Book excerpt: Compositional reservoir simulation studies were performed to investigate the effect of uncertain reservoir parameters, flood design variables, and economic factors on coupled CO2 sequestration and EOR projects. Typical sandstone and carbonate reservoir properties were used to build generic reservoir models. A large number of simulations were needed to quantify the impact of all these factors and their corresponding uncertainties taking into account various combinations of the factors. The design of experiment method along with response surface methodology and Monte-Carlo simulations were utilized to maximize the information gained from each uncertainty analysis. The two objective functions were project profit in the form of $/bbl of oil produced and sequestered amount of CO2 in the reservoir. The optimized values for all objective functions predicted by design of experiment and the response surface method were found to be close to the values obtained by the simulation study, but with only a small fraction of the computational time. After the statistical analysis of the simulation results, the most to least influential factors for maximizing both profit and amount of stored CO2 are the produced gas oil ratio constraint, production and injection well types, and well spacing. For WAG injection scenarios, the Dykstra-Parsons coefficient and combinations of WAG ratio and slug size are important parameters. Also for a CO2 flood, no significant reduction of profit occurred when only the storage of CO2 was maximized. In terms of the economic parameters, it was demonstrated that the oil price dominates the CO2 EOR and storage. This study showed that sandstone reservoirs have higher probability of need for CO2i ncentives. In addition, higher CO2 credit is needed for WAG injection scenarios than continuous CO2 injection. As the second part of this study, scaling groups for miscible CO2 flooding in a three-dimensional oil reservoir were derived using inspectional analysis with special emphasis on the equations related to phase behavior. Some of these scaling groups were used to develop a new MMP correlation. This correlation was compared with published correlations using a wide range of reservoir fluids and found to give more accurate predictions of the MMP.