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Home My WebLink About2001 Alpine Oil Pool" PHILLIPS Alaska, Inc. A Subsidiary of PHILLIPS PETROLEUM COMPANY P.O. BOX 100360 ANCHORAGE, ALASKA 99510-0360 March 06, 2002 Alaska Oil and Gas Conservation Commission 333 W. 7f" Avenue Suite 100 Anchorage, AK 99501 Attention: Cammy Taylor, Chair Subject: Annual Surveillance Report Alpine Oil Pool/Colville River Field Commissioner Taylor: Phillips Alaska, Inc., as an owner and the operator of the Colville River Unit, in accordance with Conservation Order 9443, submits the attached Reservoir Surveillance Report for the Alpine Oil Pool. Inquiries regarding this report may be directed to Cliff Crabtree at 265-6842. Sincerely, 4/71evik4ln Mark M. Ireland Alpine Development Manager 1 2 2002 Annual Surveillance Report Alpine Oil Pool March 6, 2002 Page 2 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 Mrs. Catherine Lively Anadarko Petroleum Corporation PO Box 1330 Houston, Texas 77251-1330 Todd Liebel Anadarko Petroleum Corporation PO Box 1330 Houston, Texas 77251-1330 Annual Surveillance Report Alpine Oil Pool March 6, 2002 Page 3 bcc: Distribution: Dan Rodgers ATO 2002 Jack Hartz AOGCC File: Alpine 1.4.1 Brian Richards Mark Ireland Sam French Cliff Crabtree Meg Kremer Colville River Unit - Alpine Oil Pool 2001 Annual Reservoir Surveillance Report Background The Alpine Field started production in November 2000. Initial development drilling was finished on drill site CD1 in the first quarter of 2001. Development drilling in the CD2 area began in May, 2001. CD2 began production in November 2001, and seawater injection commenced in this area during February 2002. 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. Alpine produced solution gas is near miscible with the Alpine oil at anticipated reservoir pressures. To date, miscible injectant (MI) enriching components have been obtained from a condensate flash drum that concentrates these liquids from the compression train. A Joule -Thompson treatment unit is available to extract additional enriching components from field fuel gas by reducing the amount of C2+ in the fuel stream. The JT unit but has not been in regular use as enrichment from condensate drum liquids alone has for the majority of time, been sufficient. We anticipate the JT will be placed in common use early in 2002. Reservoir Management Summary Oil production from the Alpine CD1 pad began on November 15, 2000. Sea water injection for pressure support began on January 23, 2001. During this two month time period, the reservoir management focus was to distribute offtake to keep all patterns above bubble point pressure. Offtake was higher in patterns that had gas injection support (CD1-05, CD1-06, CD1-31). Drilling and field operations prevented all water injection wells from being brought on-line until mid-April. None of the measured surveillance pressures were below the bubble point pressure of 2469 psi. Initial reservoir pressure was approximately 3,250 psia. After water injection began, the focus of the reservoir management was to distribute the injection water to balance the pattern pressures and pattern voidage. Produced gas was re -injected as previously explained, and was included in the voidage replacement calculation process on a pattern basis. Producing wells indicated rapid waterflood response, and it was observed that pattern pressures drove well productivity. The water injection pumps reached capacity at approximately 80,000 BWIPD, but excess well productivity still existed. The excess production capacity drove facility upgrades to the water injection in May 2001, when the injection capacity was increased to 90,500 BWIPD. Additional debottlenecking and optimization in the Alpine processing plant allowed production to increase to rates consistently above 100,000 BOPD by August 2001. Currently Alpine