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Home My WebLink About2005 Prudhoe Oil and Put River Oil PoolsEf BP Exploration (Alaska) Inc. 900 East Benson Boulevard P. 0. Box 196612 Anchorage, Alaska 99519-6612 1907) 561-5111 March 14, 2006 John Norman, Chairman Alaska Oil & Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, AK 99501 Re: ANNUAL RESERVOIR SURVEILLANCE REPORT WATER AND MISCIBLE GAS FLOODS PRUDHOE OIL POOL and PUT RIVER OIL POOL - 2005 Dear Chairman Norman, BP Exploration (Alaska) Inc., as the Operator of the Prudhoe Bay Unit, submit herewith a consolidated Surveillance Report for the Prudhoe Bay Waterflood Project, Miscible Gas Project, Gas Cap Water Injection Project, Field Gravity Drainage Area and Put River Oil Pool in accordance with the requirements of Conservation Orders 341C (originally CO 279), 341D and 559. This report covers the time period of January 1 through December 31, 2005. The Operators of the Prudhoe Bay Field reserve the right to alter the content of the analyses contained in this report at any time based upon the most recent surveillance information obtained. Any questions can be directed to the undersigned, or to David Lenig at 564-5301, david.lenig@bp.com. Sincerely, Gordon Pospisil Waterflood Resource Manager Greater Prudhoe Bay 564-5769 Attachments: Exhibits 1 through 12 Cc: A. Mitchell, BPXA S. Rix, ExxonMobil D. Kruse, CPAI G.P. Forsthoff, Chevron B. Brice, Forest Oil J. Williamson, AOGCC A. Copoulos, DNR T. Verseput, BPXA F. Paskvan, BPXA G. Pospisil, BPXA J. Buono, BPXA D. Zentmire, BPXA D. Lenig, BPXA K. Pitchford, BPXA March 14, 2006 This letter is to confirm that the office of the Alaska Oil and Gas Conservation Commission, has received a copy of the ANNUAL RESERVOIR SURVEILLANCE REPORT WATER AND MISCIBLE GAS FLOODS PRUDHOE OIL POOL and PUT RIVER OIL POOL - 2005 Received by: � L A I q � 1-�:) ( 0 a Oil & Gas Conservation Commission Employee I bate ANNUAL RESERVOIR SURVEILLANCE REPORT WATER AND MISCIBLE GAS FLOODS PRUDHOE OIL POOL JANUARY THROUGH DECEMBER 2005 2005 ANNUAL RESERVOIR SURVEILLANCE REPORT PRUDHOE BAY UNIT CONTENTS SECTION PAGE 1.0 INTRODUCTION 5 2.0 OVERVIEW 6 3.0 PRESSURE UPDATE 7 3.1 Pressure Monitoring 7 3.2 Pressure Plan 7 4.0 PROJECT SUMMARIES 8 4.1 Flow Station Two Water / MI Flood Project 8 4.2 Eastern Peripheral Wedge Zone Water / MI Project 9 4.3 Western Peripheral Wedge Zone Water / MI Project 10 4.4 Northwest Fault Block Water / MI Project 11 4.5 Eileen West End Waterflood Project 12 4.6 Gas Cap Water Injection Project 13 4.6.1 Reservoir Pressure 4.6.2 Injector Status, Zonal Conformance, and Water Movement Surveillance 4.6.3 Reservoir Evaluation 4.6.4 2006 Surveillance Plans 4.6.5 Plans for Change in Project Operation 4.7 Put River Pool 18 5.0 GAS MOVEMENT SURVEILLANCE 19 5.1 Gas Movement Summary 19 Page 2 2005 ANNUAL RESERVOIR SURVEILLANCE REPORT PRUDHOE BAY UNIT LIST OF EXHIBITS 1-A Prudhoe Bay Unit Field Schematic 1-B PBU Well Statistics 1-C PBU Production / Injection Statistics 1-D PBU Pressure Map 1-E Areally Weighted Average Pressure Plot 1-F Areally Weighted Pressure Pressure Data 1-G Average Monthly CGF MI Rates and Compositions 2 Fieldwide Reservoir Balance 3-A FS-2 Base Flood Map 3-B FS-2 Reservoir Balance 3-C FS-2 Areal Average Reservoir Pressure 3-D FS-2 Daily Average RMI 4-A EPWZ Base Flood Map 4-B EPWZ Reservoir Balance 4-C EPWZ Areal Average Reservoir Pressure 4-D EPWZ Daily Average RMI 5-A WPWZ Water/MI Flood Base Map 5-B WPWZ Reservoir Balance 5-C WPWZ Areal Average Reservoir Pressure 5-D WPWZ Daily Average RMI 6-A NWFB Base Flood Map 6-B NWFB Reservoir Balance 6-C NWFB Areal Average Reservoir Pressure 6-D NWFB Daily Average RMI 7-A EWE Base Flood Map 7-B EWE Reservoir Balance 7-C EWE Daily Average RMI 8 Wells Surveyed for Gas Movement 9 Pressure Surveys 10 SI Well List 11-1 PSI Daily Injection History 11-2 PSI Pressure Data 11-3 Prudhoe Bay Pressure History-GD 11-4 PSI-05 Temperature Warmback Survey 11-5 2004 PSI Injection Profiles Page 3 2005 ANNUAL RESERVOIR SURVEILLANCE REPORT PRUDHOE BAY UNIT 11-6 Pressure vs. Rate Plots for PSI-01, PSI-06, PSI-08, PSI-09, and PSI-10 11-7 Pressure vs. Rate Plots for PSI-05 and PSI-07 11-8 Hall Plots 11-9 L3-05 Neutron Logs 11-10 GCWI Locater Map 11-11 Water Bank Cross-section Interpretation - 3rd Quarter 2003 11-12 Water Bank Cross-section Interpretation - 3rd Quarter 2004 11-13 Water Bank Cross-section Interpretation - 3rd Quarter 2005 11-14 Comparison of Water Bank Extent via Different Methologies 12 Put River Lobe Map Page 4 2005 ANNUAL RESERVOIR SURVEILLANCE REPORT PRUDHOE BAY UNIT 1.0 INTRODUCTION As required by Conservation Orders 341C (Approved June 12th, 1997), 341D (Approved November 301h, 2001) and 559 (Approved November 22, 2005) this report provides a consolidated waterflood and gas oil contact report summary of the surveillance activities for the Waterflood Project, Miscible Gas and Gas Cap injection projects, and the Gravity Drainage Area within the Prudhoe Oil Pool plus a new section for the newly created Put River Pool. The time period covered is January through December of 2005. In keeping with the requirements of the Conservation Order the report format provides information for each of the five major flood projects and the gravity drainage project in the field, where applicable, as follows: • Analysis of reservoir pressure surveys and trends • Progress of the enhanced recovery projects, including the gas cap water injection project • Voidage balance by month of produced and injected