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Home My WebLink About2002 Alpine Oil Poolv ConocoPhillips Alaska, lnc. April 28, 2003 Post Office Box 100360 Anchorage, Alaska 99510-0360 Mark Ireland Alpine Subsurface Development Mgr. Phone: (907) 263-4767 Fax: (907) 265-1515 RECEIVED APR 3 0 2003 Alaska Oil and Gas Conservation Commission Alaska Oil & Gas Cons. Commission 333 West 7th Ave, Suite 100 Anchorage Anchorage, AK 99501 Sarah H. Palin, Chair Subject: Annual Surveillance Report for the Alpine Oil Pool of the Colville River Unit Commissioner Palin: ConocoPhillips Alaska, Inc., as Operator and on behalf of the working interest owners of the Colville River Unit submits this, the Annual Surveillance Report for the Alpine Oil Pool of the Colville River Unit. This report is submitted in compliance with Rule 8, of Conservation Order No. 443, and reflects the status of the Alpine Pool of the Colville River as of February 1, 2003. Attachment 1 illustrates the current unit boundary, which was revised on 1 1 /O8/2OO2. If you have any questions or require additional information, please contact me at ConocoPhillips Alaska, Inc., P. 0. Box 100360, Anchorage, Alaska, 99510-0360, Telephone: (907) 263-4767. 1.0 Progress of Recovery Projects 1. 1 Average Metrics for the time period of February 2002 through January 2003 - Average oil production rate: 96.0 MBOPD - Average gas production rate: 109.3 MMSCFD - Average water production rate: 483 BWPD - Average gas injection rate: 96.1 MMSCFD - Average seawater injection rate: 87.8 MBWPD 1.2 Cumulative Volumes Produced and Injected through January 2003 - Cumulative oil production: 72,306,880 STBO J - Cumulative gas production: 75,570,258 MSCF - Cumulative water production: 203,304 STBW - Cumulative gas injection: 65,062,484 MSCF - Cumulative water injection: 61,868,985 STB Annual Surveillance Fiepoi Alpine Oil Pool, Colville River Unit April 25, 2003 1.3 Water Injection Management Lower than expected pressure in the eastern CD2 area prompted us to allocate more injection into the area from March through June 2002. Low formation pressure resulted in lost circulation while targeting locations to the East of the drillsite. Development drilling in rows 2, 3 and 4 was affected. Significant lost circulation was encountered while drilling CD2-45, CD2-34 and CD2-17. To mitigate these problems, CD2-45 was topset to be completed at a later date, CD2-34 and CD2-17 were completed in the Alpine with horizontal sections shorter than planned. A static pressure survey in CD2- 26 on 2/03/02 indicated a reservoir pressure of 2,611 psia at the casing shoe. A review of geologic and geophysical data suggested a high frequency of fracturing in rows 2, 3 and 4 that, when combined with the depleted reservoir pressure, was the likely the cause of the lost circulation events. In the meantime the drilling schedule was modified and drilling shifted to the far western CD2 area with higher pore volume 1 higher pressure locations. In order to pressure up the CD2 area and enable development drilling in rows 2,3 and 4, a significant amount of the water injection was shifted from CD1 in late February to CD2 injection wells. Some CD2 production wells were also shut-in to more rapidly build pressure in the area. For approximately 4 months from March through June 2002 more water was injected at CD2 than the reservoir volume of fluids produced. As a result, pressures in the CD2 area have increased significantly. In March the Alpine 1B observation well was at a pressure of approximately 2,600 psia. By late June the pressure had increased to approximately 2,930 psia. Several static pressure surveys from CD2 wells in June exceeded 3,000 psia. As the core of CD2 eventually was filled in with the completion of the CD2-45 well on 01/08/2003, there has been less focus on over-injecting into this area of the field. Water injection management is now primarily being distributed to replace offtake. 1.4 Status of MWAG conversions Attachment 2 gives an overview of the MWAG conversion status. The following paragraphs will discuss some of the MWAG reservoir management issues in more detail. 1.5 Facility Upgrades It was recognized soon after startup that the Alpine producers and injectors were performing well above expectations. Offtake from Alpine is limited by reservoir voidage replacement, as it is essential to maintain sufficient reservoir pressure for stable well production, as well as keeping the reservoir pressure above the minimum miscibility pressure of the MI stream. In order to increase field oil production, more water injection is required to replace the added voidage. A first upgrade of the water injection facilities was therefore implemented in May 2001, raising injection from 80,000 bwpd to 90,500 bwpd. Subsequent debottlenecking and plant optimization efforts allowed offtake to be increased from 90,000 BOPD to 100,000 BOPD by August 2001. A second upgrade of the water injection system was completed in early July 2002, increasing Alpine's water injection capacity up to about 98,000 BWPD, which in turn allowed another 5,000 bopd to be produced from the Alpine reservoir. Some of the added water injection capacity was used to re-pressure the reservoir. Several more facility upgrade scenarios are Annual Surveillance Repo Alpine Oil Pool, ~olville.