production is constrained to approximately 100,000 BOPD to allow the reservoir to rebuild pressure. By late summer of 2001, proper reservoir management required the development of plans to create more gas injection options. Due to higher than expected gas injection rates, the gas injection patterns had matured rapidly. In September 2001 steps were taken to increase gas injection options. Well CD1-14 was taken off pre- production and converted to gas injection. Water injection rates into CD1-01, CD1- 13 and CD1-21 were increased to IWR's higher than 1.0 in order to reach the water slug target of 15% HPVi at an earlier date, allowing conversion to gas injection. In October 2001 MWAG conversions began, as previously explained. The timing and planning of MWAG conversions is a key part of the reservoir management of the Alpine reservoir. Much of the future reservoir management will be driven by the needs of the EOR project to convert injection wells at the proper maturity. Alpine reservoir management also is driven by the need to optimize the distribution of water and gas injection and to replace voidage in all patterns. A key focus of the reservoir management of Alpine has always been to keep all patterns above bubble point pressure, to inject at an injection / withdrawal ratio (IWR) of 1.0 or slightly higher in most patterns, and to inject at higher IWR's in patterns that have higher cumulative net voidage. Balancing reservoir voidage with injection will continue in all patterns at Alpine. Both water injection and gas injection are used to ensure voidage balance in all patterns throughout the field. The recent MWAG conversions have resulted in at least one gas injection well being operational in five of the six development rows at CD1. Due to the apparent highly directional permeability in the CD1 area, an injection well in one well row can provide significant pressure support to other patterns in the same row. This increases flexibility in providing pressure support to each CD1 pattern and will ensure even pressure distribution across the CD1 pad area. Wells drilled from the CD2 pad started production in early November 2001. Water injection in the CD2 area began in February 2002. Because of the fixed capacity of the sea water injection system at Alpine, a portion of the water injection will be shifted away from the CD1 wells and pumped to CD2 injection wells. Having gas injection at CD1 distributed throughout several patterns increases the flexibility of the reservoir management at Alpine by allowing gas injection to replace a significant amount of voidage that was previously replaced by water injection. Offtake in CD1 patterns will be reduced primarily in the more mature gas injection patterns as oil production at CD2 increases, so that the total reservoir voidage balance is maintained. Pattern management calculations are reviewed and updated on a monthly basis or more often when necessary. An Oil Field Manager (OFM) software database has been built for Alpine. The OFM database is used to determine required injection rates for gas and water injectors to replace voidage. Patterns are injector based. Producer to injector relationships and allocation factors are determined by a full field streamline simulation model. These allocation factors are then input into the OFM database as part of the pattern balancing calculations. 