Y start End TD of Completion X end Y end CD1-01 Injector 7752 386226 5977656 10289 384975 5979854 CD1-02 Injector 8201 388914 5978054 12773 386773 5982084 CD1-03 Injector 7816 387016 5975903 10897 388337 5973122 CD1-04 Producer 9444 390285 5979213 13977 392388 5975199 CD1-05 Injector 10633 392065 5979111 14515 393810 5975646 CD1-06 Injector 13500 395921 5978194 16024 397043 5975933 CD1-07 Injector 13477 395838 5971680 17542 397737 5968095 CD1-08 Producer 12515 394559 5970944 15837 396092 5967999 CD1-09 Producer 11894 393604 5979402 15350 395153 5976315 CD1-10 Producer 7909 387919 5977328 11693 389639 5973962 CD1-11 Injector 12293 393432 5969790 15057 394737 5967356 CD1-12 Producer 11656 392008 5969456 12912 392582 5968340 CD1-13 Injector 8841 389949 5976723 11300 391036 5974524 CD1-14 Injector 14073 397423 5974752 18939 399752 5970483 CD1-16 Injector 9595 391456 5973711 12600 392819 5971035 CD1-17 Producer 13181 395639 5975431 18590 398233 5970693 CD1-18 Producer 11382 389206 5968235 15056 390928 5964996 CD1-20 Injector 10634 389768 5969450 16114 392499 5964709 CD1-21 Injector 9049 381896 5979206 11087 380972 5981020 CD1-22 Producer 8430 387229 5978470 9236 386794 5979148 CD1-23 Injector 11473 394161 5974990 14477 395504 5972306 CD1-24 Producer 10771 392946 5974121 13706 394333 5971538 CD1-25 Producer 8887 390067 5973033 12147 391614 5970167 CD1-26 Injector 8554 388729 5972343 11134 389929 5970059 CD1-27 Producer 8500 387434 5971694 11492 388770 5969018 CD1-28 Producer 7449 385822 5974801 10468 387229 5972131 CD1-30 Producer 9520 380597 5978488 12850 379073 5981447 CD1-31 Injector 10388 379306 5977679 14364 377530 5981235 CD1-32 Producer 11128 378022 5977019 14353 376466 5979841 CD1-33 Injector 7878 384485 5974129 10854 385846 5971484 CD1-34 Producer 8410 383109 5973412 11190 384448 5970977 CD1-35 Producer 8158 384636 5977159 13450 382165 5981835 CD1-36 Injector 7654 383597 5975923 10654 382248 5978601 CD1-37 Injector 9095 386283 5970682 12134 387689 5967992 CD1-38 Producer 9170 384724 5970395 12240 386139 5967673 CD1-39 Injector 10288 383468 5969466 13298 384825 5966783 CD1-40 Producer 12042 382637 5967963 15438 384188 5964948 CD1-41 Producer 8333 382239 5975220 11170 380948 5977745 CD1-42 Injector 9054 380961 5974612 11608 379729 5976849 CD1-43 Producer 10065 380436 5972089 12921 381823 5969594 CD1-44 Producer 10070 379572 5973840 12811 378333 5976283 CD1-45 Injector 9032 381802 5972762 11950 383139 5970169 CD1-46 Injector 11334 387838 5967599 15187 389598 5964174 CD2 -01 Producer 12953 378098 5982112 17513 376080 5986195 CD2 -02 Injector 16048 359979 5982023 21178 357334 5986377 CD2 -03 Producer 13774 367095 5984985 15682 366191 5986658 CD2 -05 Producer 13712 363517 5970008 17816 361616 5973641 CD2 -06 Injector 9672 371098 5980645 16680 367816 5986833 CD2 -07 Injector 10857 373650 5982084 14977 371786 5985755 CD2 -08 Injector 12242 377278 5981611 18050 374565 5986743 10 Surface Well Name Well Service Csg