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Home My WebLink About2003 Aurora Oil PoolBP Exploration (Alaska), Inc. 900 East Benson Boulevard Post Office Box 196612 Anchorage, Alaska 99519-6612 Telephone (907) 564 581 March 10, 2021 Commissioners Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, AK 99501 RE: Aurora Oil Pool Annual Reservoir Report Dear Commissioners: Enclosed is the Aurora Oil Pool (“AOP”) Annual Reservoir Report as required by Conservation Order 457A for the year 2003. Please call Jim Young 564-5754 if you have any questions regarding this report. Sincerely, Gil Beuhler GPB Satellites Manager Attachments CC: Mark Vela (ExxonMobil) Dan Kruse (CPAI) Ken Griffin (Forest Oil) Steve Wright (Chevron-Texaco) 1 Prudhoe Bay Unit 2003 Aurora Oil Pool Annual Reservoir Report This Annual Reservoir Report for the year ending December 31, 2003 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 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. Expansion of MWAG to other areas of the field is dependent upon performance of primary production and waterflood operations, and is anticipated in 2004 for the Southeast Crest (SEC) and Crest (CR) blocks. 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 2 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 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), primarily due to existence of an initial gas cap in the West side of the field. Production was restricted to conserve reservoir energy. Beginning in mid-2001 and continuing through 2002, production from Wells S-100 and S-102 were reduced to approximately half capacity, allowing injection in Well S-101 to significantly reduce the GOR in Well S-100 by the end of 2002. This practice continued in 2003 with curtailment of wells S-106, S-113B and S-108. 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 8 b) Monthly production and injection surface volumes are summarized in Table 1. Voidage replacement and GOR trends by fault block are shown in figure 1 and summarized in Table 2. Plans to achieve injection withdrawal ratios consistent with the reservoir management strategy include stimulation of injection wells (S-101i, S-107i, and S-112i in November 2003) as well as increasing supply pressure to enhance injection rates where needed. Table 1 Aurora Monthly Production, Injection, Voidage Balance Summary Gas Inj, MSCF Water Inj, stb Oil Prod, stb Gas Prod, MSCF Water Prod, stb I/W ratio 01/01/2003 0. 295,195. 236,112. 931,786. 64,601. 0.3 02/01/2003 0. 334,565. 266,831. 1,180,495. 60,245. 0.27 03/01/2003 0. 575,520. 307,379. 1,024,039. 67,707. 0.51 04/01/2003 0. 696,598. 368,908. 1,084,649. 71,260. 0.57 05/01/2003 0. 605,187. 300,348. 840,115. 68,268. 0.62 06/01/2003 0. 593,120. 337,021. 1,477,084. 65,690. 0.39 07/01/2003 0. 759,950. 316,248. 1,132,588. 86,411. 0.61 08/01/2003 0. 827,891. 276,772. 679,345. 75,467. 1. 09/01/2003 0. 840,855. 276,179. 646,260. 107,448. 1.01 10/01/2003 0. 509,207. 342,038. 917,404. 103,225. 0.46 11/01/2003 0. 685,471. 358,499. 952,016. 143,804. 0.58 12/01/2003 356,898. 561,429. 395,896. 1,104,794. 315,871. 0.55 3 Figure 1 VRR and GOR trends by fault block 4 Table 2 Cumulative Voidage Status by Fault Block Cume by Area West NOC SEC CR Voidage (Mrb) 28,511 5,280 3,169 2,326 Inj (Mrb) 6,834 1,543 227 - I/W ratio 0.24 0.29 0.07 - Formation Volume factors (CO457A Application: Exhibit II-2: Aurora Fluid Properties) Bo 1.345 rb/stb oil Bg 0.843 rb/Mcf gas Bw 1.030 rb/stb water Rs 0.717 mscf/stb oil Bmi 0.757 rb/Mcf gas MI month ending: 03/03 stb Mcf stb stb rvb Block Well Oil Prod Cum Gas Prod Cum Water Prod Cum Water Inj Cum Net Res Voidage NOC Total 1,508,515. 2,114,761. 1,115,849. 553,637. 3,478,981 SEC Total 415,211. 1,974,420. 21,021. 0. 1,993,580 West Total 3,254,093 24,769,372 112,453. 4,065,113. 19,219,221 Grand Total 5,177,819 28,858,553 1,249,323. 4,618,750. 24,691,783 Formation Volume factors (from Pool Rules Application: Exhibit II-2: Aurora Fluid Properties) Bo 1.345 rb/stb oil Bg 0.843 rb/Mcf gas Bw 1.03 rb/stb water Rs 0.717 mscf/stb oil 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 17 reservoir pressure surveys obtained in 2003, including surface pressure falloff (SPFO) and pressure buildup (PBU) tests is shown in Table 3. The field average reservoir pressure was 3142 psi as of April 2003. The represents approximately 10% pressure depletion and is consistent with the net voidage as a percentage of the reservoir hydrocarbon pore volume. Although some measurements were made using surface pressure and fluid level data, only pressure measurements meeting quality control criteria (stable and accurate or trend able data from PBU/PFO test) are shown. Table 3 – Valid Pressure Surveys acquired in 2003. area: Well status Well NAME DATE DAYS SI PRES_ SURV_ TYPE Press@ Datum psig COMMENTS CR O S-115 3/27/2003 NA SBHP 3,071 Grad = 0.308 psi/ft CR O S-117 6/5/2003 1.5 PBU 3,396 still in linear flow, fault ~262' from well CR O S-115 9/13/2003 3.8333 FL 3,261 