Abstract
Liquid banking in the near wellbore region can lessen significantly the production from gas reservoirs. As reservoir rocks commonly consist of liquid-wet porous media, they are prone to liquid trapping following well liquid invasion and/or condensate dropout in gas-condensate systems. For this reason, wettability alteration from liquid to gas-wet has been investigated in the past two decades as a permanent gas flow enhancement solution. Numerous experiments suggest flow improvement for immiscible gas-liquid flow in wettability altered cores. However, due to experimental limitations, few studies evaluate the method’s performance for condensing flows, typical of gas-condensate reservoirs. In this context, we present a compositional pore-network model for gas-condensate flow under variable wetting conditions. Different condensate modes and flow patterns based on experimental observations were implemented in the model so that the effects of wettability on condensing flow were represented. Flow analyses under several thermodynamic conditions and flow rates in a sandstone based network were conducted to determine the parameters affecting condensate blockage mitigation by wettability alteration. Relative permeability curves and impacts factors were calculated for gas flowing velocities between 7.5 and 150 m/day, contact angles between 45° and 135°, and condensate saturations up to 35%. Significantly different relative permeability curves were obtained for contrasting wettability media and impact factors below one were found at low flowing velocities in preferentially gas-wet cases. Results exhibited similar trends observed in coreflooding experiments and windows of optimal flow enhancement through wettability alteration were identified.