fluids • Data on Minimum Miscibility Pressure (MMP) of injected miscible gas • Summary of Returned Miscible Injectant (RMI) volumes • Results of gas movement and gas -oil contact surveillance efforts. • Results of pressure monitoring efforts • Table of wells shut-in during 2005 calendar year Separate sections are provided for the five major flood areas: Flow Station 2 (FS-2), Eastern Peripheral Wedge Zone (EPWZ), Western Peripheral Wedge Zone (WPWZ), North West Fault Block (NWFB), Eileen West End (EWE) along with information on the GCWI in the Gravity Drainage region and the Put River Pool. Water and miscible gas floods are described in each section. A separate section has been provided with detailed information on gas -oil contact surveillance. As agreed last year with the Commission, the discussion of Gas Production Mechanisms was not included in the report. Page 5 2005 ANNUAL RESERVOIR SURVEILLANCE REPORT PRUDHOE BAY UNIT 2.0 OVERVIEW Exhibit IA identifies the five flood areas and gravity drainage areas in the Prudhoe Oil Pool as follows: FS-2, EPWZ, WPWZ, NWFB, EWE, and GD. The Waterflood Project encompasses all five flood areas. The Prudhoe Bay Miscible Gas Project (PBMGP) is currently active throughout the waterflood areas. The Eileen West End waterflood pilot concluded in March 1999, after successfully establishing EWE injection potential. Waterflood startup began in September 2001, EWE information is included in this report. Exhibits 1-B and 1-C provide well, production, and injection statistics for the major project areas included in this report. As in last years' report, wells do not share project boundaries, but belong to a single project area. The well counts therefore reflect the total number of wells actually contributing to production and injection. Similar to last year, only wells that actually produced or injected during the year are included. During the report period of January through December 2005, field production averaged 325 MBOD, 7,936 MMSCFD (GOR 23,809 SCF/STB), and 1,130 MBWD (water -cut 78%). Waterflood project injection during this period averaged 1,132 MBWD with 214 MMSCFD of miscible gas injection. Cumulative water injection in the five major projects from waterflood startup through December 2005 was 9,513 MMSTB, while cumulative MI injection was 2,671 BCF. Cumulative production since waterflood startup was 2,628 MMSTB oil, 8,194 BCF gas, and 6,113 MMSTB water. As of December 31, 2005, cumulative production exceeded injection by 3,876 MMRB compared to 3,441 MMRB at the end of 2004. Similar to last year, production and injection values have been calculated based upon the waterflood start-up dates for the project areas rather than for each injection pattern. Exhibit 1-D provides analysis of pressure static, buildup, and falloff data that was collected during 2005 at a datum of 8,800 ft, subsea for the Full Field Dominant Zone. As in the past, abnormal pressures, such as pressures taken in fault compartments and in the Sag Formation have been removed. The historic pressure decline appears to have stabilized with about two- thirds of the repeat pressure surveys actually increasing in the past year. For 2005, average pressure in the PBMGP project areas was calculated to be 3,314 psia by areal weighting, as compared to 3,290 in 2004. The GD area also showed a slight pressure increase from 3,239 psia in 2004 to 3,250 in 2005. This pressure stabilization can be attributed to several factors, including increased injection throughout the project areas and in the way the average pressure was calculated, which is explained on page 7. Confirmed MI breakthrough has occurred in 175 wells during the reporting period. RMI production is an indicator of FOR pattern performance and the presence of RMI is determined by gas sample analyses that show a separator gas composition richer in intermediate range hydrocarbon components. MI breakthrough in a well is considered to have occurred when the average RMI rate over the number of producing days in a well exceeds 200 mcf/d. The previous year showed MI breakthrough in 164 wells. Most of the increase in RMI can be attributed to MI breakthrough in EWE wells. Exhibit 1-G shows the 2005 average monthly CGF MI rates and compositions for the field. Page 6 2005 ANNUAL RESERVOIR SURVEILLANCE REPORT PRUDHOE BAY UNIT 3.0 PRESSURE UPDATE 3.1 Pressure Monitoring Exhibit 9 provides pressure, buildup, and falloff data collected in 2005 at a datum of 8,800 ft, subsea used for the Full Field Dominant Zone. For this report and in the past, pressures taken in fault compartments, the Sag River Formation, and in Zone 1 of the G-Pad LPA (Low Pressure Area), which don't appear to be in communication with the rest of the reservoir, have been excluded from Exhibit 1-D. Also excluded this year were wells shut-in less than a week that obviously had not stabilized as compared to offsetting statics. Other wells completed in Zone 1 and Zone 413, which are in poor communication with the rest of the reservoir and therefore have lower pressures, were still included in the map and calculations. The excluded pressure measurements are listed separately in Exhibit 9 along with the reason for exclusion. Unless otherwise noted, all pressure calculations are areally weighted, bound by the main field original 50' LOC contour, and are referenced to a pressure datum of 8,800' SS. It was agreed with the commission that the polygon pressures would be calculated differently starting with the 2004 than in past reports. Exhibit 1-D shows the 2005 pressure map, which includes the pressure points only from the wells in which pressure data was gathered in 2005. This methodology will introduce more fluctuation in year-to-year average pressure due to the reduction in the number of data points utilized in producing the map. However the product is more reliable than the past methodology of trending past pressure trends. 