Carbon dioxide injection has been widely used as an EOR process, even in carbonate reservoirs with complex rock system. In order to enhance the post water flooding recovery, CO2 exposure with the remaining oil in lower zones should be maximized. This is a great challenge, as CO2 is considerably lighter than oil making gravity the dominant force. However, reservoir complexity can influence CO2 penetrating distance before a complete gravity segregation occurs. Therefore, understanding the reservoir heterogeneity and corresponding impact on oil displacement is a key to successful CO2 flooding projects. Particular focus was placed on vertical variation of oil-water capillary pressure and relative permeability curves.

This paper provides a detailed assessment of heterogeneity based oil-water capillary and relative permeability curves on ultimate oil recovery by CO2 floods. In addition, it studies the effect of CO2 vertical placement, well type, CO2 injection rate, and simultaneous CO2 and water injection on recovery. This was achieved with a numerical simulation approach using a commercial simulator, ECLIPSE. Numerous sensitivities were carried out with a conceptual 3D model undergoing water and CO2 flooding to optimize ultimate recovery at minimum cost. The investigation is based on two scenarios in which the complexity of the vertical capillary and relative permeability curves was varied.

The results from both scenarios showed consistent trend indicating that the variation in oil-water capillary and relative permeability curves can influence the oil- CO2 exposure thereby affecting the ultimate recovery. Among the considered factors, CO2 injection rate has the greatest influence on the ultimate recovery. The heterogeneity in capillary pressure and relative permeability causes CO2 to penetrate longer distance before a complete tonguing occurs. The maximum oil- CO2 exposure was achieved in the case where the highest contrast in such transport properties exists between the top zones. At higher CO2 injection rates, additional recovery gains were achieved as CO2 penetration was enhanced further by viscous force. The recovery gain increases even more with simultaneous CO2 and water injection. Moreover, results obtained from shallower water and deeper CO2 injections were encouraging. The effect of CO2 placement was found of a concern only in cases where the highest capillary pressures exist in the top zones. Limited effect was observed by the well type, thus injection of CO2 in shallower layers in vertical wells could be a cost effective option. The ultimate oil recovery for both scenarios post-optimization has increased remarkably compared to water flooding and CO2 pre-optimization cases.

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