. This means that relative permeability of oil is a function of its saturation only. This observation is consistent with what other people have seen. Also, the water relative permeability was lowered by the trapped gas, showing the interaction between the two nonwetting fluids.
Schneider et al. also reported that the flow behavior of the uniform porosity carbonate samples tested was similar to that of consolidated sandstones. Thus rock type does not seem to influence the flow relationships other than through its wetting preference. However, due to the surface minerals most of the time carbonate rocks are oil wet, while sandstones are usually water wet. Also, carbonates usually have vugs. When large vugs exist in the reservoir, the core sample used in the experiment might not be representative of the reservoir. When laboratory data of carbonates is being used to predict three-phase flow, a greater uncertainly has been added. Also, most of the relative permeability models were derived from the assumption that the medium if water wet. Attention must be paid to the assumptions of the model to select the appropriate one for carbonates.
It is expected that IFT will affect relative permeability and recovery in the same way regardless of the rock properties since IFT is a fluid property. The effects of temperature on relative permeability in carbonates have not been reported in literature. It can be expected that a change in temperature will change the characteristics of relative permeability of fluids in carbonates. However, no data is available to identify what those changes are. Again, nothing can be said about the effects of flow rate and viscosity on the flow of fluids in carbonates since there is no data available.
 Schneider, F.N. and Owens, W.W., “Sandstone and Carbonate Two- and Three-Phase Relative Permeability Characteristics”, Trans., AIME (1970) 249, 75-84.
If you have any questions at all, please feel free to ask PERM! We are here to help the community.