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Home My WebLink About2007 Prudhoe Satellite Oil PoolsPrudhoe Bay Unit 2007 Aurora Oil Pool Annual Reservoir Report This Annual Reservoir Report for the year ending June 30, 2007 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 8a) Enhanced Recovery Projects Water injection in the Aurora Oil Pool 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 will be 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 average reservoir pressure rather than producer pressure. Early implementation of the secondary and tertiary injection processes allows adequate time for producers to capture 7/06 – 6/07 PBU Aurora Annual Reservoir Report 1 mobilized oil. Proper field management includes monitoring of productivity, GOR, water cut, pressure, and injection voidage replacement ratios. Reservoir Management Summary 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 and 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 and productivity in S-108. Pressure data and 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. S-118 pressure data and production performance suggests that severe faulting in the area that could be isolating it from injection support. The S-118 well also has collapsed tubing and will remain shut-in until intervention options can be taken. 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. Voidage Balance by Month of Produced and Injected Fluids (Rule 8b) Monthly production and injection surface volumes are summarized in Table 1. Voidage replacement by fault block is summarized in Table 2. 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 8c) Reservoir pressure monitoring is performed in accordance with Rule 5 of Conservation Order 457A. A summary of reservoir pressure surveys, including surface pressure falloff (SPFO) and pressure buildup (PBU) tests, is shown in Table 3. The field average reservoir pressure map is shown in Figure 5. Some measurements were made using surface pressure and fluid level data (FL), but only those meeting quality control criteria (stable and accurate or trend able data from prior PBU/PFO test) are shown. 7/06 – 6/07 PBU Aurora Annual Reservoir Report 2 All producers in the AOP have evidence of pressure response to injection support. In March 2006, a bottom-hole pressure of 1549 psi in well S-115 raised concerns about support, but has since shown MI response from offset injector S-120i. A pressure buildup survey is being completed in S-115 to assess static pressure behavior and possible response to S-31A which started injection into the AOP in February 2007. S- 31A may also provide pressure support to well S-118. Results and Analysis of Special Monitoring (Rule 8d) Production logging surveys were completed in wells S-100 and S-121 during the reporting period to identify sources of water entry. Results indicated good conformance along the horizontal section of these wells. Review of Pool Production Allocation (Rule 8e) 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. Review of Plan of Operations and Development and Reservoir Depletion Plans (Rule 8f and 8g) Field development areas for the AOP have been defined by geological and reservoir performance data interpretation and are annotated in Figure 1. 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-116 and S-120 that were put on MWAG in 2006. Summarized on the next page are significant accomplishments at Aurora over the past year: 7/06 – 6/07 PBU Aurora Annual Reservoir Report 3 • Drilled and completed two new grassroots wells, S-124i and S-125. • RWO of well S-31A, converting it to a dual service injector for IPA and Aurora. • Drilled and completed Prince Creek source water wells, S-400 and S-401. • Approval of infill well S-126i (planned to be drilled in 4Q’07). • Evaluating additional infill wells S-127i and commingled producer S-26. The S-400 well was produced and SI in April 2006 due to a sand-control failure and is planned for a sidetrack in 4Q’07. After S-400A is drilled and both water source wells are on production tested, Aurora will be converted to Prince Creek water injection. Table 1 – Aurora Monthly Production, Injection, Voidage Balance Summary Case 1 Date Gas Inj Rate MSCFD Gas Prod Rate MSCFD Oil Prod Rate STB/D Water Inj Rate STB/D Water Prod Rate STB/D VRR Rate RVB/RVB 7/31/2006 11,635 30,971 10,016 20,136 8,430 0.733 8/31/2006 6,237 34,725 14,585 8,097 12,971 0.25 9/30/2006 6,549 45,349 14,185 30,174 12,387 1.006 10/31/2006 5,437 37,573 11,855 33,984 9,068 0.7 11/30/2006 6,126 33,867 10,722 34,264 8,531 0.887 12/31/2006 10,061 43,404 13,261 