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Home My WebLink About2009 Greater Point McIntyre AreaPrudhoe Bay Unit Lisburne Oil Pool 2010 Annual Reservoir Report This Annual Reservoir Report for the period ending March 31, 2010 is being submitted to the Alaska Oil and Gas Conservation Commission in accordance with 20 AAC 25.517. It covers the period between April 1, 2009 and March 31, 2010. Reservoir Management Summary Production and injection volumes for the 12-month period ending March 31, 2010 are summarized in Table 1. Oil production volumes include allocated crude oil, condensate and NGL production. Current well locations are shown in Figure 1. A total of 91 Lisburne wells (including P&A’d wells) have been drilled as of March 31, 2010. Oil recovery from the East and West areas of the Lisburne reservoir continues through a combination of solution gas drive and gas cap expansion supported by gas injection at LGI pad. Solution gas drive is the primary recovery mechanism in the Central area supplemented by weak aquifer influx. Reservoir Pressure Surveys within the Pool A summary of reservoir pressure surveys obtained during the reporting period is shown in Table 2. Two wells, NK-25 and NK-26, completed in the Alapah formation in the Eastern area of the field were shut-in on September 6, 2008 for reservoir management. However, static pressures have not been measured due to a judicial decision in the United States Court of Federal Claims limiting Operator’s right to use existing surface facilities to access these two wells. Results and Analysis of Production Logging Surveys Lisburne wells which had production logs run during the time period April 1, 2009 thru March 31, 2010 are shown in Table 3 along with relevant comments. Future Development Plans and Review of Plan of Operations and Development L5 Gas Cap Water Injection Surveillance The L5 GCWI pilot project commenced injection in July of 2008. The initial injection rate was 2 mbwipd, and over time has been gradually increased to the target injection rate of 13 mbwipd. On March 31, 2010 the cumulative volume of seawater injected in the L5-29 was 3,717 mbbls. No change has been observed in offset producer water-cuts, GOR or pressure response at this time. Three pressure fall-off (PFO) tests have been conducted in the well, The PFO analysis shows a constant pressure boundary, which is indicative of water moving into the matrix in the gas cap. The well is connected to a limited fracture as was shown by the PFO skin of between – 3.6 and -3.8. This skin value is consistent with the mud losses during drilling and has remained constant through all three surveys. The PFO’s have showed that the well and reservoir behavior is consistent with expectations and as a result the injection rate has been increased to the current value of 13 mb/d. Additional PFOs will be performed in the future for monitoring and surveillance of the injection well’s behavior. Offset well annuli pressures are reported monthly to the commission by the BP North Slope Well Integrity Engineer via the Monthly Injection Report sent to James Regg and Thomas Maunder. Waterflooding Pilot Projects A review of the Lisburne development plan identified water injection as a mechanism to provide additional support in the Lisburne reservoirs. Pilot water injection projects in the L3 and the L5 areas in the Wahoo formation are being considered. Due to a judicial decision in the United States Court of Federal Claims limiting Operator’s right to use existing surface facilities to access Alapah wells NK-25 and NK-26, waterflood pilot studies on the Alapah reservoir have been temporarily suspended. These projects are currently in the select and appraise stages of the planning process. Lisburne 2 ASR for Apr ’09 – Mar’10 Development Drilling No development drilling activity for the next reporting period has been approved. However, reservoir targets and parent well access points are being evaluated. Support Facilities Lisburne will continue to share North Slope infrastructure with the Point McIntyre and Niakuk fields to minimize duplication of facilities. Four wells from the IPA can produce to the LPC as part of the L2 Re-route Project: L2-03, L2-07, L2-11 and L2-13. Production Allocation The production of oil and gas, including those hydrocarbon liquids reported as NGLs, will continue to be allocated to the Lisburne Participating Area in accordance with conditions approved by the Alaska Department of Natural Resources, Alaska Department of Revenue, and Alaska Oil and Gas Conservation Commission. There is a test separator at each Lisburne Drill Site. Gas Sales The timing of Lisburne gas sales is dependent upon market demand and the availability of a transportation system. Prior to initiation of gas sales, Lisburne produced gas (other than gas extracted as NGLs and blended with crude oil for shipment to