The URL can be used to link to this page

Home My WebLink About2007 Alpine Oil PoolConocoPhillips Alaska, Inc. Post Office Box 100360 Anchorage, Alaska 99510-0360 Chris Wilson Supervisor, WNS Base Phone (907) 265.6822 Fax: (907)265-1515 April 1, 2008 Alaska Oil and Gas Conservation Commission Attention: Mr. Dan Seamount 333 West 7th Ave, Suite 100 Anchorage, AK 99501 Subject: Annual Surveillance Report for the Alpine Oil Pool of the Colville River Unit Commissioner Seamount: 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, 2008. 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) 263-6822. 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 2007 -Average oil production rate 92.3 MBOPD -Average gas production rate 122.3 MMSCFD -Average water production rate 12.5 MBWPD -Average gas injection rate 119.0 MMSCFD -Average water injection rate 92.3 MBWPD 1.2 Cumulative Volumes Produced and Injected Through January 2008 -Cumulative oil production through December 2007: 260,076,577 STBO -Cumulative gas production through December 2007: 306,160,343 MSCF -Cumulative water production through December 2007: 12,674,753 STBW -Cumulative gas injection through December 2007: 273,596,734 MSCF -Cumulative water injection through December 2007: 259,369,821 STB 1.3 Miscible Water Alternating Gas Flood Management During 2007 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 2007 through January 2008. 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 significantly matured at CD1, as shown in Attachment 9. CD1 averages an HCPV throughput of approximately 84 percent amongst the 22 MWAG injectors there. Eight wells have completed the target MI slug of approximately 30 percent HCPV (CD1-03, CD1-05, CD1-07, CD1-11, CD1-21, CD1-23, CD1-31, & CD1-39). Eighteen wells have completed or are on their second cycle of MI, after having been temporarily converted to seawater injection in order to alleviate rising GOR trends in offset producers. Eleven wells have completed or are on their third cycle of MI. Six wells, CD1-01, CD1-02, CD1-03, CD1-13, CD7-26, and CD1-31 have completed or are on their fourth cycle of MI. No wells have begun a fifth cycle of MI at this time. Five wells at CD1 were converted to lean gas injection in 2007; CD1-02, CD1-05, CD1-11, CD1-14, and CD1- 21. Nineteen MWAG injectors have completed or are on their second cycle of seawater injection. Seventeen wells have completed or are on their third cycle of seawater injection and ten wells have completed or are on their fourth cycle of seawater injection. Four wells, CD1-01, CD1-02, CD1-03, & CD1-13, are on or have completed their fifth cycle of seawater injection. The main drivers behind the rate of maturation of the different patterns are field offtake, 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 injection centered patterns at CD2. CD2 is significantly less mature than CD1, with only 39 percent overall throughput. This is due to a combination of factors: Production started up later than at CD1, and the off take and throughput rates at CD2 were lower due to ongoing development drilling. Also, larger reserves are present at CD2 and the poorer rock quality will not allow the same throughput rates as seen at CD1. Five wells have completed the target MI slug of approximately 30 percent HCPV (CD2 -07, CD2 -11, CD2 -12, CD2 -22, & CD244). Thirty-one MWAG injectors are in place at CD2. Seven injectors are on their first cycle of seawater injection. Twenty-nine wells have completed or are on their first cycle of MI injection. Nineteen wells have completed or are on their second cycle of MI injection. Twenty-four wells have completed or are on their second cycle of seawater injection. Thirteen wells are currently on their third cycle of seawater injection and nine wells are on their third cycle of MI. Seven wells