36,089 12,396 0.749 1/31/2007 25,799 45,167 12,357 31,364 10,876 0.888 2/28/2007 13,566 36,101 10,573 44,563 8,989 1.169 3/31/2007 12,818 38,412 10,634 50,235 9,210 1.238 4/30/2007 15,857 33,763 10,069 30,764 8,382 0.811 5/31/2007 23,280 31,309 10,065 35,866 9,456 1.169 6/30/2007 9,351 33,796 10,279 41,598 10,223 1.057 Table 2 – Cumulative Voidage Status by Fault Block 6/30/2007 AURCR* AURNOC AURSEC* AURWEST* Liquid Prod** Cum MRVB 4636 10515 2426 17982 Total Inj Cum MRVB 3312 13018 2768 33581 Total Prod Cum MRVB 13663 16906 7059 63871 Cum I/W ratio 0.242 0.770 0.392 0.526 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 0.757 rb / mcf gas MI ** Solution gas only 7/06 – 6/07 PBU Aurora Annual Reservoir Report 4 Figure 1– Aurora Well Location Map – Top Kuparuk C4 Depth Map CI=25 ft. NOC WEST SEC CREST Δ Active injector • Active producer • Non-Aurora • Evaluating 7/06 – 6/07 PBU Aurora Annual Reservoir Report 5 7/06 – 6/07 PBU Aurora Annual Reservoir Report 6 Figure 2 –Cumulative Voidage Replacement by Development Area Figure 3 – Field Cumulative Oil Production, Gas Injection, Voidage Replacement; and Average GOR Figure 4 – Gas Injection Rate (GIR), Oil Production Rate (OPR), Water Injection Rate (WIR), and Water-Oil Ratio (WOR-dashed) 7/06 – 6/07 PBU Aurora Annual Reservoir Report 7 Figure 5 – Well Penetration Map with Estimated Pressure Contours 7/06 – 6/07 PBU Aurora Annual Reservoir Report 8 Table 3 – Valid Aurora Pressure Surveys acquired since 7/1/06 Well Name & No. Api O/G/GI/WAG/WI Final Test Date Shut In Time Hrs. Pres Surv Type Bh Temp (F) Pressure at 6700’ss Datum Comments S-03 500292069500 Oil Producer Shut-In 3/18/071,080SBHP 146 2,839grad = 0.4 psi/ft S-101 500292296800 Miscible Injector Shut-In 8/1/06240FL 3,584CORRECTED FROM PRIOR SPFO S-102L1 500292297260 Oil Producer Shut-In 3/20/07>1000 SBHP 148 2,886 S-103 500292298100 Oil Producer Shut-In 7/12/06>1000 SBHP 149 3,801 S-103 500292298100 Oil Producer Shut-In 4/28/07126SBHP 142 2,948grad=0.44psi/ft S-107 500292302300 Water Injector Shut-In 9/27/0638SPFO 3,260TOE SECTION ONLY, P* REPORTED S-107 500292302300 Water Injector Shut-In 10/13/0671SBHP 128 2,618Heel section only. GRAD = 0.441 PSI/FT S-108 500292302100 Oil Producer Shut-In 6/14/07358SBHP 147 2,144GRAD = 0.35 PSI/FT, p* = 2144psi based on prior PBU, J. Young S-111 500292325700 Water Injector Shut-In 8/1/06240FL 2,930CORRECTED FROM PRIOR SPFO S-112 500292309900 Miscible Injector Shut-In 8/1/06240FL 3,490CORRECT FROM PRIOR SPFO S-114A 500292311601 Water Injector Shut-In 8/1/06240FL 3,526CORRECTED FROM PRIOR SPFO S-121 500292330400 Oil Producer Shut-In 8/27/06105PBU 2,760STRONG AQUIFER BOUNDRY, P* REPORTED S-122 500292326500 Oil Producer Shut-In 11/27/06264PBU 2,720P* REPORTED S-123 500292321900 Miscible Injector Shut-In 8/1/06240FL 3,532CORRECTED FROM PRIOR SPFO S-124 500292332300 Water Injector Shut-In 2/10/074PBU 146 3,153grad = .44 psi/ft 7/06 – 6/07 PBU Aurora Annual Reservoir Report 9 S-125 500292336100 Oil Producer Shut-In 7/6/070MDT 3,190grad = 0.35 psi/ft 7/06 – 6/07 PBU Aurora Annual Reservoir Report 10 7/06 – 6/07 PBU Borealis Annual Reservoir Report 1 Prudhoe Bay Unit 2007 Borealis Oil Pool Annual Reservoir Report This Annual Reservoir Report for the year ending June 30, 2007 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 and 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 19 injectors in full service. Enhanced Recovery Projects using Miscible Injectant (MI) have been implemented in the last year on wells L-108, L-111, L-117, L-123, V-105, and V-114A. Facility upgrades and commissioning to permit MI injection into all 19 injectors has been completed. (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 gas-oil-ratios (GORs). This trend reversed during 2003 and GORs have stabilized near solution GOR. Production was restricted in several wells in 2002 to conserve reservoir energy. As more injector patterns were implemented, no further production curtailment has been required. Water injection has a planned VRR target greater than 1.0 throughout the field. Facility limitations were identified in 2003, which limited the delivery pressure of water to be injected. Booster pumps have provided injection pressure to Borealis patterns sufficient for cumulative voidage replacement to approach 1.0. Reservoir pressure is restored to a target range of 3000-3400 psig, on all waterflood patterns. VRR is being actively managed to continue this voidage replacement. In general, the conservation strategy for Borealis waterflood management is progressing as planned. Borealis has experienced water breakthrough earlier than expected in many patterns. Impacts include reduced production due to gas lift supply pressure limitations, Borealis being at the end of the line. Remedies have included gas-lift redesign, optimization and prioritization of gas lift use, and increased injection to maintain flowing bottom-hole pressure. Understanding the flood behavior is key to our surveillance and development plans. 