3.2 Pressure Plan Per C. O. 341 C, Rule 6b, a pressure plan containing the number of proposed surveys for the next calendar year is required to be filed with this report. Prudhoe Bay reservoir depletion strategies are defined, and the goal of the pressure program is to optimize areal coverage and provide sufficient data for well safety. The proposed plan for 2006 calls for collection of 90 pressure surveys fieldwide. The number of surveys proposed is equal to last year. Per administrative approval 341C.01, dated June 22, 1999, a summary of pressure surveys run during 2005 is presented in Exhibit 9. Page 7 2005 ANNUAL RESERVOIR SURVEILLANCE REPORT PRUDHOE BAY UNIT 4.0 PROJECT SUMMARIES 4.1 Flow Station Two Water / MI Flood Project The Flow Station Two area, which comprises the eastern third of the Eastern Operating Area, is shown in Exhibit 3-A. The locations of production and injection wells are shown with the FOR injection patterns identified. There were 128 producing wells and 63 injection wells that contributed to production/injection during 2005 within the FS-2 flood area. Production/injection data was calculated with the polygon boundaries as in last year's report. The FS-2 waterflood area oil production averaged 42 MBOD for 2005 compared to 44 MBOD in 2004. Cumulative production since waterflood start-up through the end of 2005 is 991 MMSTB of oil, 3,674 BCF of gas, and 3,111 MMSTB of water. Injection rates averaged 649 MBWD and 81 MMSCFD in 2005. Since 12/31/04, the waterflood imbalance has increased from a cumulative under injection of 1,174 MMRB to 1,351 MMRB under injected. During the report period, production exceeded injection by 177.6 MMRB. Under -injection is related to PWI volumes being insufficient to replace all of the production volumes. Waterflood strategy is to replace voidage on a zonal basis by obtaining additional SWI by converting selective injectors at DSO4 to SWI in addition to DS11. Conversion of 4 DS-9 producers to Produced Water injection (PWI) was started in 2005 and should be online in early 2006. The additional PWI capacity supplied by these wells will allow conversion of additional DSO4 injectors to Sea Water Injection (SWI). Cumulative water injection since waterflood start- up through the end of 2005 is 4,962 MMSTB. The flood area's GOR increased from an average of 15,530 SCF/STB in 2004 to an average of 17,530 SCF/STB in 2005, with slight improvement seen after converting DS11 to SWI. Gas influx continues along the FS02/GD GDWFI area, and in the high permeability conglomerates in the Updip Victor area. Water -cuts increased slightly to 93% in 2005. A breakdown of the production and injection data is provided in Exhibit 3-13 for the report period. See Exhibit I-C for a comparison of the cumulative figures with last year's AOGCC report. Exhibit 3-C presents the areal average waterflood pressure decline over time. The pressure in the FS2 area was 3,338 psia in 2005. This is an increase of 61 psi over the 2004 pressure. This increase was caused in part by the inclusion of a 20 day shut-in of injector, 9-25 which still had a relatively high bottom -hole pressure value of 3,890. Exhibit 3-D is a presentation of 2005 average returned MI (RMI) rates. Miscible gas return has been confirmed in 42 wells by gas compositional analysis (RMI>200 MSCFD). Page 8 2005 ANNUAL RESERVOIR SURVEILLANCE REPORT PRUDHOE BAY UNIT 4.2 Eastern Peripheral Wedge Zone Water / MI Flood Project The Eastern Peripheral Wedge Zone (EPWZ) water and miscible gas (MI) flood area is shown in Exhibit 4-A. In 2005, oil production averaged 23.1 MBOD with an average 89% water cut and 17,840 SCF/STB Gas Oil Ratio. Injection averaged 193.6 MBWD and 33 MMSCFD of miscible injectant (MI). There are a total of 73 producers and 33 injectors in the flood area that contributed to production/injection during 2005. Of the 33 injectors, 8 injected miscible gas at some point throughout the year, while the remaining wells injected water only. Production and injection values have been calculated using polygon boundaries as revised in last year's report. Two waterflood start-up dates have been used, 12/30/82 for the DS 13 flood and 8/20/84 for the down -dip sections, rather than the start-up dates of each injection pattern. A total of 580 MMSTB of oil, 2,054 BSCF of gas, and 1,215 MMSTB of water have been produced with 1,699 MMSTB of water and 598 BSCF of miscible gas injected. Exhibit 4-B shows the monthly injected and produced volumes on a reservoir barrel basis during 2005 and provides cumulative volumes since injection began. During the report period, production exceeded injection by 123.1 MMRB. Exhibit 4-C shows the trend of reservoir pressure decline in the EPWZ flood area with time. The area receives pressure support from pattern injection, some aquifer influx, and GCWI. Faulting and out of conformance injection can impair flood performance in some areas. Areas of low pressure are being addressed by flood management strategies designed to increase voidage replacement. The EPWZ pressure was 3,344 psia in 2005. This is an increase of 20 psi since 2004. Exhibit 4-D