Three-phase relative permeabilities and capillary pressures are extremely difficult to determine experimentally so they are commonly estimated using empirical models by extrapolating from two phase flow-saturation data where the third phase is at irreducible conditions, or not even present. This paper demonstrates the importance of pore-scale fluid/fluid/solid interactions and shows how the pore scale events affect the core-scale displacements, particularly residual oil and flow capabilities. and why three-phase relative permeability coefficients are so difficult to determine.
At the pore-scale the fluids will adopt one of three fluid configurations depending on the spreading characteristics of the fluids and the wetting preference of the solid. The pore-scale level configurations and mechanisms can then be linked to the flow behaviour modes at the core scale. A the core scale there are various stages of displacement which can be described in zones. The nature of the core-scale displacement mechanisms is determined in part by the pore-scale configuration and the displacing phase/s characteristics (wetting/non-wetting, spreading/non-spreading) as well as the flow mode in a particular zone. In total 25 different modes may occur. In this paper the related up-scaled core displacement processes and the 3-phase displacements and flow modes are identified by many examples. The relevance to the application for 3-phase relative permeabilities and reservoir simulation is also discussed.
During oil recovery operations there are many instances when three phases (oil, gas and water) are present and flow within the pore structure of the reservoir; examples include solution gas drive, water flooding below bubble point, depressurisation and gas injection of waterflooded reservoirs, multi-contact miscible and water-alternate-gas (WAG) processes, condensate reservoir depletion below the dew point and foam, etc.
For reservoir engineering purposes multi-phase flow through porous media is usually described in terms of continuum mechanics in the form of Darcy's equation and saturation dependent relative permeabilities. When three phases flow through a porous rock, the overall flow characteristics of each of the phases are determined by the complex interactions of the properties of the fluids and porous media (fluid/fluid and fluid/solid interactions) and are especially dependent on the spreading and wettability characteristics of the system. A detailed understanding of these phenomena is essential in order to evaluate and predict the displacement processes. Many thousands of laboratory core displacements are conducted every year but they are mainly of the 'black box' type (only input-output parameters are measured) giving little insight into the basic physics and mechanics of the flow processes. This is because reservoir rocks are essentially opaque and the fluid flow processes cannot be seen directly, although CAT and NMR scanning procedures are becoming useful tools. However micromodel studies have given many visual insights into the pore-scale physics.
This paper examines the pore-scale physics of 3-phase fluid configurations, displacement mechanisms and flow modes identified in some of our visualisation experiments and considers the implications for scale-up to determine relative permeabilities for reservoir simulation. The physics and the factors that affect the multi-phase mobility inside porous media are especially important because they affect critical/residual saturations and gas mobilisation during migration and hydrocarbon production, particularly after gas is released at pressures below the bubble point.