7/06 – 6/07 PBU Borealis Annual Reservoir Report 2 Voidage Balance by Month of Produced and Injected Fluids (Rule 9b) Monthly production and injection surface volumes for July 2006 to June 2007 are summarized in Table 1, and cumulative volumes can be found in Table 2. Attachments 2a, 2b and 3 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 1. Attachment 4 is a map contouring reservoir pressures collected over the last two years. Results and Analysis of Production & Injection Logging Surveys (Rule 9d) No production or injection profiles surveys were obtained during report period. Openhole resistivity logs through the Kuparuk have been used to evaluate vertical injection conformance via water sweep where feasible. Well logs used in this manner include L-03, drilled between L- 104 and L-105i, and V-120, drilled on the periphery between V-103 and the toe of V-106A. 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. Future Development Plans and Review of Plan of Operations and Development (Rule 9f and 9g) Development of the Borealis Reservoir in North Borealis, South Borealis and the main field are under evaluation. Construction is underway for the Z-Pad expansion with placement of gravel. The Z-Pad expansion anticipates 5-10 additional South Borealis development wells. Waterflood Waterflood has been implemented on L-, V- and Z-Pads. Injection was started June 8, 2003. 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. 7/06 – 6/07 PBU Borealis Annual Reservoir Report 3 Table 1 - Borealis Monthly Production, Injection Rates Date Gas Inj Rate MSCFD Gas Prod Rate MSCFD Oil Prod Rate STB/D VRR Rate RVB/RVB Water Inj Rate STB/D Water Prod Rate STB/D 7/31/2006 28,171 15,931 16,938 1.18 37,310 21,621 8/31/2006 15,530 14,950 16,435 1.09 39,460 20,552 9/30/2006 15,187 31,379 18,136 0.97 53,167 23,373 10/31/2006 15,956 24,277 15,817 0.93 38,136 19,050 11/30/2006 31,213 16,025 13,160 1.52 40,156 16,754 12/31/2006 29,994 22,701 17,164 1.29 47,265 19,786 1/31/2007 17,100 14,336 16,129 1.33 50,939 22,445 2/28/2007 18,061 14,276 15,291 1.32 49,656 22,967 3/31/2007 25,233 13,747 16,772 1.03 35,052 27,904 4/30/2007 20,816 12,287 12,931 1.00 27,325 22,020 5/31/2007 27,731 16,243 14,893 1.22 42,650 26,430 6/30/2007 19,583 24,015 17,728 0.79 36,964 28,732 Table 2 - Borealis Cumulative Production & Injection Summary MONTH_ENDIN G Data 2007 units 6/30/2007 Gas Inj Cum 18320 MMSCF Gas Prod Cum 42,017 MMSCF Oil Prod Cum 46,976 MSTB Water Inj Cum 74,232 MSTB Water Prod Cum 30,714 MSTB Total Production, reservoir vol.105,896 MRB Total injection, reservoir vol.90,327 MRB Cum I/W ratio 0.854 Bo 1.24 rb / stb oil Bg 0.97 rb / mcf gas Bw 1.030 rb / stb water Rs 0.500 mscf / stb oil Bmi 0.757 rb / mcf gas MI Δ Active injector • Active producer • Inactive or Non-Borealis 7/06 – 6/07 PBU Borealis Annual Reservoir Report 4 Figure 1 – Borealis Well Map as of June 29, 2007 Figure 2A – MI Gas Injection (GIR), Oil Production (OPR), Water Injection (WIR), <solid lines> Gas-oil Ratio (GOR) and Water-oil Ratio (WOR). <dashed lines> All volumes at stock tank conditions. GIROilWIRGORWORInjection rates, and production rates and ratios 7/06 – 6/07 PBU Borealis Annual Reservoir Report 5 Injection rates, and production rates and ratiosGIRGOROilWIRWOR7/06 – 6/07 PBU Borealis Annual Reservoir Report 6 Figure 2B – Borealis Voidage Replacement and Production / Injection History, in Reservoir Units Production, injection, and voidage replacement (VRR)Oil rateTotal injection: Water and MIInstant VRRVolumes in reservoir barrels.7/06 – 6/07 PBU Borealis Annual Reservoir Report 7 Figure 3 – Borealis Cumulative Production, GOR and Fill-up History Cum oil, Cum VRR, rolling VRR, GOROil3-month rolling VRRGORCum VRR7/06 – 6/07 PBU Borealis Annual Reservoir Report 8 Figure 4 – Borealis Pressure Map, August 2007 1500 psi 3500 psi CI = 100 psi 7/06 – 6/07 PBU Borealis Annual Reservoir Report 9 7/06 – 6/07 PBU Borealis Annual Reservoir Report 10 Table 3 – Borealis Pressure Survey detail: (Includes Static, SITP/FL, PFO and PBU surveys) Well Name and No. API number AOGCC Pool Code 640130 O/G/GI/WAG/WI Final Test DateShut In Time HoursPressure Survey TypePressure