market) will be used or consumed for Unit Operations, or injected back into the Lisburne formation. Lisburne 3 ASR for Apr ’09 – Mar’10 Tables & Figures Oil Gas Water Oil Gas Water Monthly Cumul. Monthly Cumul mstbo mmscf mbw mstbo mmscf mbw mmscf bscf mbw mbw Apr-09 198 2,975 222 156,176 1,683,300 45,412 2,403 1,664 302 985 May-09 249 3,140 208 156,425 1,686,440 45,620 2,989 1,667 298 1,283 Jun-09 213 3,016 193 156,638 1,689,456 45,813 2,209 1,669 284 1,567 Jul-09 241 3,726 225 156,879 1,693,182 46,038 3,526 1,673 181 1,748 Aug-09 238 3,193 185 157,117 1,696,375 46,223 3,491 1,676 98 1,846 Sep-09 240 3,505 246 157,357 1,699,880 46,468 3,574 1,680 210 2,056 Oct-09 265 3,546 239 157,622 1,703,426 46,707 4,455 1,684 26 2,082 Nov-09 237 2,939 217 157,859 1,706,365 46,924 3,353 1,688 144 2,226 Dec-09 274 3,848 222 158,133 1,710,213 47,144 4,016 1,692 373 2,600 Jan-10 284 4,471 217 158,417 1,714,684 47,362 4,112 1,696 437 3,037 Feb-10 184 3,351 152 158,602 1,718,035 47,514 3,975 1,700 305 3,342 Mar-10 265 4,202 246 158,867 1,722,237 47,760 4,331 1,704 375 3,717 Table 1-Lisburne Monthly Production & Injection Volumes Water InjectionMonthly Production Cumulative Production Gas Injection Date Lisburne 4 ASR for Apr ’09 – Mar’10 Well Name Survey Date Pressure (psi) (Datum = -8900 SS) L1-14 6/9/2009 3,398 L1-21 4/9/2009 3,367 L1-30 4/10/2009 3,516 L2-16 2/15/2010 2,645 L2-28 5/31/2009 3,217 L3-05 7/31/2009 3,162 L3-11 9/30/2009 2,607 L3-11 10/6/2009 2,622 L3-12 9/26/2009 3,008 L3-15 9/27/2009 2,325 L3-18 10/1/2009 2,882 L3-19 6/4/2009 2,525 L3-19 10/1/2009 2,632 L3-22 8/2/2009 2,768 L3-23 8/6/2009 2,319 L3-24 9/27/2009 3,138 L3-30 8/20/2009 2,820 L3-31 7/1/2009 3,100 L3-31 8/3/2009 2,691 L4-03 4/12/2009 2,230 L4-10 4/12/2009 1,905 L4-10 2/13/2010 1,821 * L4-12 4/19/2009 2,999 L4-14 4/14/2009 3,030 L4-15 10/11/2009 3,108 L4-18 4/15/2009 2,838 L4-30 4/14/2009 1,943 L4-31 4/20/2009 3,491 L4-36 4/16/2009 3,637 L5-04 6/10/2009 2,917 L5-05 6/4/2009 3,060 L5-12 1/12/2010 3,170 L5-13 8/28/2009 3,343 L5-15 11/26/2009 3,277 L5-17A 2/14/2010 3,222 ** L5-18 11/24/2009 3,227 L5-21 4/22/2009 3,403 L5-21 9/5/2009 3,427 L5-23 9/3/2009 3,360 L5-26 1/24/2010 3,411 L5-28A 9/10/2009 3,420 L5-31 9/4/2009 3,384 L5-33 9/1/2009 3,455 L5-36 9/7/2009 3,473 LGI-04 9/10/2009 3,279 * Extrapolated from 14 day SI time ** Extrapolated from 16 day SI time Table 2-Lisburne Pressure Data April 1, 2009-March 31, 2010 Lisburne 5 ASR for Apr ’09 – Mar’10 Well Date Comments/Interpretation L1-09 8/8/2009 21% of oil, 83% of gas, 1% of water from 11314-11409'. 50% of oil, little gas, 56% of water from 11700-11750'. 29% of oil, 17% of gas, 43% of water from 11770-11786'. L1-21 5/24/2009 98% of oil and 100% of gas from 8793-8803'. Some oil from 8887-8892'. L1-30 6/22/2009 28% of oil, 47% of gas, 33% of water from 11566-11595'. 50% of oil, 44% of gas from 11608-11693'. 22% of oil, 8% of gas, 67% of water from 11704-11878'. L2-06 7/23/2009 71% of oil, 71% of gas, 53% of water from 8864-8880'. 16% of oil, 16% of gas, 7% of water from 8996-9046'. 6% of oil, 5% of gas, 1% of water from 9060-9081'. 7% of oil, 8% of gas, 39% of water from 9118-9198' L2-06 8/13/2009 Reperf/acid stim resulted in productoin from 8941-8983' L3-15 4/6/2009 Majority of flow from above 11850'. L3-31 7/9/2009 98% of production from 11247-11275'. Minimal production from lower perfs. L4-03 9/9/2009 63% of flow from 10379-10439, 12% from 10441-10559, 25% from 10611-10683 L4-30 8/5/2009 75% of flow, including all oil, coming from 9606-9652'. Remaining flow from 9675-9687'. L5-05 9/14/2009 90% of oil, 80% of gas from 12090-12168'. 10% of oil, 20% of gas, 100% of water from 12188-12270'. Table 3 - Lisburne Production Logging Lisburne 6 ASR for Apr ’09 – Mar’10 Figure 1-Lisburne Location and Status Map Lisburne 7 ASR for Apr ’09 – Mar’10 Prudhoe Bay Unit Niakuk Oil Pool 2010 Annual Reservoir Report This Annual Reservoir Report has been prepared for submission to the Alaska Oil and Gas Conservation Commission in accordance with Rule 9 of Conservation Order No. 329 for the Niakuk Oil Pool, as detailed in Administrative Approval No. 329.05, and pursuant to 20 AAC 25.517. This report summarizes the period from April 1, 2009 through March 31, 2010. a. Progress of Enhanced Recovery Project Implementation and Reservoir Management Summary The Niakuk waterflood was started in April 1995, in conjunction with the commissioning of permanent facilities at Heald Point, using water from the Initial Participating Area Seawater Treatment Plant. Produced water from the LPC was used between August of 2000 and May 2004. Conversion to use only seawater for injection was completed in September, 2004. Seawater was used for injection throughout this reporting period. All producing segments (1, 2, and 3/5) are receiving pressure support from water injection. There are 6 active injectors in the Niakuk Pool with an average total