2 Some reservoir management of CD1 wells has been driven by elevated gas/oil ratios (GOR) and consists primarily of constraining production from wells with high GORs. All wells with GORs greater than solution GOR are offsets to the gas injection wells. Since these patterns have had the highest pressures of any area in the reservoir due to the high rate of gas injection, the higher gas production is due to gradual breakthrough of injected gas. Currently the CD1-09 well has a GOR of approximately 1,600 SCF/STB, which is the highest GOR of any well in the field. The CD1-09 well is located between two gas injection wells, the CD1-05 and the CD1-06. Solution GOR is approximately 850 SCF/STB. After one year of water injection CD1-28, CD1-22A and CD1-30 are the only wells producing water. Each of these have very low watercuts. Progress of Alpine EOR Implementation The Alpine miscible water alternating gas EOR project (MWAG) has been implemented and has progressed ahead of schedule, due to higher than expected offtake rates and higher than expected gas injection rates and water injection rates. The higher than expected productivity drove upgrades to the water injection facilities. The upgrades were necessary to replace the increased voidage. The higher than expected water injection rates are causing MWAG patterns to reach their target pre-injection slug of water sooner than initially planned. There are currently two types of EOR patterns at Alpine. The first type of pattern began gas injection with no pre-injection slug of water. These gas injection wells were necessary to dispose of and to utilize the produced gas for pressure support prior to the time when a sufficient number of the second type of patterns reach their water slug target. The second type is a normal MWAG pattern where a pre- determined optimal volume of water is injected prior to injecting miscible gas. EOR Project — Initial Gas Injection Wells The field startup began with first oil production on November 15, 2000. Gas injection began on December 9, 2000 into wells CD1-05, CD1-06 and CD1-31 with all injected gas being miscible. On April 3, 2001 lean gas injection into 1-06 began. Miscible gas injection into CD1-05 and CD1-31 continued. Miscible gas flooding in the Alpine C sand is itself an effective method of enhanced recovery, although injecting a pre-injection slug of water prior to miscible gas is preferred in order to delay breakthrough gas. Pattern performance in the patterns with initial MI injection has been excellent, with producing gas/oil ratios from offset producers remaining low compared to the volumes of gas injected. CD1-31 was converted from gas injection to water injection in October 2001 after injecting approximately 17% HPV slug of miscible gas. At approximately the same time CD1-01 had been converted from water injection to miscible gas injection (MWAG), thus taking most of the gas that had been injected into CD1-31. Well CD1-14 was drilled as a gas injection well in the same row as CD1-06, but was pre -produced for three months, adding an average of approximately 5,800 bopd to 3 the field rate. The well was pre -produced because it had excellent pressure support from CD1-06, another gas injection well was not needed at the time, and the added oil production rate slowed the maturity rate in other patterns. CD1-14 was converted to MI gas injection in September 2001, and to lean gas injection in late January 2002. CD1-05 will likely be converted to water injection sometime in the 1St or 2"d quarter of 2002. Before CD1-05 can be converted to water injection, a sufficient rate of production needs to be produced at the CD2 pad to replace production that will be curtailed at the CD1-05 pattern. This curtailment will be necessary to maintain the voidage balance in the CD1-05 pattern. Adequate gas injection options also need to be available when CD1-05 is converted to water injection to absorb the gas injection currently going into CD1-05. Currently we are enriching the majority of the injection gas and all enriched gas (MI) meets minimum miscibility requirements. Approximately 15% to 20% of the total injected gas is not enriched. This "lean" gas is injected into well CD1-06 and CD1-14. CD1-06 and CD1-14 are the most updip injection wells and are located in a common row. Lean gas injection at CD1-06 will allow the well to be back -flowed as a source of fuel