shows the 2005 average of estimated RMI rates in producers, as calculated from well tests and from numerous produced gas sample analyses. Miscible gas returns have been confirmed in 33 wells (RMI <200 MSCFD). Page 9 2005 ANNUAL RESERVOIR SURVEILLANCE REPORT PRUDHOE BAY UNIT 4.3 Western Peripheral Wedge Zone Water / MI Flood Project Exhibit 5-A is a map of the WPWZ water and miscible gas flood areas. During the report period oil production averaged 26.7 MBOD at a gas/oil ratio of 9,600 SCF/STB and a watercut of 84%. Injection averaged 117.4 MBWD of water and 38.1 MMSCFD of miscible injectant. For the WPWZ project, 35 injectors (II WAG injectors and 24 water injectors), and 103 producers contributed to the production and injection during 2005. The well counts reflect only the active wells for the year. The waterflood startup date for the WPWZ project area was September 1985, corresponding to the start of injection in the Main Pattern Area (MPA). The production and injection data for the project reflect this startup date. Consistent with last year, production and injection data are calculated on the single area basis. Cumulative water injection from waterflood start-up through December 2005 was 1,382 MMSTB while cumulative MI injection was 528 BSCF. Cumulative production since waterflood start-up is 463 MMSTB oil, 1,218 BSCF gas, and 911 MMSTB water. As of December 31, 2005 cumulative production exceeded injection by 586 MMRB. Exhibit 5-13 provides the monthly injection and production data from 01105 through 12/05. During the report period, production exceeded injection by 88.5 MMRB. During 2001, WPWZ injection targets were modified to take into account aquifer influx occurring along the GDWFI boundary, and super pattern management of the WPWZ waterflood to stabilize the GOC. The reservoir balance in Exhibit 5-13 doesn't identify support from the aquifer, thereby understating voidage replacement. Exhibit 5-C shows that the pressure in the WPWZ was 3,282 psia in 2005. This is an increase of 1 psi over the pressure reported in 2004. Exhibit 5-D indicates wells with MI breakthrough and the 12-month averaged returned MI rates. Miscible gas breakthrough has been confirmed in 48 wells by gas compositional analysis. Page 10 2005 ANNUAL RESERVOIR SURVEILLANCE REPORT PRUDHOE BAY UNIT 4.4 Northwest Fault Block Water / MI Flood Project Exhibit 6-A is a map of the NWFB WAG flood areas. During the report period, oil production averaged 16.8 MBOD at a gas/oil ratio of 7,685 SCF/STB and a watercut of 85%. Injection averaged 130.9 MBWD and 33 MMSCFD of miscible injectant. For the NWFB project, 31 injectors (9 WAG injectors and 22 water injectors), and 72 producers contributed to the production and injection during 2005. The well counts reflect the number of wells actually contributing to production/injection during the reporting period. Production and injection values have been calculated based upon the start-up date for the project area, 8/13/84. Consistent with last year, production and injection data are calculated on the single area basis. Cumulative water injection from waterflood start-up in August 1984 through December 2005 was 1,441 MMSTB while cumulative MI injection was 650 BCF as detailed in Exhibit 61-C. Cumulative production since waterflood start-up was 566 MMSTB oil, 1,110 BSCF gas, and 818 MMSTB water. As of December 31, 2005 cumulative production exceeded injection by 301 MMRB. Exhibit 6-13 provides the monthly injection and production data from 01105 through 12/05. During the report period, production exceeded injection by 25 MMRB. However, this does not include support obtained from aquifer influx or gas cap expansion. The areally weighted pressure in the NWFB area was 3,289 psia in 2005. This is a decrease of 7 psi over last year. The historical pressure trend can be seen in exhibit 6-C. The increase in 2004 was largely due to the fact that this polygon's boundaries were expanded to the northwest with the presense of aquifer area affecting the overall pressure of the northwest fault block. This year's slight decrease in pressure is related to a reduction in the extrapolated pressure over this area. The contours over the heart of the NWFB waterflood actually demonstrated increased values. Exhibit 6-D indicates wells with MI breakthrough and the 12-month average returned MI rates. Miscible gas breakthrough has been confirmed in 41 wells by gas compositional analysis. Page 11 2005 ANNUAL RESERVOIR SURVEILLANCE REPORT PRUDHOE BAY UNIT 4.5 Eileen West End Waterflood Project Exhibit 7-A is a map of the EWE waterflood area. During the report period, oil production averaged 18.9 MBOD at a gas/oil ratio of 3,836 SCF/STB and water cut of 70%. Injection averaged 41.2 MBWD and 28.9 MMSCFD of gas. For the EWE project, 14 injectors (7 WAG injector, 7 water injectors), and 62 producers contributed to the production and injection during 2005. The well counts reflect only the active wells for the year. Cumulative water injection from waterflood start-up in September 2001 through December 2005 was 30 MMSTB and cumulative MI injection was 26 BCF. Cumulative production since waterflood start-up was 29 MMSTB oil, 138 BCF gas, and 58 MMSTB water. As of December 31, 2005 cumulative production exceeded injection by 145 MMRB. Exhibit 7-13 provides the monthly injection and production data from January 1, 2005 through December 31, 2005. During the report period, production exceeded injection by 21 MMRB. The EWE pressure was 3,542 psia in 2005. Average pressure