~iver Unit April 25, 2003 currently being evaluated to further accelerate oil production and increase overall field recovery. I. 6 lnjectivjty of wells on pd M WA G cycle Of notable interest, three wells are now on their 2" cycle of seawater injection: the CD1-01, CD1-02 and CDI-13 injection wells. No significant decrease in water injectivity due to trapped gas has been observed in these wells after conversion back to seawater injection. 1.7 MI Enrichment Issues The MI stream consists of lean gas from the field gas production stream (blend gas) and C2+ enriching components extracted from the condensate flash drum and the Joule-Thompson Unit. The supply of enriching components is limited to about 13 MMSCFD. 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 disposed of to ensure adequate composition of the MI stream. For optimal EOR performance, the amount of dry gas disposal is kept to a minimum. This has required several reservoir management steps to adjust field gas offtake and re-shuffle dry gas disposal locations. On 1/29/02 well CD1-14 was switched from miscible gas injection to dry gas injection in order to further enrich the miscible gas and lower the minimum miscibility pressure of the MI. Offtake was also reduced from the CD1-09 because it had experienced dry gas breakthrough from the CD1-06, and was contributing a significant amount of gas to the total blend gas stream. This has, in turn, required reducing the injection of dry gas into the CD1-06. The CD2-49 was therefore converted to dry gas injection on 1011 112002 to dispose of excess blend gas, and to test the gas flood potential of lower permeability Alpine rock. The composition of the injected miscible gas is routinely monitored and adjusted with the miscible gaddry gas split to ensure miscibility with the reservoir oil. 1.8 MI Supply 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. Until April 2002, enriching components were primarily obtained from a condensate flash drum that concentrates these liquids from the gas compression train. Approximately 8.5 MMSFCD of enriching components are extracted from the condensate flash drum. A Joule-Thompson (JT) treatment unit was also made available on a permanent basis from April 2002 to extract an additional 4.5 to 5.5 MMSCFD of enriching components from the fuel gas stream. C Annual Surveillance Report Alpine Oil Pool, Colville River Unit April 25, 2003 1.9 Reservoir Management for 2003 In 2003, the reservoir management at Alpine will be driven by field wide production management aiming primarily at increasing CD2 offtake and reducing production from the more mature CD1 drill pad. Some local re-pressurization schemes to ensure safe and successful drilling operations will also play a role in overall field management decisions. Based on expected water and gas injection rates, three to four wells at the CD1 pad are likely to reach their target MI injection slug in 2003, and will be converted back to sea- water injection. A couple of CD1 wells will also be converted to their first cycle of MI. In addition, a couple of wells may be converted to their second MI cycle. All CD2 wells, except for the CD2-49, are currently still on their first cycle of seawater injection. Three or four of these wells may reach their first seawater slug target of 15-20% HPV in 2003, and be converted to MI injection. 2.0 Alpine Production and Injection by Month Total Month Oil Gas Water Wtr Inj Gas Inj MI Inj Gas Inj MSTBO MMSCF MSTBW MSTBW MMSCF MMSCF MMSCF CPAl is contemplating minor revisions to produced gas volumes based on ongoing metering studies. We expect to make a final determination on this question during 2003. 3.0 Survey Results 3.1 Reservoir Pressure Monitoring During the report period, thirty-six pressure surveys were conducted both in new wells and wells that were shut in for reservoir pressure management. These surveys were reported in the annual pressure survey report submitted to AOGCC in January 2003 and are included in Attachment 3 of this report. The reservoir has been managed to allow for local pressure build up in areas of development drilling while maintaining Annual Surveillance Report Alpine Oil Pool, Colville River Unit April 25,2003 average pattern pressures at or above the level required for stable production in the rest of the field. Pressure measurements were taken over a period of time while CD1- 43 and CD1-44 were shut-in to build pressure in the eastern CD2 area. The lower pressures in these wells (2487 psi and 2376 psi respectively) were measured before a stabilized pressure buildup was achieved. The final measured pressures (2926 psi and 291 1 psi) are thought to be more indicative of actual pattern pressure. On an ongoing basis, reservoir pressures are estimated from the Alpine full field simulation model as well as from inflow performance relation analysis on all drilled producers. Both approaches are calibrated with actual reservoir pressure measurements collected from static surveys taken in development wells as well as the continuous pressure data from the three dedicated observation wells (CD2-35, Alpine 1 B and Bergschrund 2A). 