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Home My WebLink About2010 Prudhoe Satelliite Oil Pools Prudhoe Bay Unit 2010 Aurora Oil Pool Annual Reservoir Report This Annual Reservoir Report for the year ending June 30, 2010 is being submitted to the Alaska Oil and Gas Conservation Commission in accordance with Conservation Order 457A for the Aurora Oil Pool. Progress of Enhanced Recovery Project Implementation and Reservoir Management Summary (Rule 8 a) Enhanced Recovery Projects Water injection in the Aurora Oil Pool (AOP) started in December 2001. Tertiary EOR Miscible Water Alternating Gas (MWAG) started in the North of Crest (NOC) and West blocks at Aurora in December 2003 and expanded to the Southeast Crest (SEC) and Crest (CR) blocks in 2006. Evaluation of hydrocarbon recovery mechanisms for the Aurora Oil Pool (AOP) has been a continual process. A phased development program has been deemed appropriate due to the technical characteristics of considerable faulting, low initial oil rates, gas cap presence, and thin oil columns. This development approach employs three reservoir mechanisms throughout the field’s life and will help ensure greater ultimate recovery. Initial development involves a period of primary production to determine reservoir performance and connectivity of drainage areas. Primary production under solution gas and aquifer influx drive, from both floodable and non-waterflood pay intervals, provides information, including production pressure data to evaluate compartmentalization and conformance, that is used to improve the depletion plan. This drilling and surveillance data influences subsequent steps in reservoir development, including proper water injection pattern layout. In areas of the AOP where injection is justified, water-flooding is initiated to improve recovery by reducing residual oil saturation and maintaining well productivity via reservoir pressure support. Water injection should maintain average reservoir pressure above 2400 psi in the flood area to ensure hydrocarbon recovery targets are achieved. Tertiary EOR MWAG provides additional oil recovery by further reducing residual oil saturation. The miscible gas injection project is operated to maintain miscibility between the reservoir fluid and the injected miscible gas. There will be higher pressure in the area around injection wells and a pressure sink around the producers, which in some cases can be below minimum miscibility pressure (MMP) of approximately 2700 psi. With average reservoir pressures above the MMP, incremental EOR recovery is essentially the same even when producer region pressures below the MMP are maintained. As a consequence, reservoir management guidelines for EOR are based on 7/09 – 6/10 Aurora Annual Reservoir Report 1 average reservoir pressure rather than producer pressure. Early implementation of the secondary and tertiary injection processes allows adequate time for producers to capture mobilized oil. Proper field management includes monitoring of productivity, GOR, water cut, pressure, and injection voidage replacement ratios. Reservoir Management Strategy The objective of the Aurora reservoir management strategy is to manage reservoir development and depletion to achieve greater ultimate recovery consistent with prudent oil field engineering practices. During primary depletion, producers experienced increasing gas-oil-ratios (GORs) due to existence of an initial gas cap, primarily in the West side of the field, but also apparent in the CR & SEC areas. Production was restricted to conserve reservoir energy. Beginning in mid-2001 and continuing into 2003, production from wells S-100, S-106 and S-102 were reduced to approximately half capacity, allowing injection to significantly reduce the GORs by the end of 2003. This practice continued in 2004-5 with curtailment of wells S-108, S-113B and S-118. By 2006, these wells were returned to production with a notable increase in reservoir pressure & productivity in S-108. Pressure data & production performance in S-113B indicates the well is supported by a large gas-cap, so it was returned to full-time production in 2006 to capture benefits of MI injection in the area. Irregular pattern waterfloods have been designed to ensure pressure is maintained in individual reservoir compartments and areal sweep is maximized. Initial patterns are based on the current understanding of compartmentalization; however, reservoir management is a dynamic process. Patterns and producer/injector ratios will be modified as development wells and surveillance data provide new information. The surveillance program emphasizes pressure monitoring and waterflood performance monitoring to support this feedback and intervention process. Figure 1 and Figure 2 show Aurora well locations at surface and penetration in the top Kuparuk structure. 7/09 – 6/10 Aurora Annual Reservoir Report 2 Voidage Balance by Month of Produced and Injected Fluids (Rule 8 b) Monthly production and injection surface volumes are summarized in Table 1. Voidage replacement by fault block is summarized in Table 2 and Figure 3. Plans to achieve injection withdrawal ratios consistent with the reservoir management strategy include drilling and stimulation of injection wells as necessary and increasing water injection supply pressure to enhance injection rates where needed. A booster pump was installed and started in late 2006 to provide increased injection rates to low injectivity patterns. Analysis of Reservoir Pressure Surveys within the Pool (Rule 8 c) Reservoir pressure monitoring is performed in accordance with Rule 5 of Conservation Order 457A. A summary of reservoir pressure surveys is shown in Table 3. The field average reservoir pressure map is shown in Figure 7. Static BH pressures were gathered in 10 wells during the reporting period. Most producers in the AOP have evidence of pressure response to injection support. S-134i was drilled to improve injection into the S-115 / S-117 Crest region. Initial pressure in S-134i was below original pressure, as S-115 and S-117 had depleted the area. However, the C-Sand pressure of 2436 psi was much higher than very low static pressures taken in S-115 and S-117. It is thought that during shut-in periods, there is crossflow to the A-Sand, open in S-115, S-117, that may be interfering with accurate measurement of the C-Sand pressure. The initial pressure in S-134i supports the production data, of steady oil and low GORs, which indicate a healthy pattern in the Crest area. Pressure gauges were run in S-118 about the time S-134i went on injection. No pressure response was seen in S-118 in the first 3 months of S-134i injection. Analysis of S-118 pressure / production data suggests that faulting in the area is isolating it from injection support. S-118 is a long-term shut-in well because of low production rates. Options to maximize wellbore utility are being evaluated A steep pressure gradient has been observed repeatedly in the lower permeability sections of the reservoir, like the Southeast Crest (SEC.). During the 2009 GC2 maintenance turnaround, injection and production stopped for a month in the entire Aurora Pool. Static pressures after three weeks showed differences of 1400 to 1700 psi between adjacent producer (S-108 and S-109) and injectors (S-110i and S-112i,) with no discernable faults isolating them from each other. The pressure gradient is believed to be due to the low permeability, and significant heterogeneity of this section of the reservoir. This slow pressure bleed-off has led the operator to shut-in injectors S-110i and S-112i four to six months ahead of the intended rig sidetrack of S-110i. 7/09 – 6/10 Aurora Annual Reservoir Report 3 Results and Analysis of Special Monitoring (Rule 8 d) An injection profile was run in injector S-111i. It found 100% of injection going to heel of well, the top perfs. This fault block supports S-122. It is not clear why injection was not going to the toe of the well, near S-119. Options are being considered to improve injection into other sections of this well. Review of Pool Production Allocation (Rule 8 e) Since August 2002, Aurora production allocation has adhered to the PBU Western Satellite Production Metering Plan. Allocation relies on performance curves to determine the daily theoretical production from each well. The GC-2 allocation factor is applied to adjust the total Aurora production volumes at the end of each month. A minimum of one well test per month is used to check the performance curves and to verify system performance, with more frequent testing during the first three months of production in new wells and after major wellwork. Allocated daily production and injection is shown in Table 1. Graphical representation of the allocated figures is shown in Figures 4 and 6. 7/09 – 6/10 Aurora Annual Reservoir Report 4 Review of Plan of Operations and Development and Reservoir Depletion Plans (Rule 8 f & g) Field development areas for the AOP have been defined by geological and reservoir performance data interpretation and are annotated in Figure 2. Differing initial gas-oil and oil-water contacts and pressure behavior during primary production led to the definition of these field development management areas. These areas include the: 1) West Area, 2) North of Crest Area (NOC), 3) South East of Crest Area (SEC), and 4) Crest Area (AURCR). After establishing primary production from each area, water-flood and tertiary EOR has been implemented to provide pressure support and reducing residual oil saturations. The West and North of Crest areas began production in 2000-2001; water injection commenced in 2002 and MWAG began in December 2003. Initiation of water injection into the South East of Crest Area began with conversion of Wells S-112 and S-110 to injection in June and July 2003 and conversion to MWAG in 2006. Crest Area production began in mid-March 2003 with startup of Aurora Well S-115; Well S-117 production began in early June 2003 with a water-flood startup in August 2004 with newly drilled injection wells S-116i and S-120i that were put on MWAG in 2006. Summarized below are significant events and accomplishments at Aurora over the past year: S-134i was drilled, completed and put on injection during the report period. S-134i drilled from the southern expansion pad of S-Pad, which is not served by the pressure- boosted water system on northern expansion pad. Initial rates were lower than anticipated, however the injection rates have recently increased to 1500 bwpd. Continue to catch up on voidage replacement. EOR proceeds in several patterns. A RWO was conducted on S-100 to repair a surface casing leak. The well was SI in October 2009 and the RWO was executed in July 2010. S-Pad expansion activities continue on the southern expansion pad, with an electrical and instrumentation installation for the extended injection trunk and lateral. TRIO seismic data, acquired in early 2009, has been processed and is being used for reservoir management and development. Figure 2 shows an updated Top of Kuparuk C4 map and corresponding well location as a result of the new TRIO data. S-26, a producer commingled with the Ivishak, after a rig workover to add the Kuparuk completion and a frac, underwent an EOR “buzz” this spring. The Aurora owners will continue to evaluate optimal well count and well locations through depletion of the reservoir. Production well S-129 and injection wells S-128i and 7/09 – 6/10 Aurora Annual Reservoir Report 5 S-110Ai are scheduled to be drilled in 4Q 2010. Wells S-129 and S-128i will extend development in the southwest portion of Aurora. S-110Ai will target the east side of Aurora to provide improved injection support to producer S-109. S-Pad Phase 1 should complete Execute phase during 2010/11. The project consists of a new WAG Trunk and Lateral (T&L) on South S-Pad, which has been installed, and a new electrical and instrumentation module that should be completed in late 2010. Planned well S-128i will be tied in to this new infrastructure. 7/09 – 6/10 Aurora Annual Reservoir Report 6 7/09 – 6/10 Aurora Annual Reservoir Report 7 Table 1: Aurora Monthly Production, Injection, Voidage Balance Summary Case 1 Date Oil Prod Rate STB/DAY Water Prod Rate STB/DAY Gas Prod Rate MSCF/DAY VRR Rate RVB/RVB Gas Inj Rate MSCF/DAY Water Inj Rate STB/DAY 7/31/2009 4,298 4,867 11,047 1.05 7,228 13,556 8/31/2009 4,983 5,032 10,379 1.53 2,526 26,098 9/30/2009 9,230 9,861 20,977 1.03 8,910 30,103 10/31/2009 6,891 9,384 15,288 1.22 4,897 31,201 11/30/2009 7,164 8,934 15,927 1.33 8,934 31,752 12/31/2009 6,951 9,055 14,212 1.23 7,760 27,800 1/31/2010 5,735 8,029 13,193 1.27 10,275 23,239 2/28/2010 6,115 7,926 12,563 1.62 12,101 29,694 3/31/2010 5,694 7,568 10,549 1.90 7,920 34,847 4/30/2010 5,931 8,327 12,094 1.65 5,778 34,961 5/31/2010 4,247 6,795 8,216 1.99 8,460 28,421 6/30/2010 4,536 8,695 9,514 1.66 9,086 27,665 Table 2: Cumulative Voidage Status by Fault Block 7/31/2010 AUR-CR* AUR-NOC AUR-SEC* AUR-WEST* Total Inj Cum MRVB 8,314 26,545 6,002 52,681 Total Prod Cum MRVB 22,070 28,056 21,857 73,373 Cum I/W ratio 0.37 0.95 0.28 0.72 Bo 1.32 rb / stb oil Bg 0.843 rb / mcf gas Bw 1.020 rb / stb water Rs 0.650 mscf / stb oil * Initial gas-cap Bmi 0.620 rb / mcf gas MI ** Solution gas only Table 3 - Valid Aurora Pressure Surveys acquired since 7/1/2009 6. Oil Gravity:0.9SG/25 API8. Well Name and Number:9. API Number 50XXXXXXXXXXXX NO DASHES10. Type See Instructions11. AOGCC Pool Code12. Zone 13. Perforated Intervals Top - Bottom TVDSS14. Final Test Date15. Shut-In Time, Hours16. Press. Surv. Type (see instructions for codes)17. B.H. Temp.18. Depth Tool TVDSS19. Final Observed Pressure at Tool Depth20. Datum TVDSS (input)21. Pressure Gradient, psi/ft.22. Pressure at Datum (cal)S-0350029206950000O 6401206494.37-6507.08, 6524.95-6537.7605/26/10 768 SBHP145 6400 284167000.462979S-10550029229770000O 6401206725.52-6730.03, 6730.03-6740.87, 6740.87-6743.5807/17/09 1008 SBHP143 6600 255667000.212577S-10650029229990000O 6401206688.75-6702.49, 6702.49-675.93, 6705.93-6716.22, 6726.5-6741.9107/08/09 792 SBHP153 6699 194567000.431945S-11050029230300000WAG 6401206734.86-6778.807/29/09 54360 SBHP122 6750 358667000.323570S-113B500292309402 O 6401206674.17-6695.61, 6677.74-6695.6109/04/09 696 SBHP155 6700 185667000.261856S-11650029231830000WAG 6401206717.49-6728.82, 6735.44-6747.73, 6829.08-6840.4407/14/09 3264 SBHP136 6700 333067000.443330S-117500292313700O 6401206597.76-6655.57, 6765.67-6779.2206/05/10 216 SBHP154 6650 332767000.383346S-11850029231880000O 6401206617.19-6621.19, 6621.19-6622.19, 6622.19-6651.17, 6697.15-6711.1403/03/10 26352 SBHP136 6350 200867000.062029S-125500292336100O 6401206704.62-6743.94, 6714.31-6775.28, 6785.74-6787.66, 6786.73-6782.62, 6771.12-6747.05, 6740374-6733.5, 6740.74-6732.47, 6725.94-6704.37, 6706.12-6699.1506/09/10 336 SBHP145 6200 295567000.303107S-134500292341300WAG 6401206633.29-6691.83, 677.12-6789.5401/27/10SBHP149 6640 241567000.362436BP Exploration (Alaska) Inc.P.O. Box 196612, 900 E Benson Blvd, Anchorage, AK 99519-86127. Gas Gravity:Prudhoe Bay UnitPrudhoe Bay Field: Aurora Oil Pool 6700 TVDss0.723. Unit or Lease Name:4. Field and Pool:5. Datum Reference:STATE OF ALASKAALASKA OIL AND GAS CONSERVATION COMMISSIONRESERVOIR PRESSURE REPORT1. Operator:2. Address:7/09 – 6/10 Aurora Annual Reservoir Report 8 Figure 1: Aurora Well Location Map 9 Δ Active injector • Active producer Figure 2: Aurora Well Location - Top Kuparuk C4 Depth Map Aurora TKC4 Depth Map CI=100 ft.Aurora producerAurora injectorPlanned Aurora producerPlanned Aurora injectorAurora producerAurora injectorPlanned Aurora producerPlanned Aurora injectorAurora producerAurora injectorPlanned Aurora producerPlanned Aurora injectorWESTAURCRSECNOC7/09 – 6/10 Aurora Annual Reservoir Report 10 Figure 3: Cumulative voidage replacement by region Aurora Cumulative VRR by Region 0.0000.1000.2000.3000.4000.5000.6000.7000.8000.9001.000Dec 1999Dec 2000Dec 2001Dec 2002Dec 2003Dec 2004Dec 2005Dec 2006Dec 2007Dec 2008Dec 2009Dec 2010Dec 2011Cumulative VRR [RVB/RVB]North of Crest Cum VRRWest of Crest Cum VRRTotal Aurora Cum VRRS East of Crest Cum VRRCrest Cum VRR 7/09 – 6/10 Aurora Annual Reservoir Report 11 Figure 4: Aurora Allocated Production Profile 05,00010,00015,00020,00025,00030,00035,00040,00045,00050,000Dec 1999Dec 2000Dec 2001Dec 2002Dec 2003Dec 2004Dec 2005Dec 2006Dec 2007Dec 2008Dec 2009Dec 2010Dec 2011Fluid Production or Injection Rate [stb/d]oil ratewater production rategas production rate 7/09 – 6/10 Aurora Annual Reservoir Report 12 Figure 5: VRR Rate, and VRR Cumulative 010,00020,00030,00040,00050,00060,000Dec 1999Dec 2000Dec 2001Dec 2002Dec 2003Dec 2004Dec 2005Dec 2006Dec 2007Dec 2008Dec 2009Dec 2010Dec 2011Total Production or Injection Rate [RVB/d]0.000.501.001.502.002.503.00total injection ratetotal production rateVRR rateVRR cum 7/09 – 6/10 Aurora Annual Reservoir Report 13 Figure 6: Total Injection Rates: Gas & Water 05,00010,00015,00020,00025,00030,00035,00040,00045,00050,000Dec 1999Dec 2000Dec 2001Dec 2002Dec 2003Dec 2004Dec 2005Dec 2006Dec 2007Dec 2008Dec 2009Dec 2010Gas Production or Injection Rate [MSCF/d]water injection rategas injection rate 7/09 – 6/10 Aurora Annual Reservoir Report 14 7/09 – 6/10 Aurora Annual Reservoir Report 15 Figure 7: Aurora Reservoir Pressure Map - Aug 2010 194529793570 newer test 46803346289925771856, newer test 20053330202931072436CI=200 ft.3500 7/09 – present pressurepsipsi3500 7/07-6/09 pressure21891498300731182450 Prudhoe Bay Unit 2010 Borealis Oil Pool Annual Reservoir Report This Annual Reservoir Report for the year ending June 30, 2010 is being submitted to the Alaska Oil and Gas Conservation Commission in accordance with Conservation Order 471 for the Borealis Oil Pool. This report summarizes surveillance data, analysis and other information as required by Rule 9 of Conservation Order 471. Progress of Enhanced Recovery Project Implementation and Reservoir Management Summary (Rule 9a) (Rule 9a part one) Enhanced Recovery Projects Waterflood has been implemented in Borealis, which includes 20 injectors in full service. Enhanced Recovery Projects using Miscible Injectant (MI) have been implemented in Borealis, with 19 of the 20 injectors interchanging between water and MI injection. The only injector yet to be converted to MI injection is Z-102i. It has an offset Ivishak penetration with questionable cement, and needs more investigation before converting Z- 102i to MI. Figure 1 shows well locations on a well spider map. Figure 2 shows the well bottomhole locations superimposed on the top Kuparuk structure map. (Rule 9a part two) Reservoir Management Summary The objective of the Borealis reservoir management strategy is to manage reservoir development and depletion to maximize ultimate recovery consistent with prudent oil field engineering practices. Water injection was initiated in June 8, 2002 to restore reservoir pressure and reduce gas-oil-ratios (GORs), thereby enabling wells to be produced at their full capacity. An irregular pattern waterflood has been designed and implemented to ensure pressure is maintained in individual reservoir compartments and areal sweep is maximized. Initial patterns were based on the understanding at the time of reservoir compartmentalization. Patterns and producer/injector ratios are being modified as development wells and surveillance data provide new information. The surveillance program emphasizes pressure monitoring, injection tracers in select patterns and waterflood performance monitoring to support this feedback and intervention process. During primary depletion, a number of producers experienced increasing GORs. Production was restricted in several wells in 2002 to conserve reservoir energy. As more injection patterns were implemented in 2003, the rising GOR trend was reversed and subsequently GORs stabilized near solution GOR. When water injection was initiated, a VRR target of greater than 1.0 was set in order to catch up with voidage. The current VRR target is 1.0. Injection facility limitations were identified in 2003, which limited the delivery pressure of water to be injected to the field. Booster pumps were installed at Z Pad to provide 7/09 – 6/10 Borealis Annual Reservoir Report 1 increased injection pressure and better water distribution. The increased injection pressure has allowed better management of injection at a pattern level. The Borealis waterflood strategy is progressing as planned however Borealis has experienced water breakthrough earlier than expected in many patterns. Impacts of the early breakthrough include reduced production due to unfavorable wellbore hydraulics and gas-lift supply pressure limitations. Remedies have included gas-lift redesign and optimization and prioritization of gas-lift use. Voidage Balance by Month of Produced and Injected Fluids (Rule 9b) Monthly production and injection surface volumes for July 2009 to June 2010 are summarized in Table 1, and cumulative volumes can be found in Table 2. Figures 3, 4 and 5 graphically depict this information since start-up. Subsequent to initiating and stabilizing injection, monthly reservoir voidage will be balanced with water injection, consistent with the reservoir management strategy. Analysis of Reservoir Pressure Surveys within the Pool (Rule 9c) Reservoir pressure monitoring is performed in accordance with Rule 5 of Conservation Order 471. A summary of reservoir pressure surveys obtained during the reporting period is shown in Table 3. Figure 6 is a map contouring reservoir pressures collected over the last two years. Four of the newer Borealis producers and one new injector have been completed with permanent bottomhole gauges, giving valuable information about the flowing conditions, reservoir pressures and reservoir connectivity on a continuous basis. Results and Analysis of Production & Injection Logging Surveys (Rule 9d) Openhole resistivity logs through the Kuparuk have been used to evaluate vertical injection conformance via change in water saturation over time. Well logs used in this manner include Ivishak well V-05, drilled between V-104 and V-105i. A fish in V-115 has prevented access to the wellbore below the top lateral; therefore there has been no production profile to assess the two laterals drilled in 2008 Results of Well Allocation and Test Evaluation (Rule 9e) Borealis production allocation is performed according to the PBU Western Satellite Production Metering Plan. Allocation relies on performance curves to determine the daily theoretical production from each well. The GC-2 allocation factor is now being applied to adjust the total Borealis production similar to IPA production allocation procedures. A minimum of one well test per month is used to check the performance curves and to verify system performance. In an effort to improve well test quality, multiphase meters were installed in the test header line at L-pad and V-Pad during the reporting period. Troubleshooting of the new installation is ongoing. However, no insurmountable difficulties have been identified, and the meters are expected to perform as intended. 7/09 – 6/10 Borealis Annual Reservoir Report 2 Future Development Plans and Review of Plan of Operations and Development (Rule 9f and 9g) Waterflood Waterflood has been implemented on L, V and Z-Pads. Injection was started June 8, 2002. Water injection manifolding and booster pumps have been installed and have been operating since January 2004. These booster pumps allow even pattern support throughout the waterflood providing optimum waterflood spacing, configuration, timing and operations for the Borealis Reservoir. Enhanced Recovery Miscible gas injection and water-alternating with miscible gas injection is used to increase the economic recovery of Borealis Reservoir hydrocarbons. Injection wells are being engineered and completed for Enhanced Oil Recovery service. Events and Achievements V-123i was drilled, completed and put on injection during the reporting period. The well was designed to have flow measurement and flow control between two fault blocks served by the injector. V-123i is the first Borealis injector to have bottomhole pressure gauges installed as part of the completion. From April 2008 until March 2010, Borealis had a consistent run of production well uptime. In addition, significant volumes of MI were injected. The combination was quite beneficial for oil production rates. Beginning in March 2010, GC2 reached its permit limit for H2S production. Several Borealis wells were shut-in at the height of their EOR “oil buzz,” due to elevated H2S in the returned MI. Most producers are now back online and are monitored closely. Construction began for the Z-Pad expansion in August 2006 with placement of gravel. The Z-Pad expansion anticipates 5-10 additional Borealis development wells. The Borealis owners will continue to evaluate the optimal number of development wells and their location throughout the life of the reservoir. Z-Pad expansion drilling is expected to commence in 1Q 2011. 7/09 – 6/10 Borealis Annual Reservoir Report 3 7/09 – 6/10 Borealis Annual Reservoir Report 4 Table 1: Borealis Monthly Production, Injection, Voidage Balance Summary Case 1 Date Oil Prod Rate STB/DAY Water Prod Rate STB/DAY Gas Prod Rate MSCF/DAY VRR Rate RVB/RVB VRR Cum RVB/RVB Gas Inj Rate MSCF/DAY Water Inj Rate STB/DAY 7/31/2009 10,978 12,187 24,202 0.72 0.94 17,916 13,556 8/31/2009 16,324 21,613 37,587 0.28 0.93 8,548 26,098 9/30/2009 14,247 19,434 34,609 1.20 0.94 43,286 30,103 10/31/2009 14,757 21,753 34,370 0.95 0.94 23,325 31,201 11/30/2009 14,544 22,108 32,715 0.92 0.94 23,435 31,752 12/31/2009 14,664 25,234 31,453 0.85 0.94 26,196 27,800 1/31/2010 14,765 25,469 34,829 0.82 0.93 33,302 23,239 2/28/2010 15,135 25,788 37,240 0.84 0.93 36,534 29,694 3/31/2010 13,229 19,521 28,300 1.05 0.93 34,872 34,847 4/30/2010 11,867 13,199 26,509 0.85 0.93 6,131 34,961 5/31/2010 11,315 18,135 24,260 0.83 0.93 10,659 28,421 6/30/2010 11,743 23,325 29,984 0.57 0.93 14,565 27,665 Table 2 - Borealis Cumulative Production & Injection Summary MONTH_ENDING Data 2009 2010 units 06-30-2010 Oil Prod Cum 55,113 60,086 MSTB Gas Prod Cum 55,103 66,525 MMSCF Water Prod Cum 44,582 52,107 MSTB Gas Inj Cum 35,494 43,939 MMSCF Water Inj Cum 103,287 115,056 MSTB Total Inj Cum 129,457 151,770 MRVB Total Prod Cum 142,102 163,596 MRVB VRR Cum 0.911 0.928 RVB/RVB Bo 1.24 rb / stb oil Bg 0.97 rb / mcf gas Bw 1.03 rb / stb water Rs 0.5 mscf / stb oil Bmi 0.65 rb / mcf gas MI Table 3: Borealis Pressure Survey Detail 1. Operator:BP Exploration (Alaska) Inc.3. Unit or Lease Name:6. Oil Gravity: 7. Gas Gravity:Prudhoe Bay Unit0.9 SG / 25 API 0.728. Well Name and Number:9. API Number 50-XXX-XXXXX-XX-XX10. Oil (O) or Gas (G)11. AOGCC Pool Code12. Zone 13. Perforated Intervals Top - Bottom TVDSS14. Final Test Date15. Shut-In Time, Hours16. Press. Surv. Type (see instructions for 17. B.H. Temp.18. Depth Tool TVDss19. Final Pressure at Tool Depth20. Datum TVDss (input)22. Pressure Gradient, psi/ft.22. Pressure at Datum (cal)L-10350-500-29231-01-00 WAG 6401306472 - 65227/19/20103,120 SBHP 154 6,600 2,877 6,600 0.470 2,877L-10450-500-29230-60-00 O 6401306574-66137/23/2010408 SBHP 155 6,500 2,827 6,600 0.200 2,847L-10650-500-29230-55-00 O 6401306576-66404/12/2010552 SBHP 163 6,550 3,463 6,600 0.380 3,482L-10750-500-29230-36-00 O 6401306499 - 65854/15/2010618 SBHP 162 6,450 3,237 6,600 0.440 3,302L-11650-500-29230-25-00 O 6401306468 - 6513, 6527 - 65334/13/2010576 SBHP 148 6,200 3,516 6,600 0.310 3,642L-11750-500-29230-39-00 WAG 6401306552 - 6600, 6612 - 66179/19/20096,600 SBHP 147 6,600 2,940 6,600 0.440 2,940L-11750-500-29232-55-00 WAG 6401306552 - 6600, 6612 - 66177/10/201013656 SBHP 155 6,600 2,694 6,600 0.450 2,694L-12450-500-29230-39-00 O 6401306353 - 64046/5/2010240 BHPG6,260 1,984 6,600 0.440 2,134V-10650-500-29230-83-00 O 6401306520-6543, 6561-6572, 6574-6576, 6581-6600, 6601-66024/16/2010672 BHPG6,480 3,357 6,600 0.440 3,410V-11350-500-29231-25-00 O 6401306554-66067/21/2010185 SBHP 150 6,500 2,285 6,600 0.280 2,312V-11750-500-29231-56-00 O 6401306552 - 6600, 6612 - 66177/7/2009756 SBHP 153 6,580 3,269 6,600 0.440 3,278V-11750-500-29231-56-00 O 6401306552 - 6600, 6612 - 66177/17/2010262 SBHP 154 6,600 3,310 6,600 0.440 3,310V-12250-500-29233-28-00 WAG 6401306595-6601, 6602-6603, 6605-6620, 6625-6635, 6636-66376/5/2010264 BHPG6,491 2,560 6,600 0.440 2,608V-123 heel50-500-29234-22-00 WAG 6401306554-6557, 6563-6564, 6567-6568, 6572-6573, 6576-6577, 6581-6598, 6605-6616, 6626-66333/6/2010Initial BHPG6,267 2,901 6,600 0.440 3,047V-123 toe50-500-29232-92-00 WAG 6401306569-6574, 6577-6593, 6596-6600, 6601-6604, 6606-66113/6/2010Initial BHPG6,377 2,914 6,600 0.440 3,012Z-10850-500-29234-22-00 O 6401306555-65806/30/20101320 BHPG6,430 3,024 6,600 0.440 3,099P.O. Box 196612, 900 E. Benson Blvd., Anchorage, AK 99519-6612Prudhoe Bay Field, Borealis Oil Pool6600 TVDss4. Field and Pool:5. Datum Reference:STATE OF ALASKAALASKA OIL AND GAS CONSERVATION COMMISSIONRESERVOIR PRESSURE REPORT2. Address:7/09 – 6/10 Borealis Annual Reservoir Report 5 Figure 1: Borealis Well Location Map Δ Active injector • Active producer 7/09 – 6/10 Borealis Annual Reservoir Report 6 Figure 2: Borealis Well Location - Top Kuparuk C4 Depth Map 7/09 – 6/10 Borealis Annual Reservoir Report 7 Borealis producerBorealis injectorBorealis producerBorealis injectorBorealis TKC4 Depth Map CI=100 ft.2010 Activities•Trio seismic survey used to create new structure maps•V-123i drilled•Z pad surface expansion ongoing Figure 3: Borealis Allocated Production Profile 05000100001500020000250003000035000400004500050000Jun-01 Oct-02 Feb-04 Jul-05 Nov-06 Apr-08 Aug-09 Dec-10Fuid Production (stb/d)Gas Prod RateOil Prod RateWater Prod Rate 7/09 – 6/10 Borealis Annual Reservoir Report 8 Figure 4: Borealis – Total production / Injection rates (rvb/d) and VRR Rate, and VRR Cumulative 0100002000030000400005000060000700008000090000Jun-01 Oct-02 Feb-04 Jul-05 Nov-06 Apr-08 Aug-09 Dec-10Total Production or Injection Rate (RVB/d)0246810121416Total Inj RateTotal Prod RateVRR CumVRR Rate 7/09 – 6/10 Borealis Annual Reservoir Report 9 Figure 5: Borealis - Total Injection Rates: Gas & Water 010000200003000040000500006000070000Jun-01 Oct-02 Feb-04 Jul-05 Nov-06 Apr-08 Aug-09 Dec-10Water or gas Injection Rate (stb/mscfd)Gas Inj RateWater Inj Rate 7/09 – 6/10 Borealis Annual Reservoir Report 10 7/09 – 6/10 Borealis Annual Reservoir Report 11 Figure 6: Borealis Reservoir Pressure Map - Aug 2010 psipsi287728473482330436422694213434102312309933102608304730843500 – Pressure since 7/1/20099CI=200 ft.3500 – Pressure 7/2008-7/20031673012354632353703287827783422284730353629 Prudhoe Bay Unit 2010 Midnight Sun Annual Reservoir Report This Annual Reservoir Report for the period from July 1, 2009 through June 30, 2010 is being submitted to the Alaska Oil and Gas Conservation Commission in accordance with Conservation Order 452 for the Midnight Sun Oil Pool. This report summarizes surveillance data and analysis and other information as required by Rule 11 of Conservation Order 452. Progress of Enhanced Recovery Project Implementation and Reservoir Management Summary (Rule 11 a) Production and injection volumes for the 12-month period ending June 30, 2010 are summarized in Table 1. The objective of the Midnight Sun reservoir management strategy is to manage reservoir development and depletion to ensure greater ultimate recovery consistent with prudent oil field engineering practices. During primary depletion, both producers experienced increasing gas-oil-ratios (GORs). Consequently, production was restricted to conserve reservoir energy. Produced water injection into the Midnight Sun reservoir commenced in October 2000 and continues to provide pressure support to Midnight Sun. The objective of water injection is to increase reservoir pressure, reduce GOR’s to enable wells to be produced at their full capacity, and maximize areal sweep efficiency. There is a risk of oil flux into the gas cap from mid-field water injection. Placement of the wells drilled in 2001 and voidage management is minimizing this risk. A VRR target of 1.0 to 1.3 is designed to increase reservoir pressure while minimizing re-saturation of oil into the gas cap. During the period covered by the report, the VRR averaged .94. Midnight Sun gas production has declined during the report period as reservoir pressure has increased. Both oil and water production rates have remained fairly constant during the report period. Well E-101 currently produces at ~83% watercut, and Well E-102 produces at ~92% watercut. Since 2005, gas lift has been utilized to produce the Midnight Sun wells more efficiently. Voidage Balance by Month of Produced and Injected Fluids (Rule 11 b) A total of five Midnight Sun wells have been drilled, with the most recent wells drilled in 2001. Midnight Sun is expected to have an oil production rate of approximately 1.4 MBOPD through 2010. A peak water injection rate of 20-25 MBWPD for the field has been achieved since E-103 and E-104 were converted to water injection during 2003. Monthly production and injection surface volumes for the reporting period are summarized in Table 1 along with a voidage balance of produced and injected fluids for the report period. Analysis of Reservoir Pressure Surveys within the Pool (Rule 11 c) 7/09 – 6/10 Midnight Sun Annual Reservoir Report 1 7/09 – 6/10 Midnight Sun Annual Reservoir Report 2 Reservoir pressure monitoring is performed in accordance with Rule 8 of Conservation Order 452. A summary of reservoir pressure surveys obtained during the reporting period is shown in Table 2. Reservoir pressures have remained stable throughout the last year, <50 psi change. Results and Analysis of Production & Injection Logging Surveys (Rule 11 d) A PPROF in E-102 was run in December 2009 and found production splits to be 75% from 10,006'-10,036', 25% from 10058'-10082', and 0% from 10094'-10124' Results of Well Allocation and Test Evaluation (Rule 11 e) Midnight Sun wells are tested using the E-Pad test separator, and Midnight Sun production is processed through the GC-1 facility. Midnight Sun production allocation has been performed according to the PBU Western Satellite Production Metering Plan for the report period. Future Development Plans and Review of Plan of Operations and Development (Rule 11 f & g) Development plans for the Midnight Sun Oil Pool are set forth in the Twelfth Plan of Development for the Midnight Sun Participating Area. Well E-102, located to the south of Well E-100, was planned as an injection well that would undergo a pre-production period. Well E-102 has been utilized as a producer to date and has been converted to a permanent producer. Well E-103, located to the southwest of Well E-100, was originally drilled as an up-dip production well. Due to an apparent conduit to the overlying gas cap, Well E-103 was shut-in shortly after being placed on production due to excessive gas production. Well E-103 was converted to water injection service during 2003. Well E- 104, drilled in the northwest corner of the field, was drilled as an additional injector well. At this time, no further development drilling is planned for the Midnight Sun Oil Pool. Table 1: Midnight Sun Monthly Production, Injection, Voidage Balance Summary Date (Mo-Yr) Oil Prod (stb) Water Prod (stb) Total Gas Prod (Mscf) Produced Lift Gas (Mscf) Water Inj (stb) Cum Oil (stb) Cum Gas (Mscf) Cum Gas less Prod Lift Gas (Mscf) Net Reservoir Voidage (Mrb) 07/2009 65,693 441,242 165,60738,328519,30217,655,557 56,348,36253,554,9926708/2009 0 0 00017,655,557 56,348,36253,554,992009/2009 67,526 376,449 147,93193,852379,75017,723,083 56,496,29353,609,0719310/2009 72,109 413,477 168,15266,858552,92217,795,192 56,664,44553,710,365-1211/2009 67,357 332,204 232,96631,666482,37717,862,549 56,897,41153,911,6655212/2009 55,383 440,234 146,21337,624502,31017,917,932 57,043,62454,020,2546101/2010 57,006 420,070 169,99031,927483,51717,974,938 57,213,61454,158,3178402/2010 36,063 191,981 100,27527,621411,91318,011,001 57,313,88954,230,971-14503/2010 41,032 197,170 92,40130,714342,64118,052,033 57,406,29054,292,658-7204/2010 36,456 172,511 35,96227,988282,36518,088,489 57,442,25254,300,632-6705/2010 42,046 268,832 114,41026,807274,68218,130,535 57,556,66254,388,2359806/2010 30,941 200,135 119,31716,995178,75818,161,476 57,675,97954,490,557125 Assumptions for Production Table: Oil Formation Volume Factor = 1.29 rb/stb Water Formation Volume Factor = 1.03 rb/stb Gas Formation Volume Factor = .79 rb/Mscf 7/09 – 6/10 Midnight Sun Annual Reservoir Report 1 Table 2: Reservoir Pressure Surveys 6. Oil Gravity:25-298. Well Name and Number:9. API Number 50XXXXXXXXXXXX NO DASHES10. Type See Instructions11. AOGCC Pool Code12. Zone 13. Perforated Intervals Top - Bottom TVDSS14. Final Test Date15. Shut-In Time, Hours16. Press. Surv. Type (see instructions for codes)17. B H. Temp.18. Depth Tool TVDSS19. Final Observed Pressure at Tool Depth20. Datum TVDSS (input)21. Pressure Gradient, psi/ft.22. Pressure at Datum (cal)E-10150029229090000OMSOPKUP8080-8098, 8116-81328/12/09 270 SBHP 162 8050 319880500.423198E-10150029229090000OMSOPKUP8080-8098, 8116-81326/30/10 264 SBHP 163 8050 324680500.443246E-10250029230420000OMSOPKUP7989-8015, 8034-8055, 8/15/09 345 SBHP 161 8050 345280500.353452E-10250029230420000OMSOPKUP7989-8015, 8034-8055, 03/31/10 1220 SBHP 161 8050 350380500.353503E-10250029230420000OMSOPKUP7989-8015, 8034-8055, 06/29/10 280 SBHP 161 8050 346880500.433468E-10450029230490000WIMSOPKUP7857-7870, 7879-789203/17/10 902 SBHP 128 7900 370480500.413766BP Exploration (Alaska) Inc.P.O. Box 196612, 900 E. Benson Blvd., Anchorage, AK 99519-66127. Gas Gravity:Prudhoe Bay UnitPrudhoe Bay Field, Midnight Sun8050' TVDss0.723. Unit or Lease Name:4. Field and Pool:5. Datum Reference:STATE OF ALASKAALASKA OIL AND GAS CONSERVATION COMMISSIONRESERVOIR PRESSURE REPORT1. Operator:2. Address:23. All tests reported herein were made in accordance with the applicable rules, regulations and instructions of the Alaska Oil and Gas Conservation Commission.I hereby certify that the foregoing is true and correct to the best of my knowledge.SignaturePrinted NameTitleDate 7/09 – 6/10 Midnight Sun Annual Reservoir Report 1 Prudhoe Bay Unit 2010 Orion Oil Pool Annual Reservoir Report This Annual Reservoir Report is being submitted to the Alaska Oil and Gas Conservation Commission in accordance with Rule 9 of Conservation Order 505B, and covers the period from July 1, 2009 to June 30, 2010. Voidage Balance by Month of Produced and Injected Fluids (Rule 9a) Monthly production and surface injection volumes from July 1, 2009 to June 30, 2010, as well as cumulative volumes and voidage are summarized in Table 1. Figures 1 and 2 graphically depict this information since field start-up. Analysis of Reservoir Pressure Surveys within the Pool (Rule 9b) Reservoir pressure monitoring is performed in accordance with Rule 5 of Conservation Order 505B. A summary of valid pressure surveys obtained during the reporting period is shown in Table 2 in form 10-412 format (4 pages). A shut in time of “na” is used for intervals with no prior injection or production. This data was acquired from open-hole formation tester surveys (RFT or MDT), extrapolated surface pressures (EXTR1), static bottom hole pressure surveys (SBHP), and pressures from permanent downhole gauges installed in new wells. Figure 3 illustrates valid Orion pressure data acquired since field inception, while Figure 4 shows a map of the pressures acquired during this report period interpolated to the Pool datum of 4400 ft TVDss (true vertical depth subsea). Acquiring representative regional average pressures continues to be a challenge in Orion wells due to the physical characteristics of viscous oil, multiple sand targets, and multilateral producer wellbores which present a paradigm shift from typical data acquisition in light-oil reservoirs. Pressure gradients around producers and injectors are very shallow due to the low mobility of viscous oil which results in very slow build-up and fall-off of pressures. Obtaining representative reservoir pressures is further complicated by significant differences in rock and oil properties between sands in the same wellbore, and as a result, productivity (and average sand pressure) varies dramatically between sands. Multilateral producers experience cross-flow between laterals completed in different sands and uneven zonal recharge during shut-in. Injectors also suffer from slow bleed-off rates and similar cross-flow between sands during shut-in. These phenomena combine to make the quality of pressure transient analysis (PTA) very questionable, and therefore, extrapolating a representative average reservoir pressure from pressure build up (PBU) data is very difficult. In order to mitigate these concerns, single point pressure surveys are obtained whenever possible after a well has been shut-in for several weeks or months to allow maximum build-up or fall-off. Even after a long shut-in time, wells show build or fall-off rates of several psi per day. In light of these problems, significant effort is being made to obtain high-quality initial pre-injection or pre-production pressure surveys relatively unaffected by pressure gradients applied to the wellbore. Whenever possible, by-zone initial pressures are being obtained with MDTs in new producers, or via downhole gauges in new or existing 7/09 – 6/10 PBU Orion Annual Reservoir Report 1 of 17 injectors. Injector data is expected to become increasingly important as the flood matures. Once development is completed, this becomes the only practical way to collect pressure data on a zonal basis. Most Orion pressures remain in the range of ~ 1700 to 1900 psi, but low pressures in Orion Polygon 2 continue to be a cause of concern. However, increasing pressure in the area between V-202 and V-204 is encouraging for the future of this area. Average pressure in V-216 was 1852 vs 1510 in the same zones in March, 2008. Average Schrader RFT pressure in well V-123 of 1675 psi is close to the offset commingled Schrader pressure of 1710 psi in dual zone injector V-105i last year. Due to the low pressures observed in V-214i on the opposite side of producer V-202, that well was choked in April, 2010 to help build pressure in the area. Since the well was choked, instantaneous VRR has increased from 0.8 to ~ 1.7, and cumulative pattern VRR has recovered to 0.77 from 0.75 Low pressure in V-213i reflects difficulty in maintaining up-time in V-213i and V-212i due to trouble with the wells freezing. Current waterflood regulator (WFR) designs have been revised to incorporate a minimum rate of 500 BWPD per well to ensure better on- time in the future. 1200 psi was observed in the OA sand of L-222i upon completion. Low pressure in this well is thought to be due to the influence of L-204. Due to the narrow size of the L-204 fault block, there is insufficient space to place sufficient injectors to provide full injection support. Injection in the L-222 OA sand has been initiated with a small waterflood regulator, with the intention of increasing water volume after a pressure “bulb” has been established. Average initial pressure in the remaining sands of L-222i was 1848 psi. Results and Analysis of Production & Injection Logging Surveys, and Special Monitoring (Rule 9c) Production Log: No production profiles were performed during the report period. Prior production profiles have been adversely affected by well slugging. Future production profile candidates will be evaluated on a case by case basis. Injection Logs: Sixteen injection profile logs were run during the report period, and are listed in Table 3. Profiles are run to quality check water flood regulator valve performance while in water service, or to determine the distribution of miscible injectant between zones. L-219i Monitoring across OWC: As described in prior reports, L-219i was drilled with OBd perforations both above and below the OWC to assess the degree of communication across the contact. Data discussed earlier has given confidence that communication across the contact is present. As a result, a regulator change out was performed to inject below the oil water contact instead of within the oil column. 7/09 – 6/10 PBU Orion Annual Reservoir Report 2 of 17 Red Dye Testing: A technique for diagnosing matrix bypass events (MBE’s) using injection of red dye in offset injectors has been adapted for use in the Polaris and Orion reservoirs. Due to the high injector to producer ratio of these developments, it is necessary to use oilfield brines as “tracers” to determine which of several offset injectors is the source of the MBE. Because waterflood regulators limit the volume of water into any given sand, it is theoretically possible to have an MBE in a producer without going to extremely high watercut. A red dye test was performed on V-105i, V-216i, and V-214i to see which well was the source of the suspected MBE in V-202. Red dye was observed mixed with the brine from V-214i. A second red dye test was performed between V-204 and offset injectors V-212i, V-213i and V-217i to see if an MBE was contributing to the WC on that well. No red dye was observed in this test. Interference Testing: L-103i – L-222i Interference Test: L-222i was drilled in Polygon 2AN in November 2009 to replace commingled (Borealis and Orion) injector L-103i. Although, L-103i has been injecting into the Schrader Bluff formation since 2007, and L-222i was drilled within a couple hundred feet of L-103i, no water saturation change was seen in L-222i’s logs. To eliminate the possibility of a physical barrier, an interference test was performed between the two wells. The interference test was inconclusive in two sands, due to the frequency and variability of the data, but showed connectivity between the two wells in two sands. The Schrader Bluff was dummied off in L-103i in July 2010. Interference Testing on Pre-Existing MBE’s Pressure interference testing was performed to assess the status of pre-existing MBE’s. An MBE was diagnosed from the red dye test between V-214i and V-202. However, no communication was observed in a follow up pressure interference test performed in March, 2010. The location of the MBE is thought to have been the OA sand, since that sand showed the greatest degree of pressure depletion. No communication has been observed between V-222i (OA sand) and V-202 since September of 2009. However, immediate communication still exists between V-213i (OBa sand) and V-204 as of May, 2010. The status of the MBE between V-216i (OBa sand) and V-204 could not be determined due to a failed memory gauge in the OBa sand of V-216i. Commingled injector monitoring: V-105i: A tubing tail plug was set in V-105i, and a waterflow log was used to update the injection profile within the Schrader on October 5, 2009. Results are included in Table 3. The plug was pulled on March 3, 2010 for continued commingled injection. 7/09 – 6/10 PBU Orion Annual Reservoir Report 3 of 17 L-103i: A tubing tail plug was set in L-103i, and a waterflow log was used to update the injection profile within the Schrader on January 6, 2010. Results are included in Table 3. The plug was pulled on January 8, 2010 for resumed commingled injection. Geochemical Fingerprinting: This technique has been in use since 1999 in the North Slope viscous oil developments, and has shown promise in obtaining snapshot relative oil flow splits from individual sands. This data is useful in gauging zonal well performance, identifying problem laterals, and providing a basis by which to optimize offset injection. Wellhead oil samples are taken on roughly a quarterly basis, or as well performance changes. Results to date are mixed with reasonable allocations in some wells, but questionable data in others. Work is ongoing to gather additional baseline oil samples, and improve analysis techniques to improve data value. Well fluids sampling: A well fluids sampling program is ongoing to gather high quality and high frequency surveillance data: (1) Uncontaminated wellhead samples are obtained monthly to quarterly on each producer, and tested for API, viscosity, WC, and sand quantity. This data helps track changes in production from different sands, waterflood or MI response, and sanding tendencies. A portion of these samples is later used for geochemical production allocation analysis. (2) Wellhead samples are analyzed quarterly for water properties to identify changes between formation water production and waterflood breakthrough. This data is also useful for identifying matrix bypass events (MBE) because produced water will have similar properties as injected water. (3) A produced water supply sample is analyzed quarterly to serve as a baseline for analysis of well production samples. (4) Gas sampling is done monthly or quarterly depending on WAG activity in the polygon to establish gas GC signatures and track returned miscible injectant (MI). Real-time Downhole Pressure Gauges in Injectors: Monitoring of individual zonal pressures is continuing on all injectors with downhole gauges installed. Real-time data has confirmed offtake from offset producers, formation and healing of MBE’s, pressure transmission across the OWC, and helped tremendously in identifying underperforming injection regulators. The current Orion injector basis of design calls for pressure gauge installation in all future injectors. Well Testing Improvements: Efforts are underway to improve well test quality in the Western Operating Area. New multiphase meters were installed on L and V pads in April, but troubleshooting has taken longer than expected. No insurmountable difficulties have been identified, and the meters are expected to perform as intended. Review of Pool Production Allocation (Rule 9d) Orion production allocation is performed in accordance with the PBU Western Satellite Production Metering Plan, subject to ongoing review and approved changes. Allocation relies on performance curves to determine the daily theoretical production from each well. The GC-2 allocation factor is applied to adjust production on a monthly basis. A minimum of one well test per month is used to check the performance curves, and to 7/09 – 6/10 PBU Orion Annual Reservoir Report 4 of 17 verify system performance, with more frequent testing during new well start-up and after significant wellwork. Progress of Enhanced Recovery Project Implementation and Reservoir Management Summary (Rule 9e) Enhanced Recovery Projects Water flooding began in Orion in December 2003. Initial pattern development on L and V pads is essentially complete. Downhole flow regulators are being employed to balance the flood. As noted above, a minimum rate of 500 BWPD has been implemented in new waterflood regulator designs to minimize trouble with well freezing. Wherever this rate might result in an excessive VRR, as is the case for injectors downdip of V-205, the injectors are cycled. Injection at low rates is underway in severely depleted zones such as the OA of L-222i, and also depleted zones where MBEs are thought to have healed. Commission approval for implementing an enhanced oil recovery project using Prudhoe Bay miscible injectant was granted on April 28, 2006 through C.O. 505A. Miscible injection started in L-213 in October, 2006, in the high quality oil of up dip Polygon 2. Initial response to large volume MI slugs in up dip producers was encouraging. Injection in late 2008 was concentrated in wells in down dip Polygon 2 to test for response in lower quality oil. However, hydrate problems were encountered in conjunction with returned MI in down dip producer V-205. The current MI strategy is to inject shorter MI slugs to improve MI efficiency, and also to inject MI in additional wells. The MI flood is currently implemented in most polygons in Orion. Reservoir Management Summary The objective of the Orion reservoir management strategy is to manage reservoir development and depletion to maximize ultimate recovery consistent with prudent oil field engineering practices. Key to this is balancing voidage to maintain average reservoir pressure. One aspect of the strategy is to control the waterflood sweep primarily with the injector through the downhole regulator valves. Learnings over the last few years reveal the dramatic differences in productivity and oil mobility between sands, which have led to changes in completion designs and operational strategies. The emergence of Matrix Bypass Events (MBEs) has further highlighted the complexity of this reservoir, and the importance of maintaining a dynamic depletion strategy while incorporating changes as new data becomes available. Depletion Strategy: The application of multi-lateral technology in Orion has provided wells with up to six individual legs (“hexa-lateral”), >27K ft of high-angle footage (27,743’ drilled; 24,871’ completed with slotted liner), and >17K ft of net pay (17,215’ in the L-201 Quad-lateral). Good oil quality in some wells and extensive sand exposure has combined to deliver choked production capacity in excess of 7000 bopd. With this 7/09 – 6/10 PBU Orion Annual Reservoir Report 5 of 17 prolific production, comes the reservoir management challenge of replacing reservoir energy in Orion’s fault-bounded polygons. In early 2005, the Orion depletion strategy was changed to compensate for these prolific producers. Production was choked in some new wells to ~2500 bopd which could be more easily supported by injection. The drilling of infill injectors was accelerated to earlier in a pattern’s life. Ongoing performance monitoring and reservoir modeling will guide future rate adjustments on producers and injectors, as well as determine the need for additional injection support. As the flood matures, surveillance and flood management become increasingly important in optimizing flood performance and recovery. Frequent pattern reviews are performed on all flood patterns to ensure effective flood management. Matrix Bypass Events (MBE): As described in prior Reservoir Reports, the phenomenon of catastrophic water breakthrough between producer and a water source (usually an injector) challenges the North Slope viscous oil developments. These events appear to have a multitude of probable causes: faults, fractures, matrix short-circuit through high perm streaks, and what is believed to be the creation of tunnels or “worm holes” due to sand production from the lower-pressured producer to the higher-pressured water source. A new MBE was suspected in producer V-202 due to a water rate increase in September, 2009. As mentioned above, red dye testing in November confirmed a rapid connection between V-214i and V-202. However, an interference test in the spring of 2010 failed to observe a connection between the two wells. Current interpretation is that an MBE was present in the fall of 2009, but healed before the interference test. Progress of Plans and Tests to Expand the Productive Limits of the Pool (Rule 9f) Lateral Expansion: Prudhoe Bay Unit Expansion and Orion PA Expansion applications were submitted August 5, 2008. A decision was received from the Department of Natural Resources Division of Oil and Gas on February 18, 2009 granting the unit expansion on the condition of drilling a well within ADL 390067 by September 1, 2009. An extension was granted on May 18, 2009 to allow drilling the conditional well up until Oct 15, 2009. L-223i, within in the expansion acreage, was spudded on 10/1/2009. Receipt of well data was acknowledged in a DNR Email dated January 27/2010, with remaining data presented in person on May 4, 2010. Final approval of the Prudhoe Bay Unit (PBU) and Orion Participating Area (OPA) expansions were requested on June 17, 2010. The AOGCC has issued Conservation Order 505B and Area Injection Order 26B to include this area. Drilling of conditional well L-223i was made feasible by development of the high angle waterflood regulator completion first used on well L-219i. 7/09 – 6/10 PBU Orion Annual Reservoir Report 6 of 17 New Sands: Assessment continued on efforts to develop two new sands, the Nb and OBe. As mentioned in previous reports, completion of the Nb sands with slotted liners had been recommended by the BP Technology Group. During the report period, a third N-sand slotted liner lateral was completed in well L-203, and has subsequently been flowed back above a shear disk. However, the N-sand lateral in L-205 has been shut off with an isolation sleeve in an effort to improve on-time on that well. Monitoring of V-207 OBe offtake from producer V-207 from a sandface gauge in V-220i continued during the report period. Data in Table 2 confirms a continued pressure decline, confirming continued offtake. V-207 OBe offtake is currently supported by three of four offset injectors, with a program written to initiate injection into V-220i. Analysis of the L-205PB1 core acquired in May 2008 is underway with expected completion in 4Q, 2010. The core data are expected to improve both the quality of the Orion log and reservoir models, and underpin the reservoir characterization for future Orion development. Results of Monitoring to Determine Enriched Gas Injectant Breakthrough to Offset Producers (Rule 9g) During the report period, MI breakthrough was confirmed in L-201 in September 2009. MI breakthrough is indicated by an increase in GOR in conjunction with a reduction in the producing ratio of C1 (methane) to C3 (propane). Recent Development Work One hexa-lateral producer and five injectors were drilled during this report period (Table 4). Future Development Plans No additional Orion production and injection wells are being proposed for drilling in the next year. Opportunistic logs will be run on Borealis and Ivishak new drills that cross the Schrader Bluff horizon in the next year, to evaluate future options. 7/09 – 6/10 PBU Orion Annual Reservoir Report 7 of 17