gas in an emergency. Total lean gas injection is currently approximately 15 mmscfd. Miscible gas injection is currently approximately 70 mmscfd. Fuel gas usage is currently about 10-12 mmscfd. EOR Project — Miscible Water Alternating Gas Injection Wells Simulation modeling of the Alpine reservoir indicates that in order to achieve optimal recovery from the MWAG process, a slug of approximately 10% to 20% HPV of water should be injected into a pattern at Alpine before beginning miscible gas injection. Currently a target water slug of 15% HPV is being used for WF patterns at Alpine to determine when to convert a specific well from water injection to gas injection. It is important to begin miscible gas injection prior to water breakthrough at offset producers. Waiting too long to convert can result in offset producers having watercuts that yield them unable to lift the voidage rate required by high gas injection rates. Water injection rates have been increased in some patterns above an injection/withdrawal ratio of 1.0 when necessary to stagger the timing of when wells are converted to MWAG. This approach is necessary to insure that adequate gas injection options are available and to optimize the utilization of the injection gas. Miscible gas injection in existing waterflood patterns began in the 4t" quarter of 2001. Four injection wells reached the target slug size of approximately 15% HPV during this time and were converted from water injection to miscible gas injection. The four wells, and their approximate date of first miscible gas injection, are as follows.. 4 CD1-01 10/19/01 CD1-21 11 /07/01 CD1-13 11/22/01 CD1-02 12/21 /01 Initial results of gas injection following water injection have been favorable. Gas injection rates do not appear to be constrained by a trapped -gas effect. This effect may have more impact on the water injection rates following this cycle of gas injection. Approximately 50 MMSCFD of miscible gas was being injected into these four MWAG patterns based on by -well data available in late January. Another 20 MMSCFD of miscible gas was being injected into CD1-05. As previously mentioned, the 15 MMSCFD of gas injected into CD1-06 and CD1-14 is lean gas. EOR Project Plans for 2002 Based on expected water injection rates, four to five more wells at the CD1 pad are likely to reach the target water injection slug of 15% HPV in 2002. These wells will then be converted to miscible gas injection. Simulation modeling of Alpine indicates the optimum solvent slug size to be 20%- 30% HPV injected of miscible gas before converting back to water injection. Actual field performance may determine when wells are converted back to the next cycle of water injection. If produced gas/oil ratios at offset wells increase in MWAG patterns, gas injection wells will likely be converted to water. This water cycle would eventually be followed by another cycle of MI injection. Some of the current MWAG gas injection wells may be converted back to water injection in late 2002, depending on pattern performance and offtake rates. Gas injection well CD1-05 will likely be converted to water injection in 2002. An expansion to the Alpine facilities is currently being designed but will not be implemented until 2003 at the earliest. The expansion will accelerate the EOR project when the upgrades are online at some future date by increasing gas handling rates, and therefore gas injection rates. Water injection rates will also be increased. Another aspect of the expansion is the installation of a stabilizer, which will result in a slightly different composition of miscible injectant. Monthly Production and Injection Oil production from the Alpine CD1 pad began on November 15, 2000. Gas injection began December 9, 2000. Seawater injection for pressure support commenced January 23, 2001. By June 2001, it was clear the computer flow correction