decline for this area was 72 psi from 2004. This decrease is largely attributed to the reduction in extrapolated pressure contours induced by the inclusion of a low pressure point for L-02A. Pressure values in the heart of the EWE flood are very similar to 2004 values. The lone well with pressures in both reporting periods measured a 50 psi increase. Exhibit 7-D indicates wells with MI breakthrough and the 12-month average returned MI rates. Miscible gas breakthrough has been confirmed in 11 wells by gas compositional analysis. Page 12 2005 ANNUAL RESERVOIR SURVEILLANCE REPORT PRUDHOE BAY UNIT 4.6 Gas Cap Water Injection Project Details of the Volume of Water Injected during 2005 are detailed below; units in thousands of barrels of seawater injected per month (MBWM): Month PSI-01 PSI-05 PSI-06 PSI-07 PSI-08 PSI-09 PSI-10 Total Jan 3,217 2,616 2,789 2,480 2,807 2,888 2,407 19,205 Feb 2,931 2,510 2,866 2,416 2,828 2,839 2,837 19,228 Mar 2,926 2,727 2,866 2,732 2,653 2,778 2,838 19,519 Apr 2,001 2,150 2,533 2,019 1,067 2,515 2,534 14,819 May 2,787 2,551 2,680 2,112 2,346 2,828 2,602 17,906 Jun 2,423 1,844 2,061 1,536 2,029 263 2,078 12,235 Jul 3,356 2,540 3,221 2,544 3,206 1,345 3,229 19,441 Aug 2,209 1,610 1,904 1,447 1,720 1,575 1,567 12,032 Sep 1,795 1,359 1,996 1,574 2,013 1,983 1,598 12,318 Oct 2,839 2,552 2,974 2,332 2,650 2,989 0 16,336 Nov 1,030 2,939 3,313 2,548 2,963 3,362 0 16,155 Dec 2,201 1,852 2,628 971 1,603 2,108 0 11,363 Total 29,715 27,252 31,831 24,712 27,885 27,472 21,690 190,557 Exhibit 11-I shows the GCWI history since project start up. While rates have been constrained by water supply throughout most of the project, on going operating improvements in the Sea Water Treatment Plant (STP) and the Sea Water Injection Plant (SIP) will continue to increase the volume of water injected. The 2005 volume injected exceeded the 2004 volume by nearly 50 MMBW. 4.6.1 Reservoir Pressure Five static bottom hole pressure surveys (SBHP) were taken on the injectors in 2005. Both the pressure at 8,400' and the extrapolated pressure at 8,800' SS datum are given in the table below. 8400' SS Datum 8800' SS Datum Well Date Press(psi) Press (psi) PSI-05 08/21/05 3,366 3,464 PSI-07 08/16/05 3,418 3,516 PSI-08 04/27/05 3,427 3,525 PSI-10 01/04/05 3,422 3,520 PSI-10 10/21/04 3,449 3,547 Exhibit 11-2 shows a map with all the SBHP's run to date in the PSI injectors. The 2002 pressures were taken either before or shortly after Gas Cap Water Injection began, and therefore represent the local gas cap pressure prior to GCWI. Initial pressures ranged between 3,325 psi and 3,401 psi at 8,400' SS which extrapolate to 3,423 psi to 3,499 psi at the 8,800' datum. Page 13 2005 ANNUAL RESERVOIR SURVEILLANCE REPORT PRUDHOE BAY UNIT The 2005 SBHP's showed pressures increased between 12 psi to over 50 psi from the 2002 base pressures. Incremental pressures since 2002 are noted in Exhibit 11-2. The one exception to this trend is PSI-05 which showed a decrease of 31 psi from 2004. The quality of the 2005 SBHPS for this well is suspect. Pressures are given for both an 8,400' datum and the standard 8,800' datum. As noted in the 2005 report, extrapolating the PSI pressures to the 8,800' pressure datum of the Prudhoe field is not a straight forward process since BSAD lies around 8,500' SS in the PSI injectors. It does not fall below 8,800' until nearly 4,000 lateral feet away. Estimating the depth of the GOC introduces uncertainty into the 8,800' extrapolation. Gauge pressures were first adjusted to 8,400' SS since all the SBHP's were made very close to 8,400' SS. This allowed a good comparison of pressures over time without introducing the uncertainty of extrapolating to 8,800' SS. To be consistent, the same correction (98 psi) was made to each of the 8,400' SS pressures to obtain the pressure at the 8,800' SS datum. The overall goal of the GCWI project is to slow the Prudhoe field pressure decline. To see this effect, all SBHP's from the gravity drainage areas of the field were pulled and plotted as shown in Exhibit 11-3. Because local waterflood pressures are quite variable, they introduce a wide scatter in the field pressure plot making interpretation of pressure trends difficult. The waterflood SBHPS were not included for this reason. The low pressure area at G Pad has also been excluded from Exhibit 11.3 to give a tighter grouping of pressures. (G Pad has areas of low pressure due to local geology which are not representative of the gravity drainage pressures). The change in slope at waterflood start up in 1984 is very pronounced, with declines of 80 to 90 psi/ year pre- waterflood dropping to approximately 35 psi/year after start up. The slope change is apparent only because there are long term stable trends both before and after waterflood start-up. The next obvious slope change occurs shortly after the GCWI project begins injecting in 2002. Although more data is required before reaching definitive conclusion, it appears the GCWI is achieving its goal and has stabilized field pressure decline. 