An Evaluation of Miscible CO2 Flooding in Waterflooded Sandstone Reservoirs
- H.R. Warner Jr. (Atlantic Richfield Co.)
- Document ID
- Society of Petroleum Engineers
- Journal of Petroleum Technology
- Publication Date
- October 1977
- Document Type
- Journal Paper
- 1,339 - 1,347
- 1977. Society of Petroleum Engineers
- 5.1 Reservoir Characterisation, 5.2 Reservoir Fluid Dynamics, 5.4.1 Waterflooding, 4.6 Natural Gas, 5.4.2 Gas Injection Methods, 2.5.2 Fracturing Materials (Fluids, Proppant), 5.8.7 Carbonate Reservoir, 1.2.3 Rock properties, 5.2.1 Phase Behavior and PVT Measurements, 5.4 Enhanced Recovery, 5.3.2 Multiphase Flow, 5.4.7 Chemical Flooding Methods (e.g., Polymer, Solvent, Nitrogen, Immiscible CO2, Surfactant, Vapex), 5.5 Reservoir Simulation, 5.3.4 Reduction of Residual Oil Saturation
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Miscible CO2 flooding in waterflooded sandstone reservoirs was studied using hypothetical reservoirs that incorporated rock and fluid properties representative of many watered-out Mid-Continent reservoirs. A four-component, miscible, mixing-parameter reservoir simulator was used to investigate the factors that govern tertiary oil recovery.
A large number of Mid-Continent and Rocky Mountain sandstone reservoirs are nearing the economic limit of oil production through waterflooding. For these reservoirs, production through waterflooding. For these reservoirs, additional oil production will come from a tertiary oil recovery process, most likely a surfactant flood or a miscible CO2 flood. This paper describes a computer simulation study of the potential of miscible CO2 flooding in waterflooded sandstone reservoirs. The purposes of this study were (1) to determine the expected CO2 tertiary oil recovery under typical reservoir conditions; (2) to determine the best mode of operation - that is, straight CO2 injection or some combination of water and CO2 injection; and (3) to determine the sensitivity of the tertiary oil recovery to variations in reservoir parameters.
The hypothetical reservoirs analyzed here were constructed to incorporate rock and fluid properties representative of many nearly watered-out Mid-Continent oil reservoirs. The ranges of rock and fluid properties to which the results of this study apply include porosities from 15 to 25 percent, permeabilities from 30 to 500 md, formation thicknesses from 15 to 40 ft, well spacings of 10 to 40 acres, kV/kH ratios from 0.01 to 1.0, and oil viscosities from 1 to 10 cp. It was assumed in this study that the reservoir was maintained above the miscibility pressure of the reservoir crude oil and CO2. pressure of the reservoir crude oil and CO2. Several papers in the literature describe the past work with CO2 displacement processes and water-solvent mixtures. Rathmell et al. and Shelton and Schneider presented experimental studies of the miscible CO2 process. presented experimental studies of the miscible CO2 process. Caudle and Dyes and Blackwell et al. describe the concepts of displacements using combinations of water and solvent injection. Several authors have discussed field applications of CO2 injection as a secondary oil-recovery process in carbonate reservoirs. Finally, one paper briefly sketches the application of CO2 injection paper briefly sketches the application of CO2 injection to increase recovery from the Little Creek sandstone reservoir.
Simulator and Grid Descriptions
A four-component, miscible, mixing-parameter reservoir simulator was used to investigate the factors that govern CO2 tertiary oil recovery. This simulator is basically similar to the one described by Todd and Longstaff, but this simulator incorporates the concepts of miscibility pressure, a residual oil saturation to flooding by a miscible fluid, and adsorption of CO2 by the aqueous phase. In our version, the fourth component is miscible with the gas under all conditions and miscible with the oil if certain miscibility criteria are satisfied. A mixing parameter, omega, defined in Ref. 9, must be specified in this model. In this study, omega = 0.8. A theoretical analysis of the basis of this choice is presented in Appendix A. Sormf, the residual oil saturation to the miscible fluid, was 10 percent, a value based on previous studies. The term "potential tertiary oil" used elsewhere in this paper is defined as the difference between the oil remaining in the reservoir at the end of the waterflood and the oil left because of Sormf.
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