Significant productivity loss occurs in gas-condensate wells when the bottom hole flowing pressure drops below the dewpoint pressure. The decline in productivity is due to near-well accumulation of condensate in the reservoir rock, which is significant even for wells producing very lean gas with liquid dropout values less than 1%. Many different methods such as hydraulic fracturing, dry gas injection and solvent injection have been proposed and implemented to stimulate such wells. However, all of these methods offer short-lived stimulation and are sometimes not profitable. New experimental core flooding data using chemical treatments show that the steady-state gas and condensate relative permeability in both outcrop and reservoir sandstones can be increased by a factor of 2 to 3 over a wide range of temperature (145 to 275 °F). Spectroscopic data show that the sandstone surface remains modified by the chemical even after flooding the core with large volumes of gas. A relative permeability model that includes effects such as the decrease in the residual condensate saturation after treatment and the effect of capillary number is presented. Fine-grid compositional simulations of a single-well treatment were done using the calibrated relative permeability model to investigate the performance of chemical treatments under field conditions as a function of variables such as treatment radius. These simulations show that chemical treatments have the potential to greatly increase production at low cost relative to the increased revenue since only the near-well region blocked by the condensate needs to be treated.