injection rate of approximately 28.8 mb/d. The current injection strategy is to continuously monitor and adjust seawater injection based on current production performance and voidage ratios. Reservoir Management Segment 1 NK-10 is the only injector in this segment and it supports four producers (NK- 07A, NK-27, NK-61A and L5-34). The producers in this segment appear to be in good communication with the injector. Brightwater was injected into NK-10 in October 2008 to improve sweep and to date no response has been observed. Production from the segment averaged 854 BOPD for the reporting period with a watercut of about 88%. Water injection in NK-10 averaged approximately 5.4 MBWPD for the period. Prior to waterflood startup in this segment, reservoir pressures showed a consistent drop over time. Water Niakuk Oil Pool Page 1 2010 Annual Reservoir Report injection volumes replaced reservoir voidage through the end of 1997 and since then over injection has increased reservoir pressure. The number of production and injection wells at the start and end of the reporting period was the same. Plans are to generally maintain voidage replacement and keep reservoir pressure at the current level. No conversions of producers to injectors are currently envisioned Segment 3/5 At the beginning of the reporting period, there were four producers (NK-08A, NK-09, NK-12C, and NK-29), three active injectors (NK-13, NK-15, and NK- 28), one inactive injectors (NK-17) and one suspended well, NK-14A. Well NK- 17 had injectivity problems and was converted to producer in Dec. 2000. The conversion of NK-17 to production was not beneficial and the well has been shut in since 1/30/2001. NK-13 was placed back on injection on July 08 after flowline repairs were completed. Water injection rate for the segment averaged approximately 11 MBWPD for the reporting period. Production and pressure data suggests good communication between injectors and producers. Oil production for the segment averaged 1579 BOPD for the reporting year with a watercut of 81%. Production from this segment began in February 1995 from NK-09 under primary depletion. Reservoir pressure dropped approximately 500 psi during this period but stabilized after water injection startup in May 1997. Plans are to maintain voidage replacement and keep reservoir pressure at the current level. NK-13 and NK-28 were converted to injection service on 4/3/02 and 8/13/01 respectively, to improve both sweep efficiency and voidage replacement. Segment 2 Segment 2 contained 3 producers (NK-20A, NK-22A and NK-43) and 3 injectors (NK-16, NK-18, and NK-23) at the start of the reporting period. Like all other segments in the field, the reservoir management strategy in this segment is to replace the voidage created by hydrocarbon production with water injection. Water injection was initiated in the high-permeability sands in the upper portion of the reservoir in NK-23 in May 1995. NK-23 was converted to an injector on 07/1995 and had remained on injection supporting majority of Niakuk Oil Pool Page 2 2010 Annual Reservoir Report the oil producers in the segment. In July 2007, tubing was replaced in NK-23 which improved the segment’s injection efficiency and overall oil production. NK-42 was POP in July of 2008 to verify WC and any sweep benefits from lower perfs added in offset injection well NK-23 in October of 2007. Oil rates of 250 BOPD have been seen during the reporting period. Injection was increased in NK-18 to restore the area to original pressure during the reporting period. All producers in Segment 2 have exhibited waterflood response from one or more injectors, but production, pressure, and tracer data clearly show the effects of compartmentalization within the reservoir due to faulting and/or stratigraphy. Average oil production from the segment was 1419 BOPD with 91% watercut and water injection of around 12 MBWPD during the reporting period. b. Voidage Balance of Produced and Injected Fluids Table 1 details hydrocarbon production, water injection and resultant voidage data by month for the reporting period. c. Analysis of Reservoir Pressure Surveys Within the Pool Pressure surveys have been conducted on all of the wells drilled. Table 2 shows results from the 2009/2010 reservoir pressure surveys. The pressures in Seg 2 and Seg 1, 3, 5 are generally managed to original reservoir pressure of approximately 4500 psi. Notable exceptions as seen in Table 2 in Seg 2 are NK-16 at 3729 psi and NK-43 at 2946 psi NK-16 is shut- in due to breakthrough in NK-21. Higher pressures are seen near most injectors like NK-15 at 5043 psi vs offset producer NK-09 at 4649 psi indicating the magnitude of the pressure gradient across the segment. d. Results of Production Logging, Tracer and Well Surveys Three injection logs and one production log were performed during the reporting period. No tracer surveys were