at 6600’ss Datum L-103 50-029-23101-00 Water injector 6/14/20073,144SBHP3007 L-111 50-029-23069-00 Gas injector 9/6/200672SPFO3591 L-112 50-029-23129-00 Oil Producer Shut-In 7/8/20069,610SBHP2835 L-112 50-029-23129-00 Oil Producer shut-in 7/8/20068,000SBHP2835 L-118 50-029-23043-00 Oil Producer Gas Lift 12/19/2006124SBHP2946 L-122 50-029-23147-00 Oil Producer Gas Lift 12/24/200650SBHP2865 L-124 50-029-23255-00 Oil Producer Gas Lift 10/14/200696SBHP2115 L-124 50-029-23255-00 Oil Producer Gas Lift 12/3/2006240SBHP2422 L-124 50-029-23255-00 Oil Producer Gas Lift 5/25/200772SBHP2438 V-105 50-029-23097-00 Gas injector 3/2/200726SBHP3273 V-106A 50-029-23083-01 Oil Producer Gas Lift 10/14/200696SBHP2901 V-106A 50-029-23083-01 Oil Producer Gas Lift 11/22/200696SBHP2933 V-106A 50-029-23083-01 Oil Producer Gas Lift 5/25/200796SBHP2917 V-111 50-029-23161-00 Oil Producer Gas Lift 4/17/2007463SBHP2734 V-121 50-029-23348-00 Oil Producer Gas Lift InitialSBHP2996 V-122 50-029-23328-00 Water injector 3/1/2007InitialSBHP3135 V-122 50-029-23328-00 Water Injector Injecting 5/25/200796SBHP2928 Z-102i 50-029-23353-00 Water Injector Shut-in 5/6/2007InitialMDT2842 Z-108 50-029-23292-00 Oil Producer shut-in 8/14/2006648PBU3087 Z-108 50-029-23292-00 Oil Producer shut-in 5/15/20072,880SBHP2825 Z-108 50-029-23292-00 Oil Producer shut-in 8/14/2007720SBHP2778 Prudhoe Bay Unit 2007 Midnight Sun Annual Reservoir Report This Annual Reservoir Report for the period from July 1, 2006 through June 30, 2007 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 11a) 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 GORs to enable wells to be produced at their full capacity, and maximize areal sweep efficiency. An upgrade to the GC-1 produced water injection pump in 2001 increased injection pressures and rates to 20-25 MBWPD. A June, 2005 inspection of the produced water supply line from GC-1 to the Midnight Sun injection wells revealed line corrosion resulting in a pressure derating of the supply line. The supply line was replaced in October, 2005 and full injection pressure was restored. Work to upgrade the GC-1 Skim Tank, which cleans produced water of solids and residual oil prior to re-injection into the Midnight Sun Reservoir, began mid-July, 2006 and was completed in September, 2006. 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. The VRR target of 1.0 to 1.2 should increase reservoir pressure while minimizing resaturation of oil into the gas cap. During the period covered by the report, the VRR averaged 0.87. Producer E-102 experienced water breakthrough from injector E-100 and stopped flowing due to excessive water during 2003. Gas lift was installed on the well in 2004. When the well was restarted in March, 2004, excessive gas volumes were produced. The top set of perforations was successfully squeezed in August, 2004, eliminating the excess gas production and most of the water production. Water production in E-102 gradually increased following the squeeze and the well currently produces at approximately 90% watercut. During 2005, the gas production in well E-102 steadily decreased and has since leveled off at ~ 6 mmscf/d. Well E-102 was moved to the low pressure flow line in November, 2005 and the well saw an increase in oil rate. Well-102 has poor-boy gas lift available but currently produces without it. E-102 was shut-in from 1/2/07 to 3/24/07 for choke repairs and tree replacement. Gas production in E-101 has continued to decline during the report period. Since July, 2005, gas lift has been utilized to produce E-101 efficiently. In February, 2006, water 7/06 – 6/07 PBU Midnight Sun Annual Reservoir Report 1 breakthrough was confirmed in Well E-101. Water production has continued to increase throughout 2006-2007. Well E-101 currently produces at ~75% watercut. Oil production during the report period has declined as the water production increased. Voidage Balance by Month of Produced and Injected Fluids (Rule 11b) A total of five Midnight Sun wells have been drilled, with the most recent wells drilled in 2001. Midnight Sun producing wells should have a combined rate of approximately 2-4 MBOPD through 2007. 