4.6.2 Injector Status, Zonal Conformance, and Water Movement Surveillance Injector Status All seven of the GCWI injectors are in good mechanical condition and continue daily injection. Pressure -rate plots for each well are routinely monitored and show injectivity is quite healthy. Each of the five original wells is capable of injecting well over 100 MBWPD at injection pressures between 1,400 psi and 1,800 psi. Erosional velocity limits injection to under 110 MBWPD. PSI-05 and PSI-07 were drilled in the Fall of 2003 but didn't begin injection until Fall 2004. Both wells were shot solely in Zone 113, and are capable of injecting at rates approaching 100 MBWD with injection pressures just over 2,000 psi. There are no plans at present to add additional perfs in either of these two wells. The current perfs strategy will provide Zone 1 Page 14 2005 ANNUAL RESERVOIR SURVEILLANCE REPORT PRUDHOE BAY UNIT injection. Injection logs run on the original five wells have shown Znl injection is not likely as long as Zones 2A and 3 are open. 4.6.3 Injection Profiles and Zonal Conformance Temperature warmback surveys were run in the two new wells (PSI-05 and PSI-07) in 2005. The purpose was to verify that injection was remaining in the Ivishak. The surveys were run over the Ivishak formation and up to the West Sak sands around 6,200' SS. These sands are the first significant sands that would likely take water if there was an extended channel behind pipe. Each of the original 5 injectors had 3 warmback surveys run prior to 2005. All of the temperature warmback surveys clearly showed injection was contained within the Ivishak formation and that there was no injection out of zone. Exhibit 11-4 shows the results of the temperature warmback survey for PSI-05. The log for PSI- 07 was very similar. The warmback survey showed that not only was injection confined to the Ivishak, it is also confined to Zone 1B within the Ivishak. Zone 113 is significantly cooler than the other zones and showing little change with time due to the heat capacity of the injected water. Just above Zone 1B, the temperature is significantly warmer and changing rapidly due to the low heat capacity of the gas. The conclusion for both PSI-05 and PSI-07 is that injection is confined to the perforated Zone 1B sands. Exhibit 11-5 shows the current perfs for each of the PSI injectors along with the 2004 spinner results. As expected Zones 3 & 2C dominate the injection due to higher permeability. Zone 1 gets little injection with the exception of PSI-05 and PSI-07 which are currently dedicated Zone IB injectors. Zone 2 is split into several sands by the thick and extensive Tango shales. The spinner results show that each of the sands receives at least 5%-15% of the total injection. Exhibits 11-6 and 11-7 show some of the routine monitoring that is done on the PSI injectors. The first exhibit shows the pressure rate plots for each of the original 5 injectors. All five wells have extremely good injectivity after more than 3 years of injection. Each injector is capable of injecting well over its current velocity rate restriction of 110,000 BWPD. Injectivity is also stable as seen by the last 90 days of injection (red markers). Problems or injectivity changes will cause the last 90 days to move outside the normal "envelope". If this happens additional diagnostics will be done to determine the cause of the change. Exhibit 11-7 shows the same plots for PSI-05 and PSI-07 while Exhibit 11-8 shows Hall plots for each of the seven injectors. All plots show stable and healthy injectivity. PSI-05 and PSI-07 have significantly less injection per psi since they are only perfed in Zn 1B. Observation Well RST Survey The RST surveys run in offset producers is the primary means of monitoring water movement from the Gas Cap Water Injection project. Baseline RST's were run over the Ivishak formation in 11 Lisburne observation wells prior to GCWI start-up. These wells have been logged repeatedly since injection began at intervals of 4-6 months to monitor water movement. Despite the fact the Ivishak lies above the packer and behind two strings of pipe, the RST's have given clear and confident gas and water picks as shown in Exhibit 11-9. By comparing the RST logs with the baseline and previous logs, the presence of water can be readily observed. This Page 15 2005 ANNUAL RESERVOIR SURVEILLANCE REPORT PRUDHOE BAY UNIT procedure has provided a very clear picture of water in the Ivishak formation and allows monitoring how quickly the water column builds. Exhibit 11-10 is the locator map for the GCWI area and shows the PSI injectors along with the observation wells. The information from the RST logging program was used to develop the cross sections (Exhibits 11-13) showing our interpretation of the surveillance data for the time periods of 1, 2, and 3 years after injection began. Water was initially seen on top of the 24N shale in L3-05 and L2-32 after one year of injection. Since that time water has continued to build vertically in each well as shown on the logs. L2-32 also has water in Zone 2A on top of a large shale. Water first appeared in L3-02 in early 2004 sitting on top of both the 23N and 24N shales. Each of the wells has shown that the water first appears on top of the 23N and 24N shales and begins to build height climbing from Zn 2B into Zones 2C and 3. Along with the offset Lisburne wells, PSI-05 and PSI-07 were used as additional observation wells for the year they sat waiting for injection to begin. A total of 4 RST's were run in PSI-05 with only 3 run in PSI-07. Water was already present at the time of drilling in both wells. In each case water was sitting on top of significant shales in Zones 2A, 213, and 2C. Subsequent RST's in 2004 showed the water quickly climbing until each zone was filled. In all cases the sands filled from the bottom up with no indication of thief zones in either well. By the time these two wells were put on injection in the Fall of 