It is well documented that significant production loss can be expected when regions of a retrograde condensate reservoir fall below the dew point, leading to liquid banking around the wellbore. Several methods have been utilized in industry for quite some time that can alleviate this productivity loss for a temporary period, but the viability of permanent wettability alteration in the near-wellbore region has been steadily improving in recent years. Through these treatments, the affected zone around the wellbore can adopt a more favorable relative permeability schema than the natural liquid-wetting nature of most reservoir rocks. A simulation study of the effect of wettability alteration in retrograde condensate reservoirs was undertaken in order to understand the relative economic and total recovery benefits of strongly gas-wetting treatments and intermediate gas-wetting treatments over this undesirable natural state. A radial reservoir model was built using CMG Builder and three different retrograde condensate reservoir fluid models were created using WINPROP. Numerous simulation runs were conducted on each of the fluid-reservoir model combinations to assess the impact of absolute permeability and treatment zone wettability. Aside from these primary cases, other facets of production were examined for specific permeability-fluid combinations to understand the interplay of time step size, treatment radius and rate of return on the outcome of the simulation case. Of the 27 primary cases analyzed in this study, the intermediate gas-wetting treatment was found to be the optimal option regardless of absolute permeability or fluid composition. Treatment radius was also shown to have a significant impact on production improvement but the added cost of these larger treatments is often not worth the incremental production gains.