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 11c) 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. The most recent pressure survey measured average reservoir pressure at 3076 psia. Reservoir pressure has decreased 1 psia in the last year. Results and Analysis of Production & Injection Logging Surveys (Rule 11d) A production profile log was run in E-101 on 6/30/07. Analysis of the log indicates the bottom set of perforations are covered with fill, resulting in 100% of the production coming from the perforation interval 13340’-13362’ MD. No production or injection log surveys were completed in the Midnight Sun Reservoir during the report period, 7/01/06 – 6/30/07. Results of Well Allocation and Test Evaluation (Rule 11e) Since August 2002, Midnight Sun production allocation has been performed according to the PBU Western Satellite Production Metering Plan. Midnight Sun production is processed through the GC-1 facility. Future Development Plans and Review of Plan of Operations and Development (Rule 11f and 11g) Development plans for the Midnight Sun Oil Pool are set forth in the Ninth Plan of Development for the Midnight Sun Participating Area. Well E-102, located to the south of Well E-100, was drilled 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. 7/06 – 6/07 PBU Midnight Sun Annual Reservoir Report 2 Table 1 Midnight Sun Monthly Production, Injection, Voidage Balance Summary Date (Mo-Yr) Oil Prod (stb) Water Prod (stb) Gas Prod (Mscf) Water Inj (stb) Cumulative Oil (stb) Cum Gas (Mscf) Net Reservoir Voidage (Mrb) July-06 103,843 100,672 145,924 296,662 14,855,832 47,573,525 -24 Aug-06 67,666 63,454 107,177 0 14,923,498 47,640,691 177 Sep-06 159,076 178,954 200,707 461,019 15,082,574 47,766,014 -61 Oct-06 171,490 254,398 404,998 574,066 15,254,064 48,079,212 70 Nov-06 142,790 307,495 279,476 538,891 15,396,854 48,358,688 110 Dec-06 155,186 350,926 553,687 557,252 15,552,040 48,844,175 321 Jan-07 107,122 280,204 371,781 622,190 15,659,162 49,215,956 45 Feb-07 86,154 95,472 160,732 590,599 15,745,316 49,376,688 -310 Mar-07 83,557 190,040 251,287 619,238 15,828,873 49,627,975 -169 Apr-07 122,777 395,980 485,993 538,341 15,951,650 50,047,967 307 May-07 106,618 391,701 484,337 643,148 16,058,268 50,464,073 178 June-07 73,401 209,930 238,025 263,438 16,131,669 50,702,098 206 Assumptions for Production Table: Oil Formation Volume Factor = 1.27 rb/stb Water Formation Volume Factor = 1.03 rb/stb Gas Formation Volume Factor = .86 rb/Mscf Table 2 Reservoir Pressure Surveys Well Date Type Temp (deg F) Depth (ft, ss) Pressure (psi) E-102 7/20/06 SBHP 162 8,050 3,077 E-102 2/17/07 SBHP 164 8,050 3,103 E-102 6/17/07 SBHP 161 8,050 3,076 7/06 – 6/07 PBU Midnight Sun Annual Reservoir Report 3 Prudhoe Bay Unit 2007 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 505A, and covers the period from July 1, 2006 to June 30, 2007. Voidage Balance by Month of Produced and Injected Fluids (Rule 9a) Monthly production and injection surface volumes, cumulative volumes, as well as 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 505A. A summary of valid pressure surveys obtained during the reporting period is shown in Table 2. This data was acquired from open-hole formation tester surveys (MDT), static bottom hole pressure surveys (SBHP), and permanent downhole gauges installed in new wells. Figure 3 illustrates all 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 due to the nature of viscous oil, six 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. This is further complicated by significant differences in rock and oil properties between sands in the same wellbore, and therefore 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 very questionable, and therefore extrapolating a representative average reservoir pressure very difficult. As a result, 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 this 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 surveys relatively unaffected by pressure gradients applied to the wellbore. The level of drilling affords a number of good-quality pressure measurements. Whenever possible, by-zone initial pressures are being obtained with MDTs, and the straddle packer completion design employed in new Orion injectors presents an outstanding opportunity to obtain individual sand pressures prior to injector start-up. 7/06 – 6/07 PBU Orion Annual Reservoir Report 1 Pressure data acquired during the reporting period shows some depletion from production. The lowest pressure encountered was in V-217i in the OA interval which could reflect compartmentalization resulting from faulting observed in offset producer V-204. High quality MDT data obtained in new penta-lateral L-204 is shown in Figure 5, which shows some depletion from offset producers. Results and Analysis of Production & Injection Logging Surveys, and Special Monitoring (Rule 9c) Production Logs: A production profile was attempted in quad-lateral V-204 in August 2006 to identify the source of water production and underperformance. An