algorithm for well testing was not yielding acceptable results. This was determined by comparing monthly well test summations to monthly sales volumes. For plant throughput optimization, 5 a process model had been constructed to simulate the Alpine production facility. This simulation was subsequently used to derive a new flow correction algorithm for both Alpine and Nanuq production. The Alpine process monitoring system (SETCIM) was switched over to the new flow correction algorithm beginning in October 2001. Allocation factors improved significantly with this change. PAI is now in the process of revising the historic well level allocation for the field. Although pipeline volumes will not be affected, it appears some oil will be moved from Nanuq to Alpine production and hence, necessitate that previously filed production reports be revised. In November 2001, it was determined that the meter summation employed for calculating Alpine produced gas was overstating production. Following discussions with AOGCC staff, we altered the algorithm to employ the compressor inter -stage meters with improved results. Gas production will also be amended in the revised reports. Table 1 below shows Alpine production and injection since November 2000. These volumes have not yet been fully reviewed, so there could be slight changes once finalized. The values are deemed sufficiently accurate for reservoir management. Table 1 Alpine Monthly Production and Injection Monthly totals are daily volumes are rolled up from the daily tables in ATDB Daily volumes have not yet been fully checked/justified against monthly data Reservoir Pressure Monitoring Numerous initial pressure surveys have been conducted in new wells since start up. The reservoir has been managed to trade average reservoir pressure for production during Alpine start-up. We imposed limits on pressure depletion to maintain well productivity and remain above crude bubble point. 9 Total Month Oil Gas Water Wtr Inj Gas Inj MI Inj Gas Inj STBO MSCF STBW STBW MSCF MSCF MSCF 11/30/00 533,712 473,199 40,828 418 0 0 0 12/31/00 1,697,213 1,632,973 0 19 813,113 0 813,113 01/31/01 2,079,405 2,002,516 0 339,144 1,018,687 379,519 1,398,206 02/28/01 2,042,110 1,850,399 0 1,689,113 1,097,431 250,972 1,348,403 03/31/01 2,487,427 2,084,286 0 2,301,091 409,097 1,115,830 1,524,927 04/30/01 2,486,114 2,106,462 0 2,235,957 5,481 1,637,573 1,643,054 05/31/01 2,572,955 2,158,361 0 1,865,156 194,189 1,498,520 1,692,709 06/30/01 2,656,529 2,228,792 0 2,301,500 698,593 1,254,953 1,953,546 07/31/01 3,014,107 2,753,707 0 2,827,873 782,428 1,757,946 2,540,374 08/31/01 2,722,853 2,694,312 0 2,591,231 831,631 1,663,455 2,495,086 09/30/01 2,919,238 3,125,335 0 2,709,429 1,106,350 1,538,582 2,644,932 10/31/01 2,839,460 3,169,195 0 2,577,402 834,805 1,792,129 2,626,934 11/30/01 3,043,615 3,050,994 0 2,719,863 420,850 2,245,083 2,665,933 12/31/01 3,087,598 3,135,091 0 2,752,497 422,675 2,301,726 2,724,401 01/01/02 3,125,700 3,078,668 0 2,680,821 231,560 2,331,582 2,563,142 Reservoir Pressure Monitoring Numerous initial pressure surveys have been conducted in new wells since start up. The reservoir has been managed to trade average reservoir pressure for production during Alpine start-up. We imposed limits on pressure depletion to maintain well productivity and remain above crude bubble point. 