are on or have completed their fourth cycle of seawater injection and one (CD2 -07) is on its fifth. Two wells at CD2 were converted to lean gas injection and are on or have completed their first slug of lean gas (CD2 -06 & CD2 -07). Of the 31 MWAG injectors at CD2, two have not started their first MI slug (CD2 -55 and CD2 -60). Eight wells (CD2 -02, CD2 -11, CD2 -18, CD2 -54, CD2 -56, CD2 -59, CD2 -60, and CD4 - 17) have been completed in the Alpine A sand. No injection has taken place on CD4 - 17 as this well will not be hooked up until early 2008. These wells are on or have completed their first cycle of MI injection with the exception of CD2 -60 and CD4 -17. No problems with injectivity have been observed while on water or gas and a good response by offset producers completed in the A sand suggest that this sand should deliver similar recovery factors as seen in the C sand. Overall field response to the MWAG remains excellent. Attachment 12 shows the recovery -throughput relation from all active Alpine MWAG patterns, and attests to the effectiveness of the EOR flood at Alpine. 1.4 MI Enrichment Challenges The miscible injectant (MI) stream is manufactured at the Alpine Central Facility (ACF) by blending lean gas from the field gas production stream (blend gas) with C2+ enriching components extracted from either the condensate flash drum (when stabilizer is offline) or the stabilizer reflux drum (when stabilizer is in operation). Enriching components can also be produced by the Joule Thompson Unit, when it is in MI service. The composition of the MI is routinely monitored and adjusted to ensure miscibility with the reservoir oil. With the start of MWAG injection at CD3 and CD4, the MI must now also meet the MMP requirements of the crude oils in the reservoirs flooded from those drill sites. All lean gas handled at the ACF must either be 1) used as fuel, 2) blended into MI, or 3) injected as lean gas. The rate of fuel gas consumption is fixed by the ACF heating and electrical generating needs. The amount of lean gas blended into MI is controlled by the amount of enriching fluid available. If the amount of lean gas blended into MI decreases in order to maintain the blend at the required MMP, then more lean gas must be injected. With the commissioning of the Gas Condensate Stabilizer Unit in December 2006, the MI enrichment process has taken on an added level of complexity. The stabilizer, as the name implies, stabilizes C5+ components for additional crude sales. This process can reduce the amount of enriching fluid available for MI manufacture, thus impacting the overall volume of MI produced at any given MMP spec, and the amount of lean gas remaining after blending. In 2007, a team studied the cause and affect relationship between gas production, enriching fluid availability, stabilizer operation, MI manufacture, and long term EOR performance. As a result of their evaluation, several mature MWAG injectors were converted from long-term water injection service (which is the standard late -term phase of the MWAG flood) to long-term lean gas injection. This increased lean gas injection capacity was required in order to handle the extra amount of lean gas requiring injection. Over time, as more MWAG injectors reach their target MI injection volume and switch to post-MWAG water flood chase, some will be converted to lean gas injection (either continuous LGI or IWAG) to meet the underground storage required for the unblended lean gas. 1.5 Reservoir Management for 2008 For the duration of 2007, Alpine shared the production and injection facilities with Fiord and Nanuq. This maximized the overall oil production rate from the combined developments. In 2008 reservoir management of the main Alpine field will concentrate on maximizing oil production rate by targeting a pattern injection/withdrawal ratio of one, injection capacity permitting. 