3.2 Alpine Pressure Observation Wells A plot of pressure data from CD2-35 subsurface gauges is provided in Attachment 4. This plot illustrates the effect of efforts to increase pressure in the eastern CD2 area. Operations to sidetrack CD2-35 to a new bottom hole location began in December 2002. This well is now in it's permanent location and will no longer be used for pressure observation. A plot of pressure data from Alpine 1 B subsurface gauges is provided in Attachment 5. Like the 2-35 plot, this plot also illustrates the effect of efforts to increase pressure in the eastern CD2 area. With CD2-35 in its new location and soon to be on injection, we believe that Alpine 1B data will be heavily influenced by CD2-35. In the future, we believe the Alpine 1 B data will be less useful for general reservoir pressure observation. A plot of pressure data from Bergschrund 2A subsurface gauges is provided in Attachment 6. This plot illustrates the effect of pressure management in the central CD1 area. 3.3 Well Surveillance In an attempt to measure flow profile along the length of the wellbore, several techniques have been employed to gather information in horizontal well sections. Prior to 2002, difficult wellbore conditions and unreliable tool response limited the usefulness of conventional spinner log data collection. In 2002, substantial effort was focused on developing more robust logging tools and techniques. Temperature warm-back logging, was shown to provide good qualitative results in seawater injection wells. The temperature differential along Alpine producing wells, however, is insufficient to obtain a reliable production profile using temperature-logging techniques. Given the need for understanding production profiles as well as quantitative injection profile data, a coiled tubing conveyed inflatable packer flow meter (PFM) tool system has been developed. Results of the temperature-based and PFM logging suggest that the effective span length of Alpine injection wells approaches 100%. The injection profile varies considerably well to well. We've noted that injection profile is affected by permeability variation as well as most natural faults that intersect the wellbore. To date, the inflatable Annual Surveillance I3epoi Alpine Oil Pool, Colville River Unit April 25,2003 PFM has been deployed in four producers and five seawater injectors, with mixed but promising results. Although we have not yet recovered a usable suite of data from a producing well, injection wells have proven easier to log and several useful data sets have been obtained. Revisions to the packer flow meter tool string are in progress. We are optimistic that the planned changes will increase the data recovery in both producing and injection wells. The latest tool improvements are to be tested in the second quarter of 2003. An example of how the PFM and temperature Warmback logging can be used together is provided in Attachment 7. It was also confirmed in 2002 that oil based mud-drilling results in less formation skin damage and higher deliverability from Alpine producers. The mechanism for the damage appears to be a pore level water block when the Alpine reservoir sand is allowed to imbibe water. This was further confirmed by the successful application of a surfactant squeeze that improved productivity in the low permeability CD2-24 well that was drilled with water based fluid. 4.0 Development Plans 4.1 Development Wells Drilled as of February 1,2003 - 19 CD1 producers - 17 CD1 injectors - 16 CD2 producers (9 in 2002 + 1 in 2003) - 13 CD2 injectors (1 1 in 2002) - 2 Disposal wells 67 Total 4.2 Development Drilling Completed in 2002 Twenty wells were drilled and completed in calendar year 2002, two more than expected. Eleven wells were injectors, 9 were producers, one of which was an extension of the existing well CD2-45. A total horizontal section of 64,169 ft was drilled. Twenty-nine wells have now been drilled and completed at CD2 as of January 31, 2003, primarily within the central core of the western side of the field. Attachment 8 lists the Alpine producers and injectors drilled to date and their maximum and minimum NAD27, ASP4 completion coordinates, for both the beginning and end of the horizontal productive interval in the Alpine sand. A major operational challenge during 2002 was drilling mud loss due to a higher frequency of natural fracturing and reduced reservoir pressures in some of the CD2 development area. Reservoir management practices were modified to allow re- pressurization in areas of development drilling while maintaining sufficient pressure elsewhere to maintain field deliverability and an efficient EOR process. The drilling schedule was also modified to accommodate increased injection where reservoir pressures had been depleted. CD2-29, CD2-16, CD2-28, CD2-45, and CD2-44 were Annual Surveillance Report Alpine Oil Pool, Colville River Unit April 25, 2003 re-scheduled in order to build pressure back to about 3,000 psi in those areas prior to drilling. 