Pore-Scale Network Modelling of Waterflood Residual Oil Recovery by Immiscible Gas Flooding

Abstract

Abstract The paper presents a precise description of the pore-scale displacement mechanisms responsible for the mobilization and subsequent recovery of waterflood residual oil by immiscible gas flooding. The displacement mechanisms are incorporated into a numerical three-phase invasion percolation type network model which is used to compute oil recoveries by tertiary gas flooding for oil-water-gas systems displaying positive and negative spreading behaviour under strongly water wet conditions. Computed oil recoveries are shown to be in good agreement with those observed in micromodel displacement experiments. The network model confirms the important role of oil spreading fihus in increasing recovery of waterflood residual oil for positive spreading systems. Introduction The recovery of waterflood residual oil by immiscible gas flooding is increasingly being viewed as an improved oil recovery process, particularly under conditions where gravity drainage is important. Although a number of recent laboratory studies have demonstrated that gas injection can lead to high oil recovery, little is currently understood of the basic three-phase gas-oil-water displacement mechanisms responsible for the mobilization of waterflood residual oil, or of the factors influencing the pore-scale processes responsible for the improved oil recovery. An understanding of these processes is necessary both for the development of improved gas flooding applications and for predicting phase mobilities in regions of the reservoir where oil, water and gas flow simultaneously. Macroscopic multi-phase flow in porous media is usually described in terms of Darcy's law and measured saturation dependent relationships for phase relative permeabilities and capillary pressures. For three-phase flow these relationships are extremely difficult to determine experimentally, and three-phase behaviour is almost always estimated from two-phase saturation dependent data on the basis of empirical models similar to the model first proposed by Leverett and later extended by others. The empirical nature of these models constitutes a major deficiency in the present theory for three-phase flow in porous media and limits the ability of reservoir simulators to accurately predict oil recoveries by tertiary gas flooding. In principle, it is not necessary to actually measure two-phase or three-phase relative permeability and capillary pressure data since it is possible to determine these by appropriately averaging the equations describing the physical processes occurring on the pore-scale. This approach requires a detailed understanding of the displacement mechanisms on the pore-scale and a complete description of the morphology of the pore space. P. 345^