2004, both wells were full of water from Zone 2A and above. PSI-07 also had a small amount of water in Zone 113. Continued RST surveillance has shown that water first appears on top of a major shale then builds height with time. There has been no indications of water running down thief zones or high perm intervals. The flood front appears to maintain a sloped aspect indicating that gravity has a strong influence on the process. The flood is behaving as expected. The RST program is providing high quality information in areas with observation wells, however as Exhibit 11-10 shows there is a lack of observation wells to the north and northwest. There are few well penetrations in the area and what few are present are not available for logging (gas injectors, collapsed tubing, etc...). A gravity survey and a reservoir model are being used to provide information for the areas the RST survey cannot access. Gravity Survey A gravity survey is being done to provide an independent technique of water movement surveillance. There are no blinds spots with the gravity survey as there are with the RST program. Baseline gravity surveys were completed in 2002 and 2003 before significant amounts of water had been injected. A survey was not completed in 2004 because the cumulative injection did not put enough water into the formation for the gravity survey to definitively see above the noise. By March 2005, 340 MMBW had been injected and a third survey was made. The 2005 survey had signal responses over three times the base noise level. The results of the gravity survey placed the water in general agreement with the RST Page 16 2005 ANNUAL RESERVOIR SURVEILLANCE REPORT PRUDHOE BAY UNIT information with the exception of the northerly direction. The gravity survey did not show water as far north as would have been expected from the reservoir model and RST surveillance as can be seen in Exhibit 14. A survey will be repeated in 2006. 4.6.4 Reservoir Evaluation The original reservoir model for the GCWI project was an extracted area of the Prudhoe Bay Full Field Model using 60 acre grid cells. The large scaling didn't permit detailed evaluation of water movement over the small area of water injection to date. A revised model has been completed with a refined grid down to 100' in the GCWI injector area. The grid size increases in steps back up to 60 acres along the periphery of the model. Along with the local grid refinements, a new reservoir description with considerably more detail over the gas cap area has been incorporated into the model. The model was history matched using the RST observation well data and is now functional. A comparison between the refined model and original model shows relatively good agreement with regard to water movement and timing. 4.6.5 2006 Surveillance Plans GCWI Injectors SBHP's will be obtained in most of the GCWI injectors during 2006. Injection pressures, rates, and temperatures are recorded for each well every day. Pressure -rate plots and Hall plots will be routinely monitored for changes in injectivity of the well. Observation Well RST's RST's will be run every 4-6 months in 2006. This program will continue as it has in the past by running RST's every 4-6 months with the final timing and locations determined based on the results to date. Gravity Survey A gravity survey is planned for 2006 and should be completed by mid April. Final processing, modeling, and analysis will be completed in the third quarter. 4.6.6 Plans for Change in Project Operation No changes to the Gas Cap Water Injection plan are expected in 2006. Page 17 2005 ANNUAL RESERVOIR SURVEILLANCE REPORT PRUDHOE BAY UNIT 4.7 Put River Oil Pool On November 22, 2005 the AOGCC ruled in Conservation Order 559 that the Western, Central and Southern Lobes of hydrocarbon bearing Put River sands would be defined as the Put River Pool and that the Northern lobe would be included in the Prudhoe Oil Pool. Exhibit 12 displays all four lobes which are in pressure isolation from each other. Additional technical information was previously supplied with the application which lead to Conservation order 559. 2005 Production Two wells produced from the Put River Pool in 2005. In the Western Lobe, 15-41B produced a cumulative of 1.0 MBO and 23.2 MMscf gas during March and April. In the Southern Lode 2- 23A produced 91.5 MBO and 102.7 MMscf gas during January and February which was a continuation of production period started in September 2004. The 12/13/2005 cumulative production for 2-23A stands at 312MBO and 103 MMscf gas. 2005 Pressures Put River Pressures taken during 2005 are listed in Exhibit 9. The Western Lobe measured 4,173 psi at a datum of 8,100' subsea for 15-41 B prior to its brief production period. The Southern Lobe pressure was measured twice in 2-23A, shortly after it was shut-in and 9 months later. The longer shut-in pressure registered 2,729 psi at 8100' SS. 2006 Surveillance Plan Southern Lobe - Water injection support in the southern lobe of the Put River is anticipated to start in 2006. Repeat temperature logs will be run in the 1-08Ai injection well to confirm zonal isolation. A static reservoir pressure will be also be obtained in any new completion. Prior to initiating production from the Put River, a static pressure survey will be run to confirm the pressure affects of the injection support. Western Lobe - No 2006 production or surveillance planned. Central Lobe - No 2006 production or surveillance planned. Page 18 2005 ANNUAL RESERVOIR SURVEILLANCE REPORT PRUDHOE BAY UNIT 5.0 GAS MOVEMENT SURVEILLANCE The report on gas movement surveillance activities and interpretations provides an overall summary of gas influx movement and summarizes the 2005 gas -monitoring logging program. 