Factors That Affect Gas-Condensate Relative Permeability

Abstract

Abstract When the pressure in a gas condensate reservoir falls below the dew point, liquid condensate can accumulate in the pore space of the rock. This can reduce well deliverability and potentially affect the compositions of the produced fluids. Forecasting these effects requires relative permeability data for gas-condensate flow in the rock in the presence of immobile water saturation. In this study, relative permeability measurements have been conducted on reservoir rock at a variety of conditions. The goal has been to determine the sensitivity to interfacial tension (which varies with pressure) and fluid type (reservoir fluids, pure hydrocarbons, and water). The results show a significant sensitivity to fluid type, as well as an interfacial tension sensitivity that is similar to that reported by other researchers. For obtaining relative permeability data that is applicable to a specific reservoir, we conclude that laboratory measurements should be conducted at reservoir conditions with actual reservoir fluids. The measurements reported here used a state-of-the-art relative permeability apparatus of in-house design. The apparatus uses elevated temperature and pressure, precision pumps, and a sight glass with automated interface tracking. Closed-loop recirculation avoids the need for large quantities of reservoir fluids and ensures that the gas and liquid are in compositional equilibrium. Introduction Gas condensate fields are valuable resources under high natural gas prices due to expanding gas markets. They are also valuable under low gas price markets because of the produced liquids. Gas condensate reservoir development is similar to developing dry gas reservoirs with two significant differences: condensate flow in the reservoir near the wellbore and significant liquid production over the life of the reservoir. These factors influence the number of wells and the size of the surface facilities and thus importantly the project economics. Significant liquid accumulation in the pore space around the wellbore, where larger pressure drop and gas flux are encountered, affects the gas flow due to two-phase flow. High gas flux can also lead to inertial non-Darcy effects and, along with multiphase flow effects, decreases the well deliverability. The flow behavior of gas condensate reservoirs leads to increasing liquid saturation (an imbibition process) around the wellbore. This is the reverse of typical gas-oil drainage processes such as gas cap expansion and gas flooding, in which the liquid saturation decreases. Reliable prediction of gas deliverability or liquid recovery over the life of a reservoir needs reliable information on flow behavior of both gas and condensate phases through the reservoir rock.