Shoe Well Information Start of Completion End X start Y start TD o, ;ompletion X end Y end CD2 -09 Producer 12617 365177 5982158 16094 363562 5985233 CD2 -10 Producer 10702 372139 5982079 14475 370284 5985362 CD2 -11 Injector 13809 363590 5981961 18187 361600 5985857 CD2 -12 Injector 8677 368888 5978304 13632 366637 5982712 CD2 -13 Producer 10595 376177 5980472 14575 374339 5983995 CD2 -14 Producer 7671 371963 5975571 11056 370410 5978577 CD2 -15 Injector 9830 366147 5977039 14161 364157 5980881 CD2 -16 Injector 9529 375990 5977319 12500 374782 5980013 CD2 -17 Injector 8184 373143 5976621 8756 372880 5977129 CD2 -17A Injector 8184 373143 5976621 11819 371497 5979862 CD2 -18 Injector 12112 362855 5975882 18019 360209 5981156 CD2 -19 Producer 8769 375572 5975101 11714 376896 5972473 CD2 -20 Producer 9163 369916 5979552 14570 367451 5984361 CD2 -22 Injector 7845 370575 5975090 11134 369051 5978002 CD2 -23 Producer 9676 367151 5978350 13438 365445 5981699 CD2 -24 Producer 10811 364768 5976380 14301 363212 5979501 CD2 -25 Producer 8722 369286 5974237 11994 367790 5977144 CD2 -26 Injector 8619 374207 5974408 11238 375406 5972081 CD2 -27 Injector 12461 377930 5967068 18250 380637 5961965 CD2 -28 Producer 8695 374897 5976522 13200 372799 5980502 CD2 -29 Injector 9556 376873 5975841 12560 378234 5973167 CD2 -30 Injector 11481 365217 5971303 15700 363306 5975062 CD2 -31 Producer 13598 361069 5974966 18131 358947 5978966 CD2 -32 Injector 8723 367954 5973557 11720 366579 5976218 CD2 -33B Producer 9982 366697 5972759 13078 365223 5975475 CD2 -34 Producer 7802 372917 5973731 8755 373367 5972891 CD2 -35A Injector 9063 375633 5971746 13500 377673 5967818 CD2 -36 Injector 13523 372731 5964073 17663 374634 5960399 CD2 -37 Producer 14162 371725 5963095 17085 373038 5960491 CD2 -38 Injector 9209 373424 5969394 13010 375164 5966020 CD2 -39 Producer 9122 374692 5970192 12651 376369 5967087 CD2 -40 Injector 11208 365775 5970211 14250 367117 5967484 CD2 -41 Producer 9532 372019 5968832 13024 373637 5965742 CD2 -42 Producer 9633 367542 5970978 13138 369171 5967884 CD2 -43 Producer 13106 364417 5968231 19040 367196 5962998 CD2 -44 Injector 11319 378889 5972087 14555 380338 5969198 CD2 -45 Producer 9972 377360 5971508 13402 378989 5968491 CD2 -46 Injector 7879 371539 5973093 11000 372970 5970320 CD2 -47 Producer 10840 369515 5967325 14580 371256 5964017 CD2 -48 Injector 10074 370711 5968227 13622 372304 5965058 CD2 -49 Injector 8890 368809 5971733 11874 370200 5969094 CD2 -50 Producer 7909 370191 5972556 11624 371794 5969207 CD2 -51 Injector 13246 380577 5968583 17320 382471 5964985 CD2 -52 Producer 12897 379292 5967820 16881 381127 5964289 CD2 -53 Producer 12394 376772 5966066 16985 378960 5962036 CD2 -54 Injector 14378 361169 5970560 18250 359460 5974033 CD2 -55 Injector 12210 367573 5966569 15238 368976 5963888 CD2 -56 Injector 14391 362859 5967271 19554 365279 5962714 CD2 -57 Injector 12642 375598 5965124 16433 377321 5961749 CD2 -58 Producer 12129 373883 5965245 16389 375838 5961468 CD2 -59 Injector 15743 358798 5974508 20027 357078 5978426 11 Surface Well Name Well Information Well Csg Start of Completion End o. Completion Service Shoe X start Y start TD X end Y end CD2 -60 Injector 14331 369427 5962859 18695 371542 5959079 CD3 -108 Injector 11075 392437 6010111 18915 388364 6016746 CD3 -110 Injector 8959 na na 17991 na na CD4 -208 Injector 7314 377486 5956811 12792 375176 5961758 CD4 -319 Injector 1 11995 373800 5951987 18683 372367 1 5958441 12 Attachment 3 - MWAG conversion status at CD1 Alpine MWAG Status - CD1 WELL 1st Cycle --[ 2nd Cycle 3rd Cycle 4th Cycle 5th Cycle 61h Cycle 7th Cycle Conversion HPCV Conversion HPCV Conversion HPCV Conversion HPCV Conversion HPCV Conversion HPCV Conversion HPCV Date injected Date injected Date in"ected Date injected Date injected Date injected Date injected CD1-Ol 1(25/2001 5.8% 10/19,'2001 4/4/2002 7 1 7/20/2003 6.3°la 6/11/2004 5.6% _2/13/2005 4.4 9!2/2005 3.7% CD1-02 2/7/2001 9.8% 12/21/2001_ 11.096 7/19/2002 9.9% 10/30/2003 5.8% 7/3/2004 3.8% 11/23/20_04 5.3% 6/3/2005 7.7% CD1-03 4/10/2001 14.8% 6/5/2002 16.1% 7/19/2003 7.07 12119/2003 4.5% 4/29/2004 6.3% 11/23/2004 6.6% 6/2/2005 8.5% CD1-05 1/1/2001 48.890 6/23/2002 49.2% C D 1-06 12/13/2000 169.7 CD1-07 7/13/2004 19.3% 4/11/2005 14.9% 11/22/2005 4.8% CD1-11 1/26/2005 1 16.5% 8/27/2005 11.0% 12/13/2005 3.6% CD1-13 1/25/2001 10.5% 11/22J2001 16.9% 1.1/17/2002 12.2% 10/30/2003 4.7% x6/12(2004 5.6% 4/11/2005 3.90/6 10/4/2005 3.097 CD1-14 9/4/2001 162.2% 1 4/26/2005 1 43.3% CD1-16 3!8/2001 13.7% 11/16/2002 12.4 % 7/3/2004 5.4% 6/3/2005 5.39'0 CD1-20 1/23/2005 14.7% _ 1/14/2006 0.3% CD1-21 3/10/2001 12.3% , 11/7/2001 22.0% 7/19/2003 4.1% 12/17/2003 4.0% 6/12/2004 4.6% 602.005 3.5% 12/14/2005 1.1% CD1-23 3/30/2001 18.8 % 4/3/2002 28.2 % 7/20/2003 15.0 % 10/3/2004 6.7 % 4/12/2005 11.9 CD1-26 1/25/2001 18.8% 7/26/2002 14.1% 9/19/2003 14.0% 1/16/2005 6.4% 10/5/2005 4.1% CD1-31 12/13/2000 17.8% _ 10/6/2001 22.6% 10/21/2003 28% 4/29/2004 5.6% 2/13/2005 _ 6.3% CD1-33 2/18/2001 _ 12.6% 11,29/2002 10.7% 7/5/2004 4 1 6/15/2005 3.3% CD1-36 1/25/2001 17.8% 7/19/2003 12.4% 1/16/2005 1 4.6% 1/13/2006 0.290 CD1-37 2/20/2001 20.2% 6/23!2002 13.7% 7/21/2003 8.2% 1/16/2005 3.0% CD1-39 1/25/2001 22.4% 6/25/2003 20.9% 9/19/2003 10.1% 10/31/2004 9.09'0 12/4/2005 1.2% CD1-42 1/25/2001 12.1% 2/28/2002 1 1 9/19/2003 7.0% 10(31/2004 3.2% 7/8/2005 4.29/. CD1-45 2/2/2001 15.7% 2/10/2003 8.6°Jo 7/6(2004 5.5% 6/7(2005 3.7% CD1-46 8/28/2004 18.5% 12/10/2005 1.390 Nomenclature: SW I Sea water injection MI Miscible gas injection D as Dry gas injector 13 8th Conversio Date 1 -105 Attachment 4 - MWAG maturity CD1 CD1 MWAG STATUS C D 1-46 C D 445 CD1-42 j C D 1.39 C D 1-37 C D 1-36 C D 1-33 C D 1-31 C D 426 CD423 C D 1-21 CD1-20 CD1-16 CD4k1 MM _ C D 411 C D 1-07 CD406 CD405 CD403 C D 402 CD401 0 10 20 30 40 50 60 70 80 90 100 110 120 130 140 150 160 170 180 190 200 210 220 