5.1 Gas Movement Summary Fieldwide GOC surveillance continues with collection of open -hole and cased -hole logs and monitoring of well performance. In order to mor estimates are made across the field and are based historical well performance. The central portion o exhibits in some areas almost total influx of the essentially absent in the southern peripheral regions the waterflood areas. for gas movement in the reservoir, GOC pon the ongoing monitoring program and the field, the gravity drainage area (GD) �OC (Light Oil Column). Gas influx is as a result of water and WAG injection in It has become difficult in most parts of the field to define a single current GOC as the surface is commonly broken into a series of oil lenses and gas underruns beneath the shales. The reservoir is better characterized by a description of remaining oil targets. The targets within the GD occur within three general regions; the basal Romeo (Zones 1 & 2A) sands, the inter-underrun sands, and oil lenses within the expanded GOC. Production from the Romeo (Zones 1 & 2A) sands has historically been low compared to the more prolific upper zones. This interval has a lower net to gross, lower permeability and more limited sand connectivity than the rest of the reservoir. These factors impede gas expansion into the Romeo. Underruns beneath shales within the Romeo sands are likely to be local. The inter-underrun sands occur throughout the GD and are characterized by one or more underruns or solution gas pockets segmenting the remaining oil pad. Gas underruns are observed beneath the top of the Sadlerochit reservoir, under Zone 4 shales, and the most regional persistent underruns have developed under the mappable floodplain shales of Tango or Zone 2B. Oil within the expanded GOC occurs in lenses above regionally continuous shales. Such lenses have been identified from neutron logs. Many lenses continue to exhibit oil drainage over time, while others appear isolated. Exhibit 8 lists the open and cased -hole neutron logs, as wells as RST logs, run in the Prudhoe Bay Unit during the gas -influx reporting period from January 2005 through December 2005. A total of 52 gas -monitoring logs, all cased -hole logs were run in the PBU. Page 19 2004 AOGCC Report Producers Injectors -WAG -Water Only -Gas 2005 Producers Injectors -WAG -Water Only -Gas Production Well Status in 2005 -Newly Drilled -Sidetracked or Redrilled Gas Injection Well Status in 2005 -Newly Drilled -Sidetracked or Redrilled WAG Injection Well Status in 2005 -Newly Drilled -Sidetracked or Redrilled Water Injection Well Status in 2005 -Newly Drilled -Sidetracked or Redrilled Exhibit 1-13 PBU Well Statistics WELL COUNT BY FIELD AREA WPWZ NWFB EWE FS2 EPWZ GD 101 76 58 118 71 485 37 32 10 65 33 46 13 9 2 8 7 1 24 23 6 56 25 12 0 0 2 1 1 33 103 72 62 128 73 479 35 31 14 63 33 47 11 9 7 9 8 3 24 22 7 54 25 12 0 0 0 0 0 32 0 0 2 0 0 0 2 0 5 0 3 28 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 1 0 0 1 1 0 0 0 0 0 0 0 1 0 0 0 1 0 NOTES: (1) Well count data reflects ONLY those wells which contributed to production/injection during the respective year. (2) Project boundaries were simplified in 1998. Wells no longer share project boundaries, but belong to a single project area. (3) EOA GD and WOA GD have been combined. Exhibit 1-C 2005 PBU Production/Injection Statistics Waterflood Project Area Cumulative Production from WF Start -Up through 12/31/05 Oil (MMSTB) Gas (BCF) Water (MMSTB) Cumulative Injection from WF Start -Up through 12/31/05 Water (MMSTB) MI (BCF) Cumulative Balance from WF Start -Up through 12/31/04 Cum Production (MMRB) Cum Injection (MMRB) Over/Under (MMRB) Cumulative Balance from WF Start -Up through 12/31/05 Cum Production (MMRB) Cum Injection (MMRB) Over/Under (MMRB) MI Breakthrough in Producing Wells > 200 mcfd AVERAGE RATE DATA 200° Production Oil (MBD) Gas (MMSCFD) Water (MBD) Injection Water (MBD) Gas (MMSCFD) AVERAGE RESERVOIR PRESSURE (Dsial PreviousMid report period 7/04 Mid report period, 7/05 Estimated Annual Decline (psi/yr) Waterflood Total WPWZ NWFB FS-2 EPWZ EWE 463 566 991 580 29 2628 1218 1110 3674 2054 138 8194 911 818 3111 1215 58 6113 1382 1441 4962 1699 30 9513 528 650 869 598 26 2671 2237 2064 6554 3451 149 14456 1739 1788 5381 2082 25 11015 -498 -276 -1174 -1370 -124 -3441 2379 2147 6999 3656 193 15375 1793 1846 5648 2163 48 11499 -586 -301 -1351 -1493 -145 -3876 48 41 42 33 11 175 26.7 16.8 41.9 23.1 18.9 127.4 256.3 129.1 734.5 412.1 72.5 1604.5 139.3 96.6 534.7 180.9 44.3 995.9 117.4 130.9 649.0 193.6 41.2 1132.0 38.1 33.1 81.1 32.7 28.9 213.8 GD WPWZ NWFB FS-2 EPWZ EWE FIELDWIDE 3239 3281 3296 3277 3324 3614 3290 3250 3282 3289 3338 3344 3542 3314 11 1 -7 61 20 -72 24 Exhibit 1-D 14W CE NNNI INIRN flIN1 MNM NNNI ]INN 11MN RNM P]IIMI f1NN G. RRNGE LOIY ■ m1O11A11AM VJAWM MIL NOTE: Engineered control points were added to the Southeast portion of the field to provide more accurate contouring. External control points were also 2005 PRESSURE MAP ultilized to control contours. C0.al RPNGE 0. amrw �+w-sN 3900 3800 3700 3600 P 3500 S I A 3400 3300 3200 3100 3000 Exhibit 1-E Areal Average Pressure —F PBMGP areal avg P -*— Gravity Drainage 0 `mod '0N cO cO cO e0 e0 70 e0 e0 d9 79 C9 79 79 �9 h9 "O8 h99 hOO hO7 hO hO? hOF "OS "O6 "O u' St S 6 6 cP 9 7 2 F S 6'