performed during this reporting period. One surface pulse test was done during the reporting period. e. Special Monitoring Niakuk Oil Pool Page 3 2010 Annual Reservoir Report NK-43 is a commingled producer which produces from both the Kuparuk and Sag River Reservoirs. The AOGCC approved co-mingled production in NK-43 with production allocated to each reservoir via geo-chemical analysis in Conservation Order 329B on December 7, 2006. During the reporting period, two oil samples were taken from NK-43 for geochemical analysis to confirm production allocation splits between the Sag River and Kuparuk Reservoirs. The geochemical analysis showed that the Kuparuk (Combined Niakuk PA) is contributing 81% of the oil production from NK-43. f. Future Development Plans Permanent production facilities at Niakuk were commissioned in March 1995. There have been 29 development wells drilled into the Niakuk Oil Pool through the reporting period. Future drilling prospects will be evaluated on a well-by- well basis. Reservoir management activity in the Niakuk pool includes: 1) selective perforating and profile modifications to isolate water bearing zones in production wells and to open un-swept zones in injection wells, 2) production profile logging to determine current production and injection zones for potential profile modifications, material balance calculations, and effective full field modeling, 3) pressure surveys to monitor flood performance and 4) analysis of production, GOR, and WOR trends to highlight poorer performing wells for possible intervention activity. Niakuk Oil Pool Page 4 2010 Annual Reservoir Report Niakuk Oil Pool Page 5 2010 Annual Reservoir Report Assumptions for Production Table: Oil Formation Volume Factor = 1.30 rb/stb Water Formation Volume Factor = 1.01 rb/stb Gas Formation Volume Factor = 0.68 rb/mscf Gas production above solution GOR (690 scf/stb) is incorporated in the voidage calculation. Table 1 – Niakuk Monthly Production/Injection/Voidage Data Voidage Injection Oil Prod Water Prod Gas Prod Water Inj Soln Gas Free Gas Oil Wtr Gas Total Void Wtr Net Void MSTB MSTB MMSCF MSTB MMSCF MMSCF MRVB MRVB MRVB MRVB MRVB MRVB April 104 661 126 1030 72 54 135 668 37 839 1040 -201 May 140 911 185 977 97 88 182 920 60 1162 986 176 June 108 596 153 1067 75 78 141 602 53 796 1077 -281 July 112 744 161 950 77 84 146 751 57 954 959 -5 August 136 1100 193 787 94 100 177 1111 68 1355 795 561 September 108 918 153 672 75 79 140 927 53 1121 679 442 October 157 919 195 693 108 87 203 928 59 1191 700 491 November 149 955 208 939 103 105 194 964 72 1230 948 282 December 144 949 214 975 99 114 187 959 78 1224 984 239 January_2010 118 1017 243 951 81 162 153 1027 110 1290 960 330 February 30 356 78 603 20 57 39 360 39 438 609 -172 March 109 760 121 863 75 46 141 768 32 941 872 69 Surface Fluid Volumes Subsurface Fluid Volumes Note: Monthly Production/Injection/Voidage data (Table 1) does not include the production results from NK-38A well drilled to Ivishak (Raven) formation or injection from the NK-65A injector which supports NK-38A. They are subject to a separate Raven Oil Pool Annual Reservoir Report. Table 2 – 2009 - 2010 Pressure Survey Data Well Date Pressure NK-08A 10/4/2009 4708 NK-09 4/27/2009 4649 NK-19A 8/7/2009 4096 NK-22A 4/27/2009 4747 NK-27 4/28/2009 4282 NK-10 8/8/2009 4520 NK-42 4/30/2009 4504 NK-65A 8/8/2009 4525 NK-13 8/8/2009 4879 NK-16 12/25/2009 3729 NK-15 8/24/2009 5043 NK-18 8/7/2009 4058 L5-34 9/29/2009 3819 NK-43 3/18/2010 2946 NK-28 8/8/2009 4718 Prudhoe Bay Unit Pt. McIntyre Oil Pool 2010 Annual Reservoir Report This Annual Reservoir Report for the period ending March 31, 2010 is being submitted to the Alaska Oil and Gas Conservation Commission in accordance with Conservation Order 317B for the Pt. McIntyre Oil Pool. This report summarizes surveillance data and analysis and other information as required by Rule 15 of Conservation Order 317B. It covers the period between April 1, 2009 and March 31, 2010. A. Progress of Enhanced Recovery Project Implementation and Reservoir Management Summary (Rule 15 a) Enhanced Recovery Projects During the 12 month period from April 2009 – March 2010, a total of 24.2 BCF of MI (miscible injectant) was injected into P1-14 (0.7 BCF), P1-16 (3.4 BCF), P1-25 (2.3 BCF), P2-16 (4.5 BCF), P2-28 (2.2), P2-29 (0.1 BCF), P2-42 (6.2 BCF) and P2-46 (4.9 BCF). Nine of the 15 waterflood/EOR patterns have had MI injection to date. Reservoir Management Summary Production and injection volumes for the 12-month period ending March 31, 2009 are summarized in Table 1. Total Pt. McIntyre hydrocarbon liquid production (oil plus NGL) averaged 23.7 mbopd. Current well locations are shown in Figure 1. A total of 98 Pt. McIntyre wells (including P&A’d and sidetracked wells) have been drilled as of March 31, 2010. The dominant oil recovery mechanisms in the Pt. McIntyre field are