Gas condensate reservoirs constitute a significant portion of hydrocarbon reserves worldwide. The liquid drop-out in these reservoirs may lead to recovery problems such as near wellbore permeability impairment and uncertainty in the actual location of the target condensate. Such technical issues can be addressed through improved understanding of the formation of condensate and the multiphase flow of gas/condensate/water in the reservoir as characterized by relative permeability curves. The appropriate relative permeability curves in turn can be used in reservoir simulators to assist in optimization of field development. This paper reports results of experiments conducted in micromodels, in support of possible core flow tests, using reservoir fluids under reservoir conditions. In particular, visualizations of condensate formation with and without connate water are presented and the differences between the two cases as well as the possible implications for the relative permeability measurements are discussed. Furthermore, the flow of gas and condensate at different force ratios (capillary and Bond numbers) are presented. It is postulated that a single dimensionless number may not be sufficient to characterize the multiphase flow in gas condensate reservoirs. The physical mechanisms occurring under various field conditions are examined in the light of these observations.