Typical gas condensate fields contain a gas/liquid system during depletion. Such systems are difficult to model
experimentally because they exhibit near-miscible behavior at high pressure and temperature. One way to simplify laboratory
experimentation is to use a binary retrograde condensate fluid and to adjust temperature to control miscibility. A series
of relative permeability test were conducted on a moderate-permeability carbonate core using methanol/n-hexane at
near miscible conditions in the presence of immobile water. Potassium carbonate was added to the water to prevent miscibility
with methanol. The experiments used a pseudo-steady-state technique under conditions similar to the near well region
of a carbonate gas-condensate reservoir. The flow of gas and condensate at different force ratios was investigated.
Relative permeabilities were obtained by matching historical production and pressure data using a coreflood simulator. It
was observed that relative permeability depended on fluid composition and flow rate as well as initial condensate and water
saturations. As the wetting phase (condensate) flow rate increased or interfacial tension decreased, relative permeability
versus wetting phase saturation curves shifted towards lower wetting phase saturations. It was found that a simple
three-parameter mathematical model that depends on a new dimensionless number called condensate number successfully
modeled the gas-condensate relative permeability data. The developed model resulted in a good agreement with published
gas-condensate relative permeability data as well as end point relative permeabilities and saturations. The relative permeability
behavior as a function of IFT highly resembles the one observed in sandstones.