waterflooding and miscible gas injection in the down-structure area north of the Terrace Fault and gravity drainage in the up-structure area referred to as the Gravity Drainage (GD) Area (see Figure 1). Gas injection commenced in the gas cap with field startup to replace voidage and promote gravity drainage. The waterflood was in continuous operation during 2009 with 15 wells on water injection. Water and gas injection was slightly higher than the offtake volume required for voidage replacement during this 12-month reporting period. Point McIntyre Oil Pool Page 1 2010 Annual Reservoir Report B. Voidage Balance by Month of Produced and Injected Fluids (Rule 15 b) Monthly production and injection surface volumes are summarized in Table 1. A voidage balance of produced fluids and injected fluids for the report period is shown in Table 2. As summarized in these analyses, monthly voidage is routinely balanced with injection. C. Analysis of Reservoir Pressure Surveys within the Pool (Rule 15 c) Reservoir pressure monitoring is performed in accordance with Rule 12 of Conservation Order 317B. A summary of reservoir pressure surveys obtained during the reporting period is shown in Table 3. D. Results and Analysis of Production & Injection Logging Surveys (Rule 15 d) Interpreted results of production and injection logs are reported in Tables 4 and 5. Surveys were obtained using conventional cased-hole production logging tools including spinner, temperature, pressure, and fluid identification. E. Results of Any Special Monitoring (Rule 15 e) No RST logs were performed during this reporting period. F. Future Development Plans and Review of Plan of Operations and Development (Rule 15 f & g) Production Pt. McIntyre production is processed at the LPC and GC-1 Gathering Center facilities; production is limited by both gas and water handling limits at the facilities. Production from some areas of the field is also limited by injection well capacity and reservoir management restrictions. Development Drilling The P2-31A well target is located approximately 1200 feet NW of the original P2- 31 location. The P2-31A well was side-tracked to this location. and the initial tests produced oil at a high rate and with low water cut. The P2-22A well targeted a possible field extension region outside the Pt. McIntyre PA on the northern margin of the field. Combining seismic interpretation Point McIntyre Oil Pool Page 2 2010 Annual Reservoir Report from the Northstar 3D seismic survey (to the north) with the Pt McIntyre 3D survey (to the south) suggested potential for structural closure of the field extending outside the current PA limits. The P2-22 production had declined significantly and was positioned in an ideal location to test the Northern limits of the field. The P2-22A well was sidetracked north east of the parent and drilled over 7600 feet of horizontal section with over 5500 feet outside the current PA. Results demonstrate that the reservoir is capable of commercial flow rates. Longer term production will be required to determine the need for future development in this area. There currently are a total of 26 well penetrations drilled from DS-PM1 including sidetracked, P&A and suspended wells. There are a total of 72 well penetrations drilled from DS-PM2. An additional water/MI injector (P1-25) is located at the West Dock staging area. Pipelines Figure 2 shows the existing pipeline configuration together with the miscible solvent distribution pipelines from LPC and CGF to the Pt. McIntyre drill sites. Lisburne Production Center (LPC) During the 12-month reporting period the LPC continued to provide produced water for injection at Point McIntyre. Additional produced water is provided from FS1 to LPC for injection at Pt. McIntyre. The LPC also provides up to 45 mmscfd of miscible injectant when the EOR compressor is on line. Drill Sites In March of 2004, the project to route some Pt. McIntyre production to GC-1 was completed. All wells at drillsite PM2 can be flowed to either the LPC (high pressure system) or over to GC-1 (low pressure system). This project has lowered wellhead pressures for the PM2 wells flowing to GC-1 by approximately 400 psi and utilizes approximately 80 MB/D of available water handling capacity at GC-1. PM1 wells are constrained to flow only to LPC. Support Facilities Pt. McIntyre will continue to share North Slope infrastructure with the Lisburne Participating Area ("LPA") and the IPA to minimize duplication of facilities. Point McIntyre Oil Pool Page 3 2010 Annual Reservoir Report Production Allocation The production of oil and gas, including those hydrocarbon liquids reported as NGLs, will continue to be allocated to the Pt. McIntyre Participating Area in accordance with conditions approved by the Alaska Department of Natural Resources, Alaska Department of Revenue, and Alaska Oil and Gas Conservation Commission. There