The use of coarse scales in reservoir simulation is necessary to reduce computational time; however it can degenerate results due to loss of resolution of the small-scale phenomena, especially in oil fields in which a miscible gas is injected in an enhanced oil recovery method. Errors of the upscaling process are usually mitigated with the use of pseudo relative permeability curves. In cases of miscible gas injection, these techniques cannot be used directly, since there is no saturation variation. Therefore, the proposed methodology is based on employing a fluid model with a minimum miscibility pressure (MMP) above experimental values in order to ensure an immiscible displacement. This solution does not violate the phase behavior and ensures formation of two hydrocarbon phases in the reservoir. Therefore, the gas relative permeability plays a role in the simulation results and can be used to better fit the refined model production curves. In this study, problems that occur when upscaling is applied in various levels of refinement, from fine-scale grid (necessary to preserve geological characteristics) to simulation grid (necessary to preserve flow characteristics) in large fields with miscible gas injection were investigated. As expected, (1) simulations in coarser scales were not able to represent small-scale phenomena and (2) an increased numerical dispersion effect was observed and evaluated with higher order numerical schemes. An alternative solution to better reproduce small-scale production curves using a coarser scale model and a modified fluid model is proposed.