Lick Creek Meakin Sand Unit Immiscible CO2 Waterflood Project
- Thomas B. Reid (Phillips Petroleum Co.) | Harvey J. Robinson (Phillips Petroleum Co.)
- Document ID
- Society of Petroleum Engineers
- Journal of Petroleum Technology
- Publication Date
- September 1981
- Document Type
- Journal Paper
- 1,723 - 1,729
- 1981. Society of Petroleum Engineers
- 1.6 Drilling Operations, 5.8.5 Oil Sand, Oil Shale, Bitumen, 4.1.2 Separation and Treating, 5.1.1 Exploration, Development, Structural Geology, 5.6.4 Drillstem/Well Testing, 5.4.1 Waterflooding, 5.4 Enhanced Recovery, 4.2 Pipelines, Flowlines and Risers, 4.1.5 Processing Equipment, 5.2.1 Phase Behavior and PVT Measurements, 6.5.2 Water use, produced water discharge and disposal, 5.1.2 Faults and Fracture Characterisation, 4.2.3 Materials and Corrosion, 3.1.6 Gas Lift, 5.5 Reservoir Simulation, 5.3.2 Multiphase Flow, 2.4.3 Sand/Solids Control, 5.4.2 Gas Injection Methods, 5.2 Reservoir Fluid Dynamics, 4.1.6 Compressors, Engines and Turbines, 1.2.3 Rock properties
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This paper reviews the early performance of an immiscible CO2 /waterflood project conducted for the past 5 years at the Lick Creek Meakin Sand Unit, AR. The project is currently in the third of four distinct phases. The conclusions drawn are that the project is successful and that the immiscible project is successful and that the immiscible CO2 /waterflood process is a viable process for thin, heavy oil sands.
The Lick Creek field in southern Arkansas in Bradley and Union Counties (Fig. 1) was discovered in 1957. The unit was formed in 1975 for an immiscible CO2 /waterflood project. The reservoir is the Meakin sand of the Ozan formation of the Cretaceous Age. During the early 1970's, the oil production under primary methods was approaching abandonment primary methods was approaching abandonment rates and various secondary recovery methods were considered. A favorable response from a small- volume, immiscible CO2 project conducted by U.S. Oil and Refining CO2. in the nearby Ritchie field in a similar-type reservoir caused CO2, to be considered for the Lick Creek field. Theoretical considerations] and reservoir simulation indicated an immiscible CO2/waterflood process would be the preferable secondary recovery method for the Meakin sand, using alternate CO2/water injection at pattern injectors, cyclic CO2 stimulation of the producers, followed by a waterflood. The 16 injection patterns with the 38 producers are shown in Fig. 1.
The project is being conducted in four distinct phases, using the 16 in - jectors and 38 producers on phases, using the 16 in - jectors and 38 producers on 1,640 acres (6.6 x 10 m ). The phases are (1) cycling all wells with CO2 , (2) CO2 injection into the permanent injectors, (3) CO2 /water injection into the permanent injectors, (3) CO2 /water injection into the permanent injectors, and (4) water injection into the permanent injectors, and (4) water injection into the permanent injectors. The project currently is in permanent injectors. The project currently is in Phase 3. Future plans are to drill nine additional Phase 3. Future plans are to drill nine additional producers, to rearrange the injection patterns, and to producers, to rearrange the injection patterns, and to double the recycling capacity.
After 5 years of operation, 7.6 Bscf (0.22 x 10-9 std m3) of source CO2, and 6.5 Bscf (0. 18 x 10 std m3) of recycle CO2 have been injected, and more than 1 MMbbl (0.16 x 10-6 m3) of oil have been produced. About 755,000 bbl (120 000 m) are considered additional oil resulting from the process. Field rates have been as high as 1,400 BOPD (223 m /d oil), with the present rate being 833 BOPD (132m3/d oil).
The Meakin sandstone reservoir is a fault-trap structure limited on the south by a fault and on the north, east, and west by low permeability and the water/oil contact. The Meakin sand is of beach origin, unconsolidated, and fine grained and is located in the Ozan formation near the top of the Upper Cretaceous. The under- and overlying shales are impermeable and represent a reservoir seal. Formation depth is 2,550 ft (777 m), net thickness averages 9 ft (2.7 m), permeability averages 1,200 md, porosity is 33%, and the connate water saturation is 32%.
The reservoir produces a 17 deg. API (0.95 g/cm3) Oil and has a viscosity of 160 cp (0.160 Pa s) at the reservoir temperature and pressure of 118 deg. F (48 deg. C) and 1,200 psi (8274 kPa). Original oil in place (OOIP) was 23.3 MMbbl (3.7 x 10-6 m3), with about 4.5 MMbbl (0.7x 10 m ), or 19% of OOIP, being produced by pressure depletion and a weak water produced by pressure depletion and a weak water drive in the 20 years before the project (see Table 1).
Before CO2 injection, the field was pumped at a rate of 230 BOPD (36.6 m /d oil), a low GOR, and a WOR of 21. During the huff 'n' puff phase, all wells flowed naturally.
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