9 The dedicated surveillance wells have not yet been connected for remote monitoring. This will be completed in 2002. A plot of the available data for both wells is attached. Results of all static pressure surveys are included in Attachment 1. Results from long-term pressure observation wells are shown in Attachments 2 and 3. Profile Surveys The friction and rugosity encountered in the Alpine horizontal open -hole section has precluded successful profile logging to date. PAI has not been able to complete an injection or production profile at Alpine since start up. Efforts to improve technology in this area will continue in 2002. Future Plans for Reservoir Management In 2002, the reservoir management at Alpine will be driven by MWAG conversions, the distribution of water injection between CD1 wells and CD2 wells, and the need to maintain oil production rates while replacing voidage in all patterns. The reservoir management in 2002 will utilize a new full field finite difference reservoir simulation model and an updated reservoir description. Both should be complete in the first quarter of 2002. The new simulation model will be utilized to evaluate various potential projects and reservoir management options at Alpine. Development Drilling During the first quarter 2001, CD1-21 and CD1-14 were drilled. This completed an 18 producer /18 injector line drive pattern of horizontal wells at CD1 Pad. Development drilling commenced at Alpine CD2 Pad on May 12,2001. Starting with CD2 -42, the initial wells were a North - South line of producers to the west side of the CD2 development area. A core was taken the second well drilled, CD2- 24PB1. An average C sandstone core porosity of 18.7% and permeability of 5.8md supports the results of the Neve #1 core. Both of these cores indicate the C sandstone West of CD1 has lower reservoir quality than generally encountered in the CD1 development area. Peripheral data gathering and development drilling were combined when drilling CD2 -33B. The shallow portion of that wellbore was utilized to drill two sidetracks to the Alpine -West (2-33) and Alpine -West side track (2-33A) locations as shown in Attachment 5. Eight wells were drilled and completed at CD2 between May 2001 and December 2001. Attachment 6 lists all the Alpine wells drilled through 2001 along with the ASP4 coordinates for the beginning and end of the horizontal productive interval. Attachment 7 is a map of these locations. Well CD2 -45 was suspended after landing the horizontal in the Alpine reservoir target due to lost circulation problems. Producers CD2 -45 and CD2 -47 were drilled with mineral oil as a test to determine if oil based drilling fluids would reduce formation damage and increase productivity from the low permeability & porosity rock found at CD2. Test results from CD2 -47 indicate substantially improved production rates were achieved by minimizing formation damage. At this time, we anticipate that mineral oil based mud will be used in drilling the remaining Alpine producers. Development drilling will continue through 2002 with approximately eighteen CD2 wells completed at year-end. Candidate wells are listed in Table 2. Table 2 Anticipated 2002 Development Wells Surface Bottom hole Well Well Location Location Service Type CD2 -26 47 Injector Horizontal CD2 -49 53 Injector Horizontal CD2 -17 40 Injector Horizontal CD2 -45 62 Producer Horizontal CD2 -29 45 Injector Horizontal CD2 -50 51 Producer Horizontal CD2 -25 43 Producer Horizontal CD2 -19 46 Producer Horizontal CD2 -46 49 Injector Horizontal CD2 -32 50 Injector Horizontal CD2 -48 57 Injector Horizontal CD2 -35 61 Injector WO Horizontal CD2 -28 39 Producer Horizontal CD2 -13 73 Producer Horizontal CD2 -41 58 Producer Horizontal CD2 -23 67 Producer Horizontal CD2 -44 63 Injector Horizontal CD2 -16 38 Injector Horizontal Conclusion Alpine development and recovery is proceeding as good as, or better than anticipated compared to expectations prevalent when the project received sanction. No significant obstacles to continued successful exploitation of the resource are foreseen at this time. Attachment 1 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION RESERVOIR PRESSURE REPORT Page 1 of 2 Name of Operator Address Phillips Alaska, Inc. P.O. BOX 100360, Anchorage, AK 99510-0360 Unit or Lease Name Field and Pool Datum Reference Oil Gravity Gas Gravity Colville River Unit Alpine Oil Pool 7000' SS 