Predicting production from gas-condensate wells requires an accurate relative permeability model when a condensate bank forms. At high flow rates typical of many gas-condensate wells, the relative permeability is rate dependent. Such rate dependence can be modeled using a capillary number to calculate the decrease in residual saturations and the corresponding increase in relative permeability as viscous forces become dominant over the interfacial forces. New steady-state relative permeability data have been measured over a wide range of capillary numbers including very high values corresponding to the near-well region.  These measurements have been made on several reservoir rocks as well as outcrop rocks and over a range of temperature, pressure, connate water saturation and hydrocarbon composition typical of gas-condensate reservoirs. PVT data of gas-condensate fluids can be used to predict the ratio of the gas to the condensate relative permeability and this simplifies the measurements and modeling since only data corresponding to the pressures near wells are needed.  A relative permeability model developed at the University of Texas was tested using both new data and data from the literature. With only one parameter set, essentially all of the data for all rocks and conditions was fit within experimental uncertainty.