Oil fields with non-associated gas like gas condensate type stand out due to the higher added economic value associated with their energy resource: the significant amount of condensate produced, in addition to the gas itself. However, such reservoirs have a particular thermodynamic behavior, inducing changes in composition and, consequently, phase throughout the depletion production process. Under reservoir conditions, for example, the phenomenon called condensate blockage may occur, in which bridges of condensate are formed, usually in regions close to the wells, thus hindering flow and affecting gas production. In order to define the best management strategy for a project to be implemented throughout the exploitation of this type of reservoir, an important tool used by engineers is numerical simulation. The relative permeability curves are used in the simulations, especially related to the representation of the mentioned physical phenomenon. In reality, however, there is a specific limitation of representativeness of the phenomenon in the laboratory tests carried out by the industry, and the best inputs could be provided by simulations in a pore network, with models that represent its alteration as a function of changes in interfacial tension and flow velocity along the reservoir. The reproduction of a pore network flow simulation to the closest possible scale in a commercial finite difference simulation is validated. From the pore network simulation to the field scale practiced in reservoir simulations, a scale-up methodology is proposed, using an optimization process, seeking to be faithful to the original relative permeability curve, on a microporous scale, obtained by simulating phenomenologically the condensation process in the reservoir, using a model that reproduces its dependence on the velocity flow developed by the phases in a porous medium. The three relative permeability curves used were presented by comparing productivities at the field scale and the evolution of condensate saturation in regions close to the wells. The results show that the proposed methodology proves to be more faithful to the influence of condensation in the reservoir on the productivity of the wells when compared to the relative permeability curve input from the laboratory test, which presents the condensate with more mobility.