FL @ 216', SITP=1250 psi. LG/GG=.36/.04 psi/ft CR SI S-116 12/15/2003 NA RFT 3,242 ~150psi depletion in C-sand, 0psi in A-sand NOC WI S-104 3/8/2003 2 SPFO 2,899 Per PE - 0.442 psi/ft NOC WI S-104 5/28/2003 3 FL 3,465 SITP = 1150 psig, FL @ 1648' SEC O S-109 2/1/2003 NA SBHP 3,349 Grad = 0.518 psi/ft 5 SEC O S-112 6/13/2003 32.67 SBHP 2,919 Building >2 psi/hr after long SI SEC O S-108 6/18/2003 5.54 PBU 2,700 fault seen at 100', drainage radius ~600' at 133 hrs si (P*, correction to 4Q’03 10-412) SEC O S-110 7/14/2003 90.58 PBU 2,835 S-109 POP last 360 hrs of buildup; P* SEC WI S-112 09/12/03 1.13 SPFO 3,254 GRAD=0.44 PSI/FT; P* reported WEST WI S-114A 3/1/2003 89 SBHP 2,733 picked from WFL prior to Inj SU WEST WI S-107 4/8/2003 1.5 SPFO 2930 extrap press reported, Pbar = 3171 psi WEST O S-102 6/14/2003 7.04 PBU 2,346 P* extrap from horner (JPY) WEST O S-106 7/17/2003 30.33 SBHP 1,919 Well partially isolated from injection. WEST WI S-114A 09/10/03 2.50 SPFO 2,760 GRAD=0.44 PSI/FT; P* reported WEST O S-113B 10/22/2003 90.63 SBHP 2,747 GRAD=0.30 PSI/FT Due to relatively low reservoir permeability, PFO/PBU test have been critical to understanding pressure surveys and their implications to reservoir pressure in the AOP. On the north-slope, a well is typically shut-in (SI) for 5-days prior to obtaining a pressure survey. This allows the pressure in the wellbore to equalize with the reservoir so a representative measurement can be taken. In extremely low permeability reservoirs however, wells may take a much longer period to stabilize. Figure 1 shows bottom hole pressure data from AOP well S-110 that is still building 2 psi/hour after over 90 days of SI. This behavior indicates low effective permeability (4 milli-darcies) in the reservoir and extrapolation of this data using pressure transient analysis (PTA) indicates the well-bore pressure is still 500psi lower than the reservoir. AURORA S-110 EXTENDED PBU -1000.0.1000.2000.3000.-100.200.Time (hours) rates STB/DAURORA S-110 EXTENDED PBU -1000.0.1000.2000.3000.500.1000.1500.2000. pressure PSIHomogeneous Reservoir ** Simulation Data ** well. storage = 0.00267 BBLS/PSI skin = -5.00 permeability = 4.00 MD Perm-Thickness = 160. MD-FEET +x Distance = 800. FEET (1.00) Initial Press. = 2975.00 PSI 2003/04/17-0125 : OIL Figure 2 S-110 PBU data after 90-days SI 6 Because it is not viable to SI wells for 3 months at a time, PTA techniques are employed to assess pressure surveys in the AOP. A low pressure in well S-108 was observed during a 5-day PBU on 7/18/03, and is compared with S-110 data in figure 3. Due their similar reservoir properties the PBU data from the two wells nearly overlay. Using PTA, the reservoir pressure around S-108 was estimated at 2700 psi, nearly 1000psi higher than what was measured in the wellbore after nearly six days of SI. aurora s108110 -1000.0.1000.2000.3000.-100.300.Time (hours) rates STB/Daurora s108110 -1000.0.1000.2000.3000.500.1000.2000. pressure PSI.(2198.,2238.).(2198.,2238.).(2198.,2238.).(2198.,2238.).(2198.,2238.).(2198.,2238.).(2198.,2238.).(2198.,2238.).(2198.,2238.).(2198.,2238.).(2198.,2238.).(2198.,2238.).(2198.,2238.).(2198.,2238.).(2198.,2238.).(2198.,2238.).(2198.,2238.).(2198.,2238.).(2198.,2238.).(2198.,2238.).(2198.,2238.).(2198.,2238.).(2198.,2238.).(2198.,2238.).(2198.,2238.) 2004/08/24-0948 : OIL Figure 3 Comparison of S-108 (100hr SI) and S-110 (2100hr SI) PBUs Results and Analysis of Special Monitoring (Rule 8 d) Production & Injection Logging Surveys In 2003, surveys were obtained in Wells S-114Ai, S-103 and S-115. On March 1, an injection survey in Well S-114Ai was undertaken in combination with a water-flow log and verified injection containment in the AOP. A production profile completed on September 8 in Well S-103 indicated fracture growth into a lower zone (C-1) would prevent a water-shutoff from being successful. A production profile completed in Well S-115 on September 9 indicated majority of production from the C-sand, but that the A- sand perforations were flowing through a separate propped fracture. No other special monitoring was undertaken during the reporting period. 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. 7 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. 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, 3) South East of Crest Area, and 4) Crest Area. Primary production is occurring from each area. An effective water-flood has been established in the West Area and North of Crest Area, providing pressure support and reducing residual oil saturations. Tertiary EOR MWAG in these areas began in 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 & July 2003. 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 2004 with newly drilled injection wells S- 116 and S-120. Figure 4 Well Penetration map with Estimated Pressures at 6700' datum 8 Figure 3 Test Oil & GOR vs. Allocated Production for 2003, S-100 to S-108 9 Figure 4 Test Oil & GOR vs. Allocated Production for 2003, S-109 to S-117