is a test separator at Drill Site PM1 and two test separators at Drill Site PM2. Gas Sales The timing of Pt. McIntyre gas sales is dependent upon market demands and the availability of a transportation system. Prior to initiation of gas sales, Pt. McIntyre produced gas (other than gas extracted as NGLs and blended with crude oil for shipment to market) will be used or consumed for Unit Operations, or injected into the Pt. McIntyre or another formation underlying the Unit Area. Point McIntyre Oil Pool Page 4 2010 Annual Reservoir Report Table 1 - Pt. McIntyre Monthly Production & Injection Summary Produced Produced Produced Injected Injected Injected Cum Prod Cum Prod Oil Gas Water Gas Water MI Oil Gas mstb mmscf mstb mmscf mstb mmscf mstb mmscf Apr-09 30 635 4267 3428 3046 4072 2409 416948 904202 May-09 31 780 5117 4142 3619 4874 2365 417728 909319 Jun-09 30 682 4428 3623 2857 4134 2393 418410 913748 Jul-09 31 627 5265 2706 3774 3483 2053 419037 919012 Aug-09 31 492 4210 2209 4260 4412 275 419530 923223 Sep-09 30 619 5118 3307 3884 3769 1824 420149 928341 Oct-09 31 748 6701 4047 4123 5306 1716 420897 935041 Nov-09 30 652 5710 3761 3663 4482 2045 421549 940752 Dec-09 31 755 6320 4665 4201 4694 2362 422304 947072 Jan-10 31 791 6696 4928 4449 4372 2307 423095 953768 Feb-10 28 724 6672 4249 3991 3612 2098 423819 960440 Mar-10 31 725 6663 3985 4152 4352 2402 424544 967104 Year 365 8230 67168 45050 46019 51563 24249 Table 2 - Pt. McIntyre Monthly Voidage Balance Res. Vol Res. Vol Res Vol Injected Injected Injected Net Res. Oil Free Gas Water Gas Water MI Voidage m rvbm rvbm rvbm rvbm rvbm rvbm rvb Apr-08 30 883 2561 3480 2078 4133 1470 -757 May-08 31 1085 3061 4204 2468 4947 1442 -508 Jun-08 30 948 2645 3677 1949 4196 1460 -333 Jul-08 31 872 3246 2747 2574 3536 1252 -497 Aug-08 31 685 2601 2242 2905 4479 168 -2024 Sep-08 30 862 3150 3357 2649 3826 1113 -220 Oct-08 31 1040 4159 4107 2812 5385 1047 63 Nov-08 30 907 3536 3818 2498 4550 1247 -34 Dec-08 31 1050 3895 4735 2865 4765 1441 610 Jan-09 31 1101 4132 5002 3034 4437 1407 1356 Feb-09 28 1007 4153 4313 2722 3666 1280 1805 Mar-09 31 1008 4146 4045 2831 4417 1465 486 Year 365 11448 41284 45726 31385 52336 14792 -55 Note: Negative Net Reservoir Voidage indicates IWR > 1 Point McIntyre Oil Pool Page 5 2010 Annual Reservoir Report Well Survey Date Pressure Survey Type Pressure @8800'SS Datum P1-12 2/7/2009 SBHP 3,939 P1-13 5/25/2009 SBHP 4,092 P2-32 6/23/2009 SBHP 4,035 P2-41 7/8/2009 SBHP 4,187 P2-50B 7/12/2009 SBHP 4,202 P1-18A 8/1/2009 SBHP 3,985 P2-29 8/3/2009 SBHP 4,230 P1-13 8/8/2009 SBHP 4,047 P2-43 8/9/2009 SBHP 4,062 P2-22 8/24/2009 SBHP 4,085 P2-58 8/24/2009 SBHP 4,061 P2-40 8/25/2009 SBHP 4,136 P2-48 8/26/2009 SBHP 4,316 P1-24 8/27/2009 SBHP 3,892 P2-48 9/1/2009 SBHP 4,335 P2-36A 9/28/2009 SBHP 4,226 P1-20 11/3/2009 SBHP 4,131 P1-24 11/6/2009 SBHP 4,114 P1-13 12/7/2009 SBHP 4,097 P2-34 1/24/2010 SBHP 4,296 P1-13 3/25/2010 SBHP 4,080 * Survey Type Definition: SBHP = Static Bottomhole Pressure Survey Table 3 - Summary of Pressure Surveys Point McIntyre Oil Pool Page 6 2010 Annual Reservoir Report Table 4 – 2009-2010 Production Profiles Splits Rates STB/D STB/D STB/D STB/D Mscf/d WELL NO.P1-05 Interval Zone % Water % Oil % Gas BOPD BWPD GAS SP NNER DATE: 8/20/2009 13,056 13,064 UB4 28 69 72 00 757 3828 3344 TOOL OD: 1-11/16 NCHES 13,075 13,088 UB4 15 31 26 00 347 1971 1180 O L RATE: 1,104 STBPD 13,135 13,148 UB3 17 0 0 6 0 2102 29 GOR: 4,193 SCF/STB 13,391 13,563 LB2-4 40 0 1.4 0 5488 76 WATER CUT: 92 % GLG RATE: 0 MSCF/D FTP: 1,152 PSIG FBHP: 3,757 PSIG SPINNER TYPE: Full Bore AVG. RES. P.: 4,009 PSIG HOLE ANGLE: 54 Degrees RES. TEMP: 184 °F Splits Rates STB/D STB/D Mscf/d WELL NO.P1-11 Interval Zone % Water % Oil % Gas BOPD BWPD GAS SP NNER DATE: 7/21/2009 12,249 12,316 UC1 0 0 0 0 0 0 TOOL OD: 1-11/16 NCHES 12,316 12,340 UC1/UB4 26 70 66 237 1629 601 O L RATE: 340 STBPD 12,340 12,390 UB4/UB3 0 0 0 0 0 0 GOR: 2,662 SCF/STB 12,390 12,403 UB1-2 74 30 34 103 4517 304 WATER CUT: 95 %12,425 12,492 UB1-2 000 00 0 GLG RATE: 2,700 MSCF/D FTP: 730 PSIG FBHP: 3,522 PSIG SPINNER TYPE: Turbine AVG. RES. P.: 4,040 PSIG HOLE ANGLE: 31 Degrees RES. TEMP: 183 °F Splits Rates STB/D STB/D Mscf/d WELL NO.P2-07 Interval Zone % Water % Oil % Gas BOPD BWPD GAS SP NNER DATE: 4/5/2009 9,251 9,271 UC2-3 0 0 0 0 0 0 TOOL OD: 1-11/16 NCHES 9,286 9,526 UB4/UB3 100 100 100 114 5600 212 O L RATE: 114 STBPD GOR: 1,860 SCF/STB WATER CUT: 98 % GLG RATE: 3,499 MSCF/D FTP: 829 PSIG FBHP: 3,945 PSIG SPINNER TYPE: Full Bore 3 5" AVG. RES. P.: 4,011 PSIG HOLE ANGLE: 23 ° RES. TEMP: 182 °F Point McIntyre Oil Pool Page 7 2010 Annual Reservoir Report Table 4 – 2009-2010 Production Profiles (continued) Splits Rates STB/D STB/D Mscf/d WELL NO.P2-21 Interval Zone % Water % Oil % Gas BOPD BWPD GAS SP NNER DATE: 10/7/2009 11,133 11,152 UC1/UB4 46 93 85 285 2046 534 TOOL OD: 1-11/16 NCHES 11,235 