Abstract
Abstract
For heavy oil reservoirs, the oil viscosity usually varies dramatically during production processes, such as thermal process or solvent injection. This paper presents an investigation of the effect of oil viscosity on relative permeability curves for heavy oil-water systems. Unsteady-state displacement tests were conducted in sandpacks under a typical injection flow rate in a heavy oil recovery process. A series of crude oils with a wide range of viscosities were used in the measurements. Large pore volumes of water were injected to minimize the errors caused by the extrapolation of the recovery data. History matching was used to obtain the relative permeability curves, in which capillary pressure was included. It was found that, for the same injection flow rate, heavy oil-water relative permeability curves systematically shifted with oil viscosity. With increasing oil viscosity, the residual oil saturation increased and the oil and water relative permeabilities decreased at the higher water saturation range. Irreducible water saturation tended to decrease with increasing oil viscosity. Micromodel experiments were conducted to visually investigate the difference in the flow behaviour between heavy oil-water and light oil-water systems. Interacting capillary bundle models were used to analyze the impact of oil viscosity on the residual oil saturation. This work aids in the laboratory measurement and determination of the representative relative permeability curves for heavy oil-water systems, as well as in the proper use of relative permeability curves in reservoir simulation for heavy oil development.
Introduction
Heavy oil development is becoming increasingly important due to the continuous decline in conventional oil production. During improved heavy oil production processes, including both thermal and solvent processes, the oil phase viscosity usually varies because of temperature increase or dissolving of solvent in the oil. The common concept that the relative permeability is independent of fluid viscosities may be relatively appropriate for the systems of low to medium oil viscosities. However, for heavy oil-water systems, to this point, there is no sound experimental evidence to support this assumption.
The effect of fluid viscosity on relative permeability curves has been investigated extensively since the work of Leverett.[1] Dong and Dullien[2] gave a review of the effect of viscosity ratio on two-phase relative permeabilities. Generally, there are two different observations reported in the literature. One is that fluid viscosity has no effect on relative permeabilities.[3-5] The other one is that the oil relative permeability is anomalously high at low water saturation for low permeability media due to the lubricating effect of the moving water film,[6,7] and that oil permeability shows an increasing trend with increasing oil/water viscosity ratio. So far, most of the research on the effect of viscosity on relative permeability curves has involved only a low range of oil viscosities. Dullien[8] pointed out that, if one of the fluids is very viscous, the viscosity ratio is evidently a very important parameter.
The study of temperature effect on relative permeability often involves the viscosity effect. Lo and Mungan[9] measured oil-water relative permeabilities using the steady-state technique for both oil-wet and water-wet core samples at room temperature and elevated temperatures. Their results showed that, with the increase in temperature, residual oil saturation decreased, irreducible water saturation increased, and oil relative permeability increased. They attributed the change in oil relative permeability to the variation of viscosity and viscosity ratio.
The variation of residual oil saturation with increasing oil viscosity also reveals the influence of fluid viscosity on relative permeabilities. Abrams[10] conducted waterflood tests on sandstone and limestone core samples, and his results showed that the viscosity ratio exerted an influence on the residual oil saturation, which is larger for a higher oil/water viscosity ratio (µo/µw) flood. By using a two-layer glass micromodel, Tzimas et al.[11] observed that the viscosity ratio had a great influence on the residual oil saturation for a wide range of capillary numbers. For the same capillary number, the greater the oil/water viscosity ratio, the larger the residual oil saturation.