40 0.928 Final Pressure Test Data Production and Test Data Well Name API Oil (0) Date Shut-in Shut-in Pressure Tool Final PRODUCTION RATES Liquid Wt. of Wt. of Casing and No. API Number or Tested Time Tubing Depth B. H. Observed BbIs per Da Mcfd Gradient Liquid Gas Pressure at Oil Gas Water Gas(G) HRS Pressure MD Tem Pressure sift Column Column Datum CD1-33 50-103-20357-00 Oil (0) 2/1/2001 N/A 277 7,665 160 2,658 Injector 0.355 0.298 N/A 0 2,675 CD1-03 50-103-20319-00 Oil (0) 2/4/2001 N/A 150 7,701 161 2,814 Injector 0.446 0.298 N/A 0 2,843 CD1-28 50-103-20356-00 Oil (0) 2/9/2001 N/A 328 7,275 159 2,725 3,168 2,648 38 0.387 0.298 N/A 125 2,746 CD1-37 50-103-20302-00 Oil (0) 2/10/2001 N/A 123 8,500 157 2,611 Injector 0.430 0.298 N/A 50 2,622 CD1-33 50-103-20357-00 Oil (0) 2/16/2001 N/A 225 7,670 159 2,582 Injector 0.314 0.298 N/A 0 2,597 CD1-03 50-103-20319-00 Oil (0) 2/22/2001 N/A 100 7,700 160 2,800 Injector 0.409 0.298 N/A 0 2,830 CD1-21 50-103-20362-00 Oil (0) 2/27/2001 N/A 154 8,912 154 2,615 Injector 0.355 0.298 N/A 0 2,626 CD1-23 50-103-20301-00 Oil (0) 3/1/2001 N/A 100 11,000 160 2,533 Injector 0.491 0.298 N/A 0 2,591 CD1-16 50-103-20306-00 Oil (0) 3/7/2001 N/A 250 9,200 159 2,521 Injector 0.291 0.298 N/A 0 2,575 CD2 -35 50-103-20256-00 Oil (0) 3/9/2001 N/A 450 9,000 163 3,117 Prod - S Prod - S11rod -S 0.460 0.298 N/A 50 3,089 CD1-03 50-103-20319-00 Oil (0) 3/14/2001 N/A 100 7,700 161 2,718 Injector 0.400 0.298 N/A 0 2,747 CD1-23 50-103-20301-00 Oil (0) 3/29/2001 N/A 450 11,000 161 2,605 Injector 0.290 0.298 N/A 750 2,658 CD1-03 50-103-20319-00 Oil (0) 4/8/2001 N/A 100 7,732 161 2,687 Injector 0.430 0.298 N/A 250 2,716 CDI-14 50-103-20371-00 Oil (0) 5/13/2001 N/A 252 13,900 155 2,692 4238' 4,450 253 0.504 0.298 N/A 0 2,757 CD2 -42 50-103-20374-00 Oil (0) 6/25/2001 N/A 210 9,190 159 3,238 1,117 1,784 18 0.470 0.298 N/A 0 3,231 CD2 -24 50-103-20377-00 Oil (0) 7/22/2001 N/A 675 10,518 163 3,264 848 1,470 15 0.470 0.298 N/A 0 3,227 CD2 -42 50-103-20374-00 Oil (0) 8/31/2001 N/A 200 9,191 159 3,226 1,117 1,784 18 0.469 0.298 N/A 0 3,218 CD2 -42 50-103-20374-00 Oil (0) 9/3/2001 N/A 213 9,191 160 3,226 1,117 1,784 18 0.468 0.298 N/A 0 3,218 CD2 -33 50-103-20381-00 Oil (0) 10/1/2001 N/A 500 9,750 165 3,275 1,271 2,250 3 0.490 0.298 N/A 0 3,219 CD2 -39 50-103-20387-02 Oil (0) 10/3/2001 N/A 450 9,080 163 3,108 825 2,855 6 0.470 0.298 N/A 50 3,058 Attachment 1 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION RESERVOIR PRESSURE REPORT Page 2 of 2 Name of Operator Address Phillips Alaska, Inc. P.O. BOX 100360, Anchorage, AK 99510-0360 Unit or Lease Name Field and Pool Datum Reference Oil Gravity Gas Gravity Colville River Unit Alpine Oil Pool 7000' SS 40 0.928 Final Pressure Test Data Production and Test Data Well Name API Oil (0) Date Shut-in Shut-in Pressure Tool Final PRODUCTION RATES Liquid Wt. of Wt. of Casing and No. API Number or Tested Time Tubing Depth B. H. Observed Bbls.per Da (M d) Gradient Liquid Gas Pressure at Oil Gas Water Gas(G) HRS Pressure MD Tem Pressure psi/ft Column Column Datum CD2 -24 50-103-20377-00 Oil (0) 10/4/2001 N/A 675 10,518 163 3,264 848 1,470 15 0.470 0.298 N/A 0 3,227 CD2 -42 50-103-20374-00 Oil (0) 10/6/2001 N/A 308 9,212 161 3,200 1,117 1,784 18 0.394 0.298 N/A 0 3,178 CD2 -14 50-103-20390-00 oil (0) 11/9/2001 N/A 100 7,540 163 2,901 1,084 4,026 114 0.490 0.298 N/A 0 2,864 CD2 -15 50-103-20386-00 Oil (0) 11/11/2001 N/A 675 9,700 163 3,186 Injector 0.410 0.298 N/A 0 3,141 CD2 -47 50-103-20394-00 Oil (0) 12/21/2001 N/A 726 10,630 159 3,266 3,908 2,857 5 0.360 0.298 N/A 0 3,201 ** This Injector was Pre -Produced I hereby certify that the foregoing is true and correct to the best of my knowledge Signed Tine Production Engineer Date 3500 3400 3300 .N 3200 C. 3100 3000 N 2900 L- CL a 2800 2700 2600 2500 00 00 00 00 00 00 00 00 00 O� O� O� Date Attachment 2 Bergschrund 2A Pressure @ 6677' SS 3300 3200 3100 3000 2900 2800 2700 2600 2500 O� 4 Attachment 3 CD2 -35 Static Pressure @ 6,984' SS ATTACHEMENT 4 CD2 -33, 33A and 33B borehole profiles Phillips Alaska, Inc.' PHILLIPS .... .......... __._ _........ _.__ ..... ...._ u o��e ny For S R eyn a i1ds Structure COg2 Well 331181 5—J 200 Pial .a 33 PB 1 -will. !, Field Alpine F f pe, Id .I North SI Alaska .......... ...._ .._........ .. ............ __......... 'n coorelnotaa ora leer rele.ence a DI /�3. ..._....... .. a Vertical Deptha ore rafercnce RNB (Doyon f9). rp <— West (feet) 17600 16800 16000 15200 14400 13600 12800 12000 11200 10400 9600 8800 8000 7200 6400 5600 4800 4000 3200 2400 1600 800 0 1600 CD2 -3 3 TD3] LOCATION: TD - Csg Pt. n Ati o 978' FNL, 25fifi' FWL � 3 N 800 �o 0 248.33 AZIMUTH C-20 'C-20 18175' (TO PB1 TARGET) c°z-33 TARGET N. m ,� - c' �° .' EOC F� 800 ...Plane of Proposal--- LOCATION: 1658' FSL. 7307' FEL 0 0 0 SEC. 3, T11 N, R4E Target - EOC - CsgPt . anti" 1600 N (. 9 f c? sS •� Q. �� O( a 2400 TRUE L� oe (� nc1 J J 3200 K -Albion-97 /a 4000 CO2 -3311111 TARGET LOCATION: 1933'FSL, 2579' FEL Al bion -97 (� SEC. 8, T11N, R4E Albion -96 ��J;'Albion-96 4800 �1CD2-33PB2 5600 TARGET 11 � V ' LK i HRZ C LOCATION: SEC. 9FST11 NZ R4E /HRZ 6400 IpMieu�each A vas TD Base9&Ipl¢ine y C61 rileeach A ��r��a �@dsegljfPineapine 7200 CD2 -331111 TO TD LOCATION: 1741' FSL. 2221' FWL SEC. 8, T11N, R4E CD2-33PB2 TD LOCATION: 8000 1297' FSL, 289' FEL SEC. 9, 711N, R4E Attachment 5 All Wells Drilled Through 2001 Surface Bottomhole Well Well Well Start of Completion End of Completion Name Name Service X start Y start X end Y end CD1-01 3 Injector 386223 5977665 384975 5979854 CD1-02 14 Injector 388914 5978054 386773 5982084 CD1-03 21 Injector 387030 5975876 388335 5973121 CD1-05 27 Injector 392060 5979100 393833 5975653 CD1-06 82 Injector 395935 5978137 397053 5975880 CD1-13 23 Injector 389954 5976715 391036 5974524 CD1-14 83 Injector 397422 5974748 399750 5970479 CD1-16 34 Injector 391456 5973711 392819 5971035 CD1-21 4 Injector 381897 5979207 380663 5981642 CD1-23 36 Injector 394166 5974982 395504 5972306 CD1-26 32 Injector 388736 5972327 389928 5970058 CD1-31 16 Injector 379306 5977679 377530 5981235 CD1-33 19 Injector 384479 5974142 385846 5971484 CD1-36 2 Injector 383593 5975934 382249 5978602 CD1-37 30 Injector 386288 5970673 387689 5967992 CD1-39 28 Injector 383465 5969470 384820 5966793 CD1-42 15 Injector 380940 5974591 379708 5976828 CD1-45 17 Injector 381806 5972745 383138 5970171 C D1-04 24 Producer 390285 5979213 392388 5975199 C D1-09 78 Producer 393604 5979398 395153 5976312 CD1-10 22 Producer 387919 5977328 389639 5973962 CD1-17 77 Producer 395639 5975431 398233 5970693 CD1-22 7 Producer 387229 5978470 385833 5981196 C D1-24 35 Producer 392946 5974121 394333 5971538 CD1-25 33 Producer 390067 5973033 391614 5970167 CD1-27 31 Producer 387434 5971701 388804 5969032 CD1-28 20 Producer 385825 5974800 387228 5972131 CD1-30 10 Producer 380597 5978488 379073 5981447 CD1-32 37 Producer 378022 5977019 376466 5979841 CD1-34 18 Producer 383109 5973412 384448 5970977 CD1-35 1 Producer 384636 5977159 382165 5981835 CD1-38 29 Producer 384766 5970331 386136 5967662 CD1-40 80 Producer 382644 5967952 384185 5964949 CD1-41 9 Producer 382239 5975219 380948 5977745 CD1-43 64 Producer 380436 5972089 381823 5969594 CD1-44 44 Producer 379572 5973840 378333 5976283 CD2 -42 54 Producer 367542 5970978 369171 5967884 CD2 -24 76 Producer 364768 5976380 363212 5979501 CD2 -33 52 Producer 366697 5972759 365223 5975475 CD2 -39 55 Producer 374692 5970192 376369 5967087 CD2 -14 41 Producer 371963 5975571 370410 5978577 CD2 -15 66 Injector 366147 5977039 364157 5980881 CD2 -47 126 Producer 369515 5967325 371256 5964017 CD2 -45 62 Producer Top Set not completed due to lost circulation CD2 -34 48 Producer 372917 5973731 373367 5972891 Attachment 6 — Wells Drilled Through 2001 L.