Factors That Affect Gas-Condensate Relative Permeability

Abstract

When the pressure in a gas-condensate reservoir falls below the dewpoint, 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 were conducted on reservoir rock at a variety of conditions. The goal was to determine the sensitivity to interfacial tension (IFT) (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 IFT sensitivity that is similar to that reported by other researchers. For obtaining relative permeability data that are applicable to a specific reservoir, we conclude that laboratory measurements must 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.

A Model for Relative Permeabilities Under Gas Liberation or Condensate Precipitation in Porous Medium

“…The bubbles form an immobile gas phase, which plugs the separate paths for oil, and the relative permeability for oil is correspondingly reduced. Similarly, if the pressure falls below the dew point underproduction of a gas-condensate reservoir, the precipitated condensate droplets may form an immobile liquid phase plugging the gas flow (Kalla et al, 2014). Reduction of permeability may be rather significant (Pope et al, 1998) and should somehow be accounted for in the models for relative permeabilities.…”

A proposed capillary number dependent model for prediction of relative permeability in gas condensate reservoirs: a robust non-linear regression analysis

“…The immensity of the viscous forces is set by the fluid viscosity, flow velocity, and flow path length (Fulcher et al, 1985). It has been widely accepted that the foregoing connection between the IFT and k r /S r becomes momentous when the IFT is lower than its critical (base) value (IFT b ) (Asar and Handy, 1988;Kalla et al, 2014;Longeron, 1980). Additionally, many researchers have been confirmed experimentally that relative permeability of the gas condensate fluids (in particular for the gas phase) increase with the velocity at low/moderate flow velocities (Henderson et al, 1997(Henderson et al, , 2000aJamiolahmady et al, 2008;Mott et al, 1999).…”

Development and Applications of a Compositional Pore-Network Model for Gas-Condensate Flow

“…This means that, at a given gas relative permeability, condensate relative permeabilities are lower for the reservoir fluids than for the model fluids, which indicates higher liquid accumulation in porous media. Kalla et al [49] also compared the use of reservoir and model fluids during the experimental measurements of relative permeabilities of gas and condensate. In their findings, both k rg and k rc were higher for reservoir fluids than for model fluids, at a given saturation and interfacial tension.…”