11,254 UB3/UB1-2 13 7 10 19 574 60 O L RATE: 305 STBPD 11,310 11,320 UA1-4 41 0 5 0 1857 30 GOR: 2,053 SCF/STB WATER CUT: 92 % GLG RATE: 2,200 MSCF/D FTP: 800 PSIG FBHP: 3,790 PSIG SPINNER TYPE: Full Bore 2 5" AVG. RES. P.: 4,062 PSIG HOLE ANGLE: 42 ° RES. TEMP: 183 °F Splits Rates STB/D STB/D Mscf/d WELL NO.P2-48 Interval Zone % Water % Oil % Gas BOPD BWPD Gas SP NNER DATE: 2/11/2010 15,528 15,558 LC1 58 100 100 364 1684 828 TOOL OD: 1-11/16 NCHES 15,572 15,582 LB2-4 29 0 0 0 836 9 O L RATE: 364 STBPD 15,588 15,598 LB2-4 13 0 0 0 382 0 GOR: 2,053 SCF/STB 15,608 15,638 LB1 0 0 0 0 0 0 WATER CUT: 89 % GLG RATE: 3,644 MSCF/D FTP: 268 PSIG FBHP: 2,080 PSIG SPINNER TYPE: Full Bore 3 5" AVG. RES. P.: 4,335 PSIG HOLE ANGLE: 27 ° RES. TEMP: 182 °F Point McIntyre Oil Pool Page 8 2010 Annual Reservoir Report Table 5 – 2009-2010 Injection Profiles Rates WELL NO.P1-01 Interval Zone Perf'd % Inj BWPD SPINNER DATE: 8/2/2009 13,540 13,560 UC2-3 Yes 15 450 TOOL OD: 1-11/16 INCHES 13,560 13,600 UC2-3/UC1 Yes 72 2160 INJECTION RATE 3000 BPD 13,605 13,626 UC1 Yes 13 390 Injection Tbg. Press 1930 PSIG Injection BHP 5780 PSIG AVG. RES. P.: 3969 PSIG HOLE ANGLE: 18 Degrees RES. TEMP: 182 F SPINNTER TYPE Turbine Rates WELL NO.P1-21 Interval Zone Perf'd % Inj BWPD SPINNER DATE: 7/4/2009 11,032 11,042 UC4 Yes 0 0 TOOL OD: 1-11/16 INCHES 11,050 11,090 UC4/UC2-3 Yes 0 0 INJECTION RATE 13,000 BPD 11,102 11,112 UC2-3 Yes 0 0 Injection Tbg. Press 2050 PSIG 11,124 11,134 UC2-3/UC1 Yes 0 0 Injection BHP 5449 PSIG 11,151 11,168 UC1/UB4 Yes 0 0 AVG. RES. P.: 3939 PSIG 11,170 11,251 UB4-UB1-2 Yes 100 13,000 HOLE ANGLE: 35 Degrees 11,271 11,361 UB1-2 Yes 0 0 RES. TEMP: 181 F 11,375 11,400 UB1-2_L Yes 0 0 SPINNTER TYPE Full Bore 4-1/2" Rates WELL NO.P2-15A Interval Zone Perf'd % Inj BWPD SPINNER DATE: 6/4/2009 11,860 11,950 UC1/UB4 yes 5 335 TOOL OD: 1-11/16 INCHES 12,200 12,350 UB1-2 yes 0 0 INJECTION RATE 6708 BPD 11,400 11,510 UB1-2 yes 0 0 Injection Tbg. Press 1805 PSIG 11,550 12,710 UB1-2 yes 95 6373 Injection BHP 5436 PSIG AVG. RES. P.: 4100 PSIG HOLE ANGLE: 45-84 Degrees RES. TEMP: 182 F SPINNTER TYPE Tubine Rates WELL NO.P2-29 Interval Zone Perf'd % Inj BWPD SPINNER DATE: 8/2/2009 10,980 11,010 UC1 yes 0 0 TOOL OD: 1-11/16 INCHES 11,085 11,105 UB1-2 yes 0 0 INJECTION RATE 17000 BPD 11,120 11,180 UB1-2/UA1-4 yes 100 1700 Injection Tbg. Press 1650 PSIG 11,195 11,225 LC3 yes 0 0 Injection BHP 5651 PSIG 11,240 11,270 Lc3 yes 0 0 AVG. RES. P.: 4230 PSIG HOLE ANGLE: 41 Degrees RES. TEMP: 182 F SPINNTER TYPE Full Bore 3.5" Log run on Coiled Tubing Point McIntyre Oil Pool Page 9 2010 Annual Reservoir Report Table 6 – 2009-2010 Gas Cap Monitoring Surveys No RST logs were performed during this reporting period. Point McIntyre Oil Pool Page 10 2010 Annual Reservoir Report Figure 1 Pt. McIntyre Well Location Map Point McIntyre Oil Pool Page 11 2010 Annual Reservoir Report PM2 Approximate Scale 01Miles Prudhoe Bay Existing Pipelines Pipelines for EOR PM1 LG1 L1 CCP CGF L2 L3 L5 NK L4 LPC Figure 2. Drill Site and Pipeline Configuration GC1* * GC1 location not to scale Figure 3 Point McIntyre Oil Pool Page 12 2010 Annual Reservoir Report Prudhoe Bay Unit Raven Oil Pool 2010 Annual Reservoir Report This Reservoir Report has been prepared for submission to the Alaska Oil and Gas Conservation Commission in accordance with Conservation Order 570 for the Raven Oil Pool and pursuant to 20 AAC 25.517. This report summarizes surveillance data and analysis and other information as required by Rule 10 of Conservation Order 570. It covers the period from April 1, 2009 through March 31, 2010. Raven is a small oil and gas field in the Permo-Triassic interval (Ivishak and Sag River) located beneath the Niakuk field (Kuparuk reservoir). Two oil wells, NK-38A (Ivishak producer) and NK-43 (commingled Kuparuk and Sag River producer), produce from the Raven field. NK-65A is the only injector in the Raven field and it provides injection support for the Ivishak producer, NK-38A. Production from the Raven field started in March 2001 when the Sag River in NK-43 was produced from 03/11/01 to 05/05/01. The Sag River was subsequently isolated with a cast iron bridge plug (CIBP) and the well was perforated in the uphole Kuparuk reservoir and produced from this interval until 1/2/06 when the CIBP was removed and the Sag River commingled with the Kuparuk. Production from NK-38A began in March 2005 from the Ivishak reservoir. Water injection in NK-65A to provide pressure support in the Ivishak reservoir started in October 2005. a. Progress of Enhanced Recovery Project Implementation and Reservoir Management Summary Using water from the Initial Participating Area Seawater Treatment facilities, waterflood at Raven begun in October 2005. Thro ughout this reporting period, seawater was used in NK-65A to provide injection support for the Ivishak reservoir at an average rate of 6.2 mb/d. Raven Oil Pool Page 1 20010 Annual Reservoir Report Reservoir Management Raven Pool NK-65A is the only injector in the Raven field and it supports the Ivishak producer, NK-38A. For the most part, the NK-38A producer in this pool appears to be in good communication with the injector. Oil Production from the Raven pool averaged 1.0 mb/d for the reporting period. The general plan is to replace the voidage created by hydrocarbon production with water injection and keep reservoir pressure at levels that will optimize oil production. No conversions of producers and injectors are currently envisioned. b. Voidage Balance of Produced and Injected Fluids Table 1 details the production, injection and calculated voidage by month for the reporting period. c. Analysis of Reservoir Pressure Surveys Within the Pool Static pressure surveys have been conducted on the wells in the field. Table 2 shows results of static reservoir pressure surveys conducted on the wells since March 2005. Figure 1 shows the pressure trends in the Raven Ivishak reservoir. The most recent static reservoir pressure of 4,167 psi during the reporting period in August 2009 indicates that with extensive shut-in periods, pressure will continue to build. Thus while baffling exists between the injector and producer, pressure drop is not as excessive as a typical static pressure would indicate. d. Results of Production Logging, Tracer and Well Surveys One production log was obtained in NK-38A performed during the reporting period. Raven Oil Pool Page 2 20010 Annual Reservoir Report e. Special Monitoring NK-43 is a commingled producer which produces from both the Kuparuk and Sag River Reservoirs. The AOGCC approved co-mingled production in NK-43 with production allocated to each reservoir via geo-chemical analysis in Conservation Order 329B on December 7, 2006. During the reporting period, two oil samples were taken from NK-43 for geochemical analysis to confirm production allocation splits between the Sag River and Kuparuk Reservoirs. The geochemical analysis showed that the Sag (Raven PA) is contributing 23% of the oil production from NK-43. f. Future Development Plans No development wells were drilled in the Raven field during the reporting period. Future drilling prospects will be evaluated on a well-by-well basis. Reservoir management activity in the Raven pool includes: 1) imposing optimal drawdown on the reservoir to prevent water coning from underlying aquifer and gas coning from overlying gas cap 2) optimum injection rate selection to ensure excellent sweep efficiency toward the producer, 3) frequent pressure surveys to monitor flood performance and 4) analysis of production, GOR, and WOR trends to ensure timely intervention activity whenever possible. Raven Oil Pool Page 3 20010 Annual Reservoir Report Assumptions for Production Table: Oil Formation Volume Factor = 1.54 rb/stb Water Formation Volume Factor = 1.01 rb/stb Gas Formation Volume Factor = 0.76 rb/mscf Gas production above solution GOR (1004 scf/stb) is incorporated in the VRR calcs. Table 1 – Raven Monthly Production/Injection/Voidage Voidage Injection Oil Prod Water Prod Gas Prod Water Inj Soln Gas Free Gas Oil Wtr Gas Total Void Wtr Net Void MSTB MSTB MMSCF MSTB MMSCF MMSCF MRVB MRVB MRVB MRVB MRVB MRVB April 22 70 115 197 24 91 34 71 69 174 198 -25 May 3 48 9 191 3 6 4 48 5 57 193 -136 June 29 131 152 193 31 120 45 133 91 269 195 74 July 25 74 114 187 27 87 38 75 66 180 189 -10 August 0 0 0 96 0 0 0 0 0 0 97 -97 September 34 137 86 149 37 49 52 139 37 228 150 78 October 42 93 152 180 45 107 65 93 81 239 182 57 November 34 82 84 239 37 47 53 82 36 171 241 -70 December 45 101 137 239 48 88 69 102 67 238 241 -3 January_2010 37 114 120 239 40 80 57 116 61 233 241 -8 February 15 52 24 141 16 8 23 52 6 81 142 -61 March 28 148 115 214 30 85 43 150 65 258 216 41 Surface Fluid Volumes Subsurface Fluid Volumes Note: Monthly Production/Injection/Voidage for the Ivishak formation. Raven Oil Pool Page 4 20010 Annual Reservoir Report Raven Oil Pool Page 5 20010 Annual Reservoir Report Table 2 – Raven Ivishak Pressure Survey Data for Since March 2005 Period Sw Name Test Date Pres Surv Type Datum Ss Pres Datum NK-38A 3/29/2005 SBHP 9,850 4,973 NK-38A 8/1/2005 SBHP 9,850 4,237 NK-38A 8/7/2005 SBHP 9,850 4,273 NK-38A 12/24/2005 SBHP 9,850 4,210 NK-38A 7/26/2006 SBHP 9,850 4,155 NK-38A 1/23/2007 SBHP 9,850 4,104 NK-38A 7/6/2007 SBHP 9,850 3,758 NK-38A 8/24/2007 SBHP 9,850 4,370 NK-38A 10/30/2007 SBHP 9,850 4,379 NK-38A 6/9/2008 SBHP 9,850 3,543 NK-38A 9/2/2008 SBHP 9,850 3,507 NK-38A 4/29/2009 SBHP 9,850 3537 NK-38A 5/18/2009 SBHP 9,850 3928 NK-38A 8/31/2009 SBHP 9,850 4167 NK-65A 8/9/2005 SBHP 9,850 4,463 NK-65A 8/15/2005 SBHP 9,850 4,295 NK-65A 5/24/2006 SBHP 9,850 4,414 NK-65A 7/26/2006 SBHP 9,850 4,400 NK-65A 8/16/2007 SBHP 9,850 4,827 NK-65A 8/17/2008 SBHP 9,850 4,379 NK-65A 8/8/2009 SFO 9,850 4,525