Multi-scale Pore-network Modelling of WAG in Carbonates

Carbonate reservoirs have textural heterogeneities at all length-scales (triple porosity: pore-vug-fracture) and tend to be mixed- to oil-wet. The choice of an enhanced oil recovery process and the prediction of oil recovery require a sound understanding of the fundamental controls on fluid flow in mixed- to oil-wet carbonate rocks, as well as physically robust flow functions, i.e. relative permeability and capillary pressure functