Abstract
Three-phase relative permeabilities have an important role in numerical simulation of oil recovery processes. Thermal methods for heavy oil recovery, such as steam injection and in situ combustion, involve simultaneous flow of oil, water and gas at high temperatures. A knowledge of three-phase relative permeabilities at elevated temperatures is required to predict performance of these processes by reservoir simulation studies. Measurements of three-phase relative permeabilities for heavy oil systems at elevated temperatures have been unavailable due to experimental difficulties.
The objectives of this work were to develop an experimental apparatus for measuring three-phase relative permeabilities at elevated temperatures and pressures and to carry out such measurements in a model system. The rock-fluid system used in these measurements comprised Ottawa sand - refined mineral oil - distilled water - nitrogen gas. A high viscosity mineral oil (405 mPa.s at 23°C) was selected to simulate heavy oil behaviour. The measurements were carried out at 100°C temperature and 3.5 MPa pressure. Two-and three-phase relative permeability measurements were obtained using the steady-state technique. A large number of steady-state tests were carried out to completely define the three-phase relative permeability characteristics in two types of saturation histories; (1) water and gas saturations increasing and oil saturation decreasing, (2) water and gas saturation decreasing, oil saturation increasing.
The three-phase water relative permeability was found to be a function of water saturation only and did not change with the direction of saturation change. The gas relative permeability was also a function of its own saturation only. It was lower in the direction of decreasing gas saturation. The oil relative permeability was found to vary with saturations of the other fluids. Oil isoperms were concave towards the oil apex.
