A laboratory approach on the improvement of oil recovery and carbon dioxide storage capacity improvement by cyclic carbon dioxide injection

Abstract

This paper experimentally investigated influential thermodynamic reservoir characteristics such as pressure, temperature, soaking time, core stimulation, number of cycles, shale particle size, and carbon dioxide phase during the cycling carbon dioxide injection. The carbon dioxide supercritical phase has reached the maximum recovery factor of 40%. When carbon dioxide is in the supercritical phase, its density will become lower than the liquid phase due to the high pressure. Therefore, the oil recovery factor has been increased in micro and nanopores. It is concluded that more than 12 h of carbon dioxide soaking would not play a significant role in oil recovery enhancement. It was observed that each shale particle size distribution would be a proper representative for the carbon dioxide adsorption calculation. Therefore, by doing this, the required time to equilibrate pressure for carbon dioxide adsorption would be decreased by pulverizing the shale cores into micro and nanoparticles. In higher temperatures, carbon dioxide helps to retrograde vaporize hydrocarbon liquid as carbon dioxide provided a higher gas–oil ratio (GOR), higher value of condensate oil density. Thereby, due to increased carbon dioxide content, oil recovery has been increased, indicating that carbon dioxide would be properly soluble. Therefore, at 120 °C, the oil recovery factor has the highest value of 64%. At 3000 psi, the oil recovery factor has the highest value, and it has reached 60% after 14 cycles of carbon dioxide injection. It would be related to the more surface area of carbon dioxide with shale matrixes. Finally, temperature increase would reduce the carbon dioxide absorption, which has a reverse pattern with oil recovery factor increase by the temperature increase.