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 eight or more producers. However, now that Alpine development drilling is complete, its production rate is expected to continue to decline throughout 2008. The satellite demand for injection water averaged approximately 43 MBWPD in 2007. Satellite demand will continue to increase in 2008 to approximately 52 MBWPD. Total 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. In that case, Alpine production may be temporarily prorated to maintain complete voidage replacement The water injection system at Alpine consists primarily of three 50 MBWPD injection pumps. Currently, two of the pumps take seawater imported from the Seawater Treatment Plant (STP), in the Kuparuk River Unit, and one pump takes produced water and seawater and sends this mixed water to CD1. The demand for water from the seawater pumps has increased with the addition of the satellites. Drilling results at the satellites have lead to increased injection demand than predevelopment estimates. This was due to higher than expected Kuparuk performance at Nanuq and Fiord as well as lower than expected Nanuq Nanuq performance. Additionally the desire to mitigate against corrosion in the water injection lines prevents long term mixing of all waters at Alpine and thus reduces the water injection system's flexibility. A team has been assembled to look at both short and long term projects to enhance the flexibility of the current system while mitigating corrosion risks. 2.0 Alpine Production and Injection by Month Total Month Oil Gas Water Wtr Inj Gas Inj MI Inj Gas Inj MSTBO MMSCF STBW MSTBW MMSCF MMSCF MMSCF 2/28/2007 2,920.8 3,346.9 491.5 3,230.4 536.9 2,763.2 3,300.1 3/31/2007 3,074.2 3,705.7 584.5 3,063.8 592.3 3,123.9 3,716.2 4/30/2007 3,081.5 3,758.5 413.7 2,914.7 578.9 3,237.9 3,816.8 5/31/2007 3,146.7 4,111.8 335.5 2,597.0 898.3 3,422.8 4,321.1 6/30/2007 2,881.1 3,743.1 258.2 1,724.5 897.9 3,158.3 4,056.2 7/31/2007 2,692.7 3,822.2 290.3 1,925.4 1,267.9 2,761.3 4,029.2 8/31/2007 2,377.3 3,308.5 262.1 2,572.3 1,018.1 2,156.0 3,174.1 9/30/2007 2,674.8 3,550.6 296.3 2,526.4 1,025.2 2,321.7 3,346.9 10/31/2007 2,678.4 4,005.1 356.5 2,767.5 1,241.1 2,336.6 3,577.7 11/30/2007 2,490.5 3,819.5 384.8 3,258.7 1,418.8 1,832.8 3,251.6 12/31/2007 2,495.6 3,814.6 404.7 3,471.7 1,668.4 1,567.8 3,236.2 1/31/2008 2,412.7 3,688.7 447.5 3,148.2 1,540.9 1,804.1 3,345.0 3.0 Survey Results 3.1 Reservoir Pressure Monitoring Several pressure surveys were conducted on Alpine wells during the course of operations in 2007. The reservoir is continuously being managed to allow for local pressure build up in areas of historic under injection 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. The Annual Reservoir Pressure Report for Alpine was issued to the AOGCC on April 1, 2008 and contains all reservoir pressure data gathered during the course of 2007. 3.2 Well Surveillance Eleven Alpine wells had reservoir pressure measured via static pressure surveys in 2007. Per Alpine's scale management program quarterly samples from wells producing greater than or equal to five percent water cut or 50 BW PD were acquired to determine scaling potentials. Based on the sampling results six wells had slight to moderate scaling potential therefore, gauge ring runs were performed to verify that no scale build up existed in the tubulars. Nine fracture stimulations were performed in 2007 and resulted in appreciable production rate increases. Based on the fracturing success at Alpine eight or more additional stimulations are planned for 2008. 4.0 Field Development 4.1 Development Wells Drilled as of March 31, 2008 - 108 wells drilled total: 21 CD1 producers • 22 CD1 injectors 28 CD2 producers • 31 CD2 injectors CD4 Alpine producers CD4 Alpine Injector • disposal wells 4.2 Development Drilling Completed in 2007 All Alpine wells planned for initial development of the main field from CD1 and CD2 have been drilled and completed as of November 2005. In 2006, CD4 -17 was drilled from CD4 as part of a planned 2 -well development of a single injector/producer pattern in the southwest corner of the PA. The Alpine reservoir drilled by CD4 -17 proved to have much higher water saturation than anticipated. This drilling result called into question the viability of drilling the offset producer, CD4 - 16, unless it could be demonstrated that the water found by CD4 -17 was a small reservoir volume swept by water from CD2 -56. After the rig moved off CD4 -17, a testing program was developed to determine the risk of finding sufficient recoverable oil in CD4 -16's drainage area to justify drilling that well. The test results were reviewed by the end of 1Q07, after which CD4 -16 was drilled and found initial oil saturation. It was completed as a producer. In addition, three other wells were drilled and completed as A Sand producers in 2007: CD2 -72, CD4 -05 and CD4 -07. 4.3 Fracture Stimulations in 2007 Nine fracture stimulations were performed in 2007 on CD1-18, CD1-43, CD2 -05, CD2 - 14, CD2 -25, CD2 -28, CD2 -31, CD2 -50 and CD2 -52 that resulted in appreciable production rate increases and reserve adds. Based on these results, plans are to stimulate additional wells in 2008. 4.4 Development Drilling in 2008 Additional Alpine A Sand opportunities are being developed for drilling from CD2. One producer is expected to be drilled to the north of CD4 -07 in 2008 (CD2 -75), with an additional injector -producer pair (CD2 -73 & CD2 -74) to be drilled to the north of CD2 -75 and CD2 -59 in 2009. The drilling order and timing are a function of coordinating the drilling schedule with several coincident drilling programs, including the Qannik CD2 project. Several other Alpine drilling prospects are being considered from CD1, CD2 and CD4. The success of drilling CD4 -05 and CD4 -16 has indicated additional development potential for 3-4 wells to the immediate south, as well as an injector to the west of CD4 - 05 (all to be drilled from CD4). A sidetrack of CD2 -60 to the west and to parallel CD4 -16 at a closer location (than its current 2000 -foot spacing), is being evaluated. Approximately 3-4 CD1 locations are being evaluated in the periphery of the Alpine C Sand reservoir. If these prospects prove to be economically viable, they will be drilled as rig availability allows. 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. ACX Phase 1 The Alpine Capacity Expansion Project Phase 1 (ACX1) was approved by the Alpine working interest owners in April 2003, and work was completed in the summer of 2004. 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. rSW7 X413Y% The Alpine Capacity Expansion Project Phase 2 (ACX2) was approved by the Alpine working interest owners in February 2004., and work was completed in the 2004 and 2005 summer shut down periods. 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 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 3 In January 2005 the Alpine working interest owners approved the Alpine Capacity Expansion Project Phase 3 (ACX3). The ACX3 project installed a stabilizer column, Fred 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 adds 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 was completed in December 2006 and the stabilizer was started up in late December 2006 with an initial production of 3 MBOPD. The stabilizer has now been in operation for over a year and continues to perform well. 