MBE had been identified from V-213i to V-204 earlier in 2006 in the OBa zone. No definitive data was obtained from this log due to spinner plugging, but follow-up coil work showed that production from the bottom two laterals was plugged by sand. Production logging is accomplished with memory PLT tools conveyed by coiled tubing, but conventional tools and centralizers can get stuck across multilateral junction windows, as has happened in prior jobs. New tools are being designed to address this risk. Injection Logs: Injection profile logs were run on a number of active injectors during the report period, and are listed in Table 3. Data from these logs is being used to map zonal sweep, and balance voidage by regulating injection by zone. Note that several surveys highlight the disparity of rock and oil quality between sands which results large differences in injectivity between zones. It is not uncommon for a well with 4+ zones open to have a single sand that takes the majority of the total injection. Commingled injector monitoring: Three commingled Borealis / Orion injectors (V-105, L- 103, and L-117) are currently in service providing injection support to both pools. Injection rate to the Schrader Bluff interval is controlled by a wireline-retrievable flow regulator set in an injection mandrel adjacent to the straddled Schrader interval. Good quality injection profiles were obtained in these wells across the Schrader interval by using the water flow log to determine flow behind the tubing. These profiles are the first that successfully mapped the Schrader splits in these wells, despite several attempts. Uphole Zone Pressure Monitor: New injector V-217i was completed near a plug-back hole drilled, but abandoned due to inadvertently sidetracking. The final V-217 completion included a downhole pressure gauge adjacent to a wet uphole Mc sand to monitor the long- term pressure trends. The gauge was installed as part of the group of sandface gauges installed in other zones, with the intent that it may detect evidence of crossflow between injected fluids migrating out of the O sands to the high-mobility Mc zone via the abandoned wellbore. To date, there has not been any change the in Mc pressure. Geochemical Fingerprinting: This technique has been in use since 1999 in the North Slope viscous oil developments, and has shown great promise in obtaining snapshot relative oil flow splits from individual sands. This data is useful in gauging zonal well performance, identifying a problem lateral, and provides a basis by which to optimize offset injection. 7/06 – 6/07 PBU Orion Annual Reservoir Report 2 Wellhead oil samples are taken on roughly a quarterly basis, or as well performance changes. Oil samples from individual sands (“end-members”) were obtained recently from MDT on L-204, which has allowed for allocating production from L-204 and L-201. A few end-member samples in select polygons are still needed, but the base dataset is almost complete to allocate L- and V-Pad producers. Analysis of previously obtained production samples using the new end-member samples is ongoing. Real-time Downhole Pressure Gauges in Injectors: A recent change to the injector design is the addition of real-time permanent downhole gauges which measure sandface pressure adjacent each individual injection zone. Data from these gauges is streamed to the SCADA system, and stored for analysis. This “smart well” component will provide accurate pre- injection sand pressures, monitoring of injection performance, and more quickly diagnose any injection problems with the reservoir or downhole mechanical equipment. These gauges, along with an upgraded surface control kit are part an ongoing effort to provide a high level of injector control to better manage the reservoir. Well Testing Improvements: A number of initiatives are underway to improve welltest quality in the Western Operating Area, which includes Orion development wells: A) A strap-on sonar-based CiDRA meter was installed on L and V pads to measure the Gas Volume Fraction (GVF), which is the amount of gas entrained in the liquid that cannot break-out before it flows through the liquid metering leg of the separator. Measurement of the GVF allows for compensation of overall mass density, which results in more accurate calculation of gross fluid rate, WC, and GOR. Surface oil sampling reveals that the gas- lifted Schrader Bluff oil is very foamy, and gas does not break out of the liquid easily. The CiDRA meter will be a key component in the evolving “kit” to modify testing equipment that was designed for “light” oil so that it can accurately meter viscous oil. B) An extensive study of production behavior for each well was also completed to quantify the best purge and test lengths needed in order to capture several full “cycles” of production. This is especially useful on slugging wells which can produce long cycles of high watercut, followed by cycles with low watercut. Depending on what portion of these cycles were captured in a welltest period, test results can vary dramatically. Data from this study now drives the welltest periods on a well-by-well basis. C) Work is ongoing to test and qualify a portable multiphase flowmeter as an alternative to the current well pad separator equipment. Another test is planned to evaluate on-pad permanent multiphase equipment. D) A fieldwide team has been meeting to identify problem areas, evaluate new testing components, and update testing techniques. 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 verify system performance, with more frequent testing during new well start-up and after significant wellwork. 7/06 – 6/07 PBU Orion Annual Reservoir Report 3 Progress of Enhanced Recovery Project Implementation and Reservoir Management Summary (Rule 9e) Enhanced Recovery Projects Waterflood began in Orion in December 2003. At report time, there are sixteen stand-alone and three commingled injectors in use. Polygon-level waterflood patterns are being filled-in as new producers and injectors are drilled. Injector designs are evolving, and downhole flow regulators are being employed to balance the flood. 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. MI was expanded to V-210, V-211, V-214 and V-216 in 2Q, 2007. These wells will also seek to evaluate how MI injection will be distributed across multiple zones with large variations in rock and oil quality, test the value of MI as a pre- water injection stimulation technique, and provide information on injectivity for implementing MI in other patterns. Based on learnings from this initial MI pattern, additional WAG patterns will be added. All Orion injectors were tied-in with MI supply lines during a major infrastructure upgrade in 2006. 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 above bubble point pressure. One tenant 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 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 five individual legs (“penta-lateral”), >27K ft of high-angle footage (27,743’ drilled; 24,871’ competed 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 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 the ~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. 7/06 – 6/07 PBU Orion Annual Reservoir Report 4 Matrix Bypass Events (MBE): There have been no new MBEs in Orion during this report period. As described in last year’s Reservoir Report, 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. Multilateral Intervention Toolbox: Work continues to develop tools and techniques to successfully intervene in complex multilateral wellbores. A checklist of “toolbox” items has been developed to provide assurance that a wide range of intervention work can be accomplished in the future. During the report period, several techniques were tested in tri- lateral L-250: 1) Isolation sleeves were run and pulled successfully. 2) A metal-to-metal lubricant was used to achieve an additional 3000’ reach in a lateral. 3) A new multilateral junction locator tool (Discovery tool™) was used to locate and enter both junctions without a mechanical diverter. 4) Fill clean outs were performed in two laterals. 5) A special rotating side-jet nozzle (Jetblaster™) was used to clean the screens in the completion. 6) A specially designed “mainbore centralizer” was used to keep the coil and logging tools from inadvertently entering a lateral. Reservoir Simulation Studies Extensive reservoir simulation has been performed for the Orion field and refinements to the models continue as new data is gathered. Integration of a large amount of well log and fluid quality information has resulted in a high-quality reservoir description and fluid characterization that provides the foundation for the simulation models. Reservoir simulation has provided the basis for development planning as well as waterflood management strategy. The fifth generation of polygon-level simulation models, which include improvements to vertical heterogeneity estimates, were built this year and are being used to solidify the long term development strategy and injection strategy. Orion has just recently started to experience water breakthrough in wells V-202, V-204, and L-201. An extensive amount of history matching on gas and water has been done to understand the expected waterflood response, fluid movement, and compartmentalization in the reservoir, as well as the production character of each multilateral well. The EOR model has been updated to test the effects of the new vertical heterogeneity estimates on the benefits. These models confirmed the benefits of MI injection derived from previous generation models. Progress of Plans and Tests to Expand the Productive Limits of the Pool (Rule 9f) Orion Schrader Bluff oil accumulations were better defined in the area north of Z-Pad through the drilling and logging of EWE well Z-19A and Borealis well Z-102. The Z-19A well logged wet Schrader Bluff Nb through OBd sands in a downthrown fault which were 7/06 – 6/07 PBU Orion Annual Reservoir Report 5 7/06 – 6/07 PBU Orion Annual Reservoir Report 6 expected to be wet in the most likely case, but which still had oil potential in an upside/maximum fill case. Z-19A results confirmed our expected case fluid level assumptions. Z-102 confirmed the presence of Schrader Bluff Nb through OBd sand oil in the southern extension of the main V-Pad fault block with logged Z-102 oil-down-to levels consistent with oil and water fluid levels logged in nearby wells. This consistency of fluid contacts supports, but does not prove, our assumption of hydraulic continuity within the main fault block extending between the southern V-Pad and northern Z-Pad areas. There were no Prince Creek wells drilled to support Orion activity. Results of Monitoring to Determine Enriched Gas Injectant Breakthrough to Offset Producers (Rule 9g) MI injection started last fall, with additional wells added 2Q07. Gas sampling has been initiated in four producers which surround the MI injectors. API gravities and gas composition suggest a possible MI breakthrough in V-203, but the data is still very limited at this early time. Recent Development Work Two multilateral producers and five injectors were drilled during this report period (Table 4). Work is ongoing to complete injection patterns. Infrastructure upgrades were completed in 2006 to add MI supply lines, and install smaller, remote-actuated chokes on all injectors to improve injection control. Future Development Plans Additional production and injection wells from L- and V-Pad are being evaluated fro drilling in the next year. Where possible, plug-back appraisal legs will be drilled to test reservoir boundaries. Testing and logs will be run on Borealis and Ivishak new drills that cross the Schrader Bluff horizon. The future development for Orion may encompass as many as seventy (70) to one hundred twenty-five (125) production and injection wells on L-, V-, Z- Pads, and a proposed I-Pad. BU Orion Annual Reservoir Report 7 Report y DatJul-06Aug-Sep-Oct-Nov-Dec-Jan-Feb-Mar-Apr-May-Jun- Table 1 – Orion Monthly Production & Injection Summary 7/06 – 6/07 P Oil Prod Gas Prod Water Prod Water Inj MI InjOil Prod CumGas Prod CumWater Prod CumWater Inj CumCum Total Inj (MI+Water)Net Res VoidageNet Voidage CumMonthlVRRe STB MSCF STB STB MSCF STB MSCF STB STB RBRVB RVB RVB/RVB285,245. 198,913. 32,263. 289,317. 0 6,571,821. 6,837,803.249,526. 4,685,047. 4,685,047 102,293 4,657,384 0.7406 190,670. 104,846. 16,418. 319,306. 0 6,762,491. 6,942,649.265,944. 5,004,353. 5,004,353 -72,776 4,584,608 1.3006 220,792. 174,659. 38,628. 402,186. 0 6,983,283. 7,117,308.304,572. 5,406,539. 5,406,539 -77,982 4,506,627 1.2406 210,272. 138,430. 34,281. 321,960. 41,820. 7,193,555. 7,255,738. 338,853. 5,728,499. 5,753,173 -50,399 4,456,228 1.1706 172,752. 89,525. 20,759. 343,260. 40,800. 7,366,307. 7,345,263. 359,612. 6,071,759. 6,120,505 -140,048 4,316,180 1.6206 322,087. 136,301. 27,248. 373,657. 67,345. 7,688,394. 7,481,564. 386,860. 6,445,416. 6,533,895 -12,075 4,304,105 1.0307 320,229. 160,646. 26,351. 413,503. 71,090. 8,008,623. 7,642,210. 413,211. 6,858,919. 6,989,341 -48,166 4,255,939 1.1207 305,118. 182,054. 23,180. 312,726. 83,130. 8,313,741. 7,824,264. 436,391. 7,171,645. 7,351,114 34,766 4,290,705 0.9107 315,300. 256,277. 41,790. 350,546. 92,566. 8,629,041. 8,080,541. 478,181. 7,522,191. 7,756,274 46,906 4,337,611 0.9007 227,633. 155,209. 33,430. 271,675. 90,408. 8,856,674. 8,235,750. 511,611. 7,793,866. 8,081,290 -6,084 4,331,527 1.0207 296,816. 199,289. 50,235. 249,623. 235,546. 9,153,490. 8,435,039. 561,846. 8,043,489. 8,469,885 32,803 4,364,330 0.9207 433,767. 332,666. 60,438. 186,605. 247,576. 9,587,257. 8,767,705. 622,284. 8,230,094. 8,802,560 285,048 4,649,378 0.54