Abstract The fluid transfer parameters between matrix and fracture are not well known. Consequently, simulation of fractured reservoirs uses, in general, very crude and unproved hypothesis such as zero capillary pressure in the fracture and/or relative permeability functions that are linear with saturation. In order to improve the understanding of flow in fractured media, an experimental study was conducted and numerical simulation used to interpret experimental results. A laboratory flow apparatus was built to obtain data on water-air imbibition and oil-water drainage displacements in fractured sandstone systems. During the experiments, porosity and saturation were measured along the core utilizing a Computerized Tomography (CT) scanner. Saturation images were reconstructed in 3-D to observe how matrix-fracture interaction occurred. Differences in fluid saturations and relative permeabilities caused by changes of fracture width have also been analyzed. In the case of water-air imbibition, fracture systems with narrower fracture apertures showed more stable fronts and slower water breakthrough than the wide fracture systems. However, the final water saturation was higher in wide fracture systems, thus showing that capillary pressure in the narrow fracture has more effect on fluid distribution in the matrix. During oil-water drainage, oil saturations were higher in the blocks near the thin fracture, again showing the effect of fracture capillary pressure. Oil fingering was observed in the wide fracture. Fine-grid simulations of the experiments using a commercial reservoir simulator were performed. Relative permeability and capillary pressure curves were obtained by history matching the experiments. The results showed that the assumption of fracture relative permeability equal to phase saturation is incorrect. We found that both capillary and viscous forces affect the process. The matrix capillary pressure obtained by matching an experiment showed lower values than reported in the literature.