CUM HCPVI (%) 14 Seawater Injection MI Injection Lean Gas Injection Attachment 5 - MWAG conversion status at CD2 Alpine MWAG Status - CD2 CD2 -02 WELL 1st Cycle 2nd Cycle 3rd Cycle 4th Cycle 5th Cycle Conversion HPCV Conversion HPCV Conversion HPCV Conversion HPCV Conversion HPCV 1 6/23/2005 110.7% Date injected Date injected Date injected Date injected Date I injected CD2 -02 12/30/2005 1 2.6% CD2 -06 11/10/20 1 10/30/2004 1 1 6/23/2005 110.7% CD2 -07 2/6/2004 1 2/11/2005 1 1 8/25/2005 1 1 11/19/2005 1 6.4% CD2 -08 3/25/200--T-----71 3/28/2004 1 13.4% 2/12/2005 111.0 CD2 -12 6/25/2003 24.6% 1 10/3/2004 1 1 1 6/22/2005 1 1 12/8/2005 1 CD2 -15 2124/2002 11.7% 8/6/2003 1 1 1 4/9/2005 1 1 1/11/2006 10.3 CD2 -16 9/25/200 1 12/19/2003 1 1 2/15/2005 1 8/24/2005 4.0% CD2 -17 3/5/2002 1 10/30/2003 1 1 10/30/2004 16.1 CD2 -18 10/30/2003 11.5 CD2 -22 6/8/2002 1 9/22/2003 1 1 2/8/2005 1 6.1 % 8/27/2005 5.8 CD2 -26 2/22/2002 1 15.0% 1 7/23/2003 1 1 1 4/9/2005 1 12/12/2005 1.1 CD2 -27 1/8/2004 1 13.0 CD2 -29 10/30/2002 9.0 %�1 10/10/2003 1 1 2/14/2005 5.7 %� 913/2005 5.0 CD2 -30 2/3/2004 9.6% CD2 -32 3/31/200 1 9/23/2003 J 7/7/2005 1 CD2 -35 4/26/200 1 4/29/2005 1 CD2 -36 4128/200 1 6/4/2005 17.4 CD2 -38 10/17/200 1 4/29/2005 1 4.5% CD2 -40 9/20/2003 8.2 CD2 -44 10/22/2002 14.77719/21/2003 1 11.2% 1 7/9/2004 1 10.2% 2/15/2005 1 1 10/25/2005 1 CD2 -46 5/30/2002-T--10.7% 6/10/2004_ 1 �1 7/7/2005 1 4.3% CD2 -48 7/19/200 1 10/2/2004 1 57/ CD2-49 2/22/2002 4.09% 1 10/11/2002 1 3.7% 1 4/17/2003 1 10/22/2003 1 1 6/4/2005 1 2.677 CD2-51 11 7/4/2003 1 1 12/5/2005 10.9 CD2 -54111/24/2004 CD2 -55 12/23/2003 5.6 CD2 -56 11/19/2004 9.0% CD2 -57 6/23/2004 9.6 CD2 -59 11/20/2005 0.9% CD2 -60 1/26/2006 0.1 Momenolmre: SW Sea waterinjeotion MI Miscible gas injection D as Ory gas injector 15 Attachment 6 - MWAG maturity at CD2 CD2 MWAG STATUS CD2 -60 CD2 -59 j CD2 -57 CD2 -56 CD2 -55 j CD2 -54 CD2 -51 C D2-49 C D2-48 C D2-46 CD2 -44 C D2-40 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 C D2-08 CD2 -07 C D2 -O6 C D2-02 0.00 10.00 20.00 30.00 40.00 50.00 60.00 70.00 80.00 90.00 100.00 CUM HCPVI (%) 16 Seawater Injection MI Injection Lean Gas Injection Attachment 7 — Recovery - throughput response at Alpine Alpine Pattern Performance 100 TPM O sw bt in TPM gas bt in TPM 90- CD1 ♦ CD2 80 ♦ 70 5. CL ♦ .♦ U 2 . 60 0 c . ♦ 0 Y OM 50 - L W L ♦ > 40- 0 m L 30 e ♦ 20 's ® • 10 ® O 0 0 0.1 0.2 Alpine Pattern Performance 0.3 0.4 0.5 0.6 Qtinj [fraction HCPVI] 17 TPM O sw bt in TPM gas bt in TPM ♦ CD1 ♦ CD2 ♦ ♦ .♦ . . . ♦ ♦ 0.3 0.4 0.5 0.6 Qtinj [fraction HCPVI] 17 0.7 0.8 0.9 1 TPM O sw bt in TPM gas bt in TPM ♦ CD1 ♦ CD2 0.7 0.8 0.9 1 Attachment 8 - Alpine Development: drilled and planned wells Wells drilled in 2005 are indicated as thick dark green (producers) and thick dark blue (injectors) lines. Wells drilled prior to 2005 are indicated as thin dark green (producers) and thin dark blue (injectors) lines. �-r r ------J Participating Area 11