4.3 Development Drilling in 2003 The remaining development locations are at the periphery of the field. Fourteen CD2 wells are scheduled to be drilled in 2003, including four southern wells, six western wells, one sidetrack from an existing wellbore, and three northern wells. Two have already been drilled at this writing (CD2-35a and CD2-08). Attachment 9 lists wells scheduled to be drilled in 2003, and Attachment 10 is an Alpine map with all wells drilled to date and those planned for the remainder of 2003. This plan is subject to change as the drilling schedule is optimized throughout the course of the year. There was a break in development drilling in the March - April timeframe to utilize the rig for drilling a well in the Kuparuk Unit. 4.4 Facilities Expansion Evaluation Efforts are underway to obtain approval for capacity expansion of the Alpine plant and surface facilities. The expansions envisioned include additional gas handling, additional produced oil and water handling and increased water injection capacity. If approved, these changes would accelerate recovery and add incremental reserves. We do not anticipate that any of these will be implemented prior to the middle of 2004. Conclusion Alpine production rates remain above expectations. Development drilling in the CD2 area while maintaining high offtake has been challenging, but managed without serious impact to drilling costs or material affect on long term production capacity or reserves. Improved surveillance techniques have been developed and are being fine-tuned. We foresee no significant obstacles to continued successful exploitation of the resource at this time. Sincerelv. &?iFyh&%$ Mark M. lrelan Alpine Subsurface Development Manager cc: Mr. Mark Meyer, Director Alaska Department of Natural Resources Division yi Oil & Gas 550 W. 7 Avenue, Suite 8000 Anchorage, Alaska 99501 -3560 Ms. Teresa I mm, Resource Development Manager Arctic Slope Regional Corporation 301 Arctic Slope Avenue, Suite 300 Anchorage, Alaska 9951 8-3035 Annual Surveillance Report Alpine Oil Pool, Colville River Unit April 25,2003 Mr. Isaac Nukapigak, President Kuu kpik Corporation PO Box 187 Nuiqsut, Alaska 99789-01 87 Mrs. Catherine Lively Anadarko Petroleum Corporation PO Box 1330 Houston, Texas 7725 1 - 1 330 Attachment 1 - CRU Boundary as of 11/08/2002. Exhibit B Colville River Unit Colville Delta Area, Alaska January 9.2003 -- - - - - - - Umt Boundary - - - - - - - - Tract Boundary O Tract Number Attachment 2 - MWAG conversion status at Alpine !3Qt% All conversions thatoccwted in 2002 are underlined in bald Namendafw Sea water injection Miscible gas injeclion Dty gas injector Attachment 4 - CD2-35 Formation Pressure Historv CD2-35 Formation Pressure April, 2000 through November, 2002 Commence CD1 SWI i Commence CD2 SWI 04/00 06/00 08/00 10/00 12/00 02/01 04/01 06/01 08/01 10101 12/01 02/02 04/02 06/02 08/02 10102 Date Attachment 5 - Alpine 1 B Formation Pressure History Alpine 1 B Formation Pressure 3,000. -- Note: pressure gauge or telemetry were not functional in periods without data 2,500. 3/02 4/02 5/02 6/02 7/02 8/02 9/02 10102 11/02 12/02 1/03 2/03 3/03 4/03 Date Attachment 6 - Bergschrund 2A Formation Pressure History Bergschrund 2A Formation Pressure Attachment 7 - Pacbr Flow Meter and Temperature Warmback Lagging en246 Temp Wrm Back - PFM Injection PZofilfile 76m 8,000 8,500 QpOb 9,800 10,000 '1 450Q 11,006 MEASURED DEPTH (ft) Attachment 8 - All Wells Drilled as of February 1,2002 . Attachment 9 - Planned Wells for 2003 Well Surface Count Location Completed: 65 CD2-35a 66 CD2-08 To Be Drilled: 67 CD2-36 68 CD2-5 1 69 CD2-12 70 CD2-20 7 1 CD2-58 72 CD2-52 73 CD2-18 74 CD2-40 75 CD2-30 76 CD2-55 77 CD2-43 78 CD2-05 If Ahead of Schedule: 79 CD2-31 Bottom Hole Well Location Service 61 Injector 74 Injector lnjector lnjector lnjector Producer Producer Producer lnjector lnjector lnjector lnjector Producer Producer 1 34 Producer 95 Producer Well Type Horizontal Horizontal Horizontal Horizontal Horizontal Horizontal Horizontal Horizontal Horizontal Horizontal Horizontal Horizontal Horizontal Horizontal Horizontal Horizontal Attachment 10 -Alpine Development: drilled and planned wells Wells drilled in 2002 are indicated as thick dark green (producers) and thick dark blue (injectors) lines. The wells planned for 2003 are those drawn up as thick light blue lines. Wells drilled prior to 2Q02 are indicated as thin dark green (producers) and thin dark blue (injectors) lines. Wells planned for 2004 are shown as thin black lines. 1 r96000 FEET &f 5000 FEET - Alpine C Gross Thickness CI = 10 ft