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 following the 2004 summer shutdown and turbines were placed in service in February 2005. The original power packages were removed from service in the spring of 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. Limited additional drilling opportunities may be progressed in 2008 with one firm candidate well at time of writing (CD2 -75). The MWAG EOR project will continue throughout 2008 based on the excellent response seen to date. We foresee no significant obstacles to continued successful exploitation of the Alpine resource at this time. 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. Chr?Wilson Supervisor, WNS Base Tom Irwin, Commissioner Alaska Department of Natural Resources 550 W. 7t' 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. Steve Dodds, Landman Anadarko Petroleum Corporation PO Box 1330 Houston, Texas 77251-1330 Attachment 1 - CRU Boundary effective as of August 15, 2005 Unit Boundary Treat Boundary ! Two Number (D ,B , OB) _®_ o G) KKfO� P Ll B I O O `"/ Py 1Y b Colville River a " ® *+ o I o (sjpip Unit Boundary -- -- gyp" p, Vii® ConocoPhillips ue1r] inn. Colville River Unit Exhibit B 0 4 8 Located within T10 -13N, R3 -5E Umiat Meridian, Alaska SCALE IN MILES August 15, 2005 �isos osoetwanbo 10 Attachment 2 - All Wells Drilled as of February 1. 2008 Surface Well Information Well Name Well Service 7' Csg Shoe Start of Completion X—sta—rt—F Y start End TD of Completion X end Y end CD1-01 Injector 7752 386226 5977656 10289 384975 5979854 CDi-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 CDI.09 Producer 11694 393604 5979402 15350 395153 159763151 CD1-10 Producer 7909 387919 5977328 11693 369639 5973962 C131-11 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 159810201 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 367434 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 15979841 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 COI -37 Injector 9095 386283 5970682 12134 387689 5967992 CD1-38 Producer 9170 384724 5970395 12240 366139 5967673 CD1-39 Injector 10288 383469 5969466 13296 384825 5966783 CD1-40 Producer 12042 382637 5967963 15438 384188 5964948 CD141 Producer 8333 382239 5975220 11170 380948 5977745 CD1-42 Injector 1 9054 380961 5974612 11608 379729 5876849 CD143 Producer 1 10065 380436 5972089 12921 381823 16969594. CD144 Producer 1 10070 379572 5973840 12811 378333 5976283 CD1-45 Injector 1 9032 381802 5972762 11950 383139 5970169 CD1-46 Inector 1 11334 387838 5967599 15187 389598 5964174 CD2 -01 Producerl 12953 378098 5982112 17513 376080 5986195 Inector 16048 359979 5982023 21178 357334 5986377 Producer 13774 367095 5984985 15682 366191 5986658 Producer 13712 363517 5970008 17816 361616 5973641 C Injector 9672 371098 5980645 16680 367816 5986833 Injector 10857 373650 5982084 14977 371786 5985755 Injector 12242 377278 1 5981611 18050 1 374565 15986743 Surface Well Information Well Name Well Service 7" Csg Shoe Start of Completion X start Y start End TD of Completion X end I Y and CD2 -09 Producer 12617 365177 5982158 16094 363562 15985233 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 1 9830 366147 5977039 14161 364157 5980881 CD2 -16 Injector 1 9529 375990 5977319 12500 374782 5980013 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 376406 5972081 CD2 -27 Injector 12461 377930 5967068 18250 380637 5961965 CD2 -28 Producer 8695 374897 5976522 13200 372799 5980502 CD2 -29 Injector 1 9556 376873 5975841 12560 378234 15973167 CD2 -30 Injector 11481 365217 5971303 15700 363306 5975062 CD2 -31 Producer 13598 361069 5974966 18131 358947 5978966 CD2 -32 Injector 1 8723 367954 5973557 11720 366579 5976218 CD2 -33B Producer 1 9982 366697 5972759 13078 365223 5975475 CD2 -34 Producerl 7802 372917 5973731 8755 373367 5972891 CD2 -35A Injector 1 9063 375633 5971746 13500 377673 5967816 CD2 -36 Injector 1 13523 372731 5964073 17663 374634 5960399 CD2 -37 Producer 1 14162 371725 5963095 17085 373038 5960491 CD2 -38 Injector 1 9209 373424 5969394 13010 375164 5966020 CD2 -39 Producer 9122 374692 5970192 12651 376369 15967087 CD2 -40 Injector 11208 365775 5970211 14250 367117 15967484 CD2 -41 Producerl 9532 372019 5968832 13024 373637 15965742 CD2 -42 Producerl 9633 367542 5970978 13138 369171 5967884 CD2 -43 Producer 13106 364417 5968231 19040 367196 5962998 CD2 -44 Injector 1 11319 378889 5972087 14555 380338 5969198 CD2 -45 Producer 1 9972 377360 5971508 13402 378989 5968491 CD2 -46 Injector 1 7879 371539 5973093 11000 372970 5970320 CD2 -47 Producerl 10840 369515 5967325 14580 371256 5964017 CD2 -48 Injector 1 10074 370711 5968227 13622 372304 5965058 CD2 -49 Injector 1 8890 368809 5971733 11874 370200 5969094 CD2 -50 Producerl 7909 370191 5972556 11624 1 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 CO2 -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 6961749 CD2 -58 Producer 12129 373883 5965245 16389 375838 5961468 CD2 -59 Injector 15743 358798 5974508 20027 357078 5978426 12 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 CD2 -60 Injector 14331 369427 5962859 18695 371542 5959079 CD2 -72 Producer 16692 358481 5980385 21089 356322 5984105 CD4 -05 Producer 15140 366426 5956030 21142 363632 5961338 CD4 -07 Producer 17716 363602 5962039 25040 360029 5968372 CD4 -16 Producer 11664 369790 5957923 16850 367402 5962514 CD4 -17 Injector 13334 368009 5957262 17975 365932 5961403 13 Attachment 3 - MWAG conversion status at CD1 Alpine MWAG Slalua - CDl CD121 3/10/2001 123. 11/7/2001 22.3. 7/192003 4.1% 1211 ?/20031 41% 6/12/2004 4G6 6/3/2005 3.62 12/14/2005 fl2. L24/207 37. CD123 3/30/2001 1982 4/3/2002 28.57 7/20/2003 15.0% 10/3/2004 1 67% 4/12/2005 37.3% CD1-26 1/25/2001 18,62 M6/2002 14.2% 9/19/2003 14.0% 1/16/2005 6.5Y 10/5/2005 602 3/29/2006 1 70 1 1/10/2007 1 77% 12/132M7' 0.2.8 MI -31 12/13/2000 18.02 10/6/2001 22.6% 10/21/2003 28% 4/29/2004 56% 2/13/2005 802 3/29/2006 1 5.02 1 12/9/2006 1 1 12 I 321/2007 1 31% CD133 2/18/2001 12.6% 11/29/2002 10.8% 7/5/2004 44 6/24/2005 93% 12/92006 4.1% CDt M 125/2001 17.SY. 7/19/2003 125% 1/16/2005 4bi 1/13/2006 69% 3/d2007 In CD1-37 2/20/2001 211.2% 62312e 128% 721/2003 822 1/1612005 8,4. 2/2/2007 4.8% CD 139 1/25/2001 22.8 6/252003 211. 9/19/2003 10.1% 10/31/2004 9.1% 12/4/2005 15.6% DD1 Q 1/2520M 120% 2/282002 20.0% 3/19/2003 7.02 10/31/2004 32/ 7/8/2605 8.88 9/27/2006 1 25% I 3/16/200/ 1 44% D01 45 222A01 15.6% 2/10/2003 8.7. 7/6/2004 55% 6/72005 78% 12/18/2006 4.3% CD1 46 1 92828041 1859. 112/1072D05I 85% 11/10/20071 792 112/10/20071 0.0% Nomenclature. ®Miabeg iMeGiw Mouble gas iniedion Oi Gas Dry gas iNestw 14 Attachment 4 - MWAG maturity CD1 15 CD1 MWAG Status CDM -01 ' CD1-02 CD1-03 CD1-05 --- - _ CD1-O6 CDi-07 CD7-11 CD1-13 CDi-14 CD1-16 C--D1-20' CD1-21 CD1-23 CD1-26 CD7-31 ODI -33 CEM -36 - CD -37 CD1-39 CD1 42 wi CD1 45 CD1 46i o >o �o -'o yo Bo �o 80 `b 70 7>o �o �"'o Cum HCPVI )%) 15 Attachment 5 - MWAG conversion status at CD2 Aoi. MWAG SM6us-D02 CD2.2 3/312002 127% 1 3/23/2003 962 1 7l7/2005 1 106% 1 1/2001jll�CD2. 5 4/26/2003 122% 429/2005 7.32 5)2012006 69% //30/200]CD2d6 4/28/2003 1652 6/4/2005 10.3%. 4/26/2006 632 6/13/2007CD238 10/172002 123% 4/29/2005 8.6% 9/24/2006 d2% 10/22/2007 wommdewre: sw see wete.�ni=1- MI Mixcible ges inledicn Dr Gax Dry gax inledun 16 17 Attachment 7 — Recovery - throuahput response at Alpine Im GO ■ ti m ■ 70 6 m 0 IN —TPM • Water BT Gas BT a w o m w © IN Col • coz 0 90 40 m A 1a Injected Volume (fraction HCPV) In ■ ti ■ ■ Attachment 8 - Alpine Development: drilled and planned wells Wells drilled through the end of 2007 we indicated as thin dark green (producers) and thin dark blue (injectors) lines. Wells to be drilled in 2008-2009 are shown highlighted in red. Additional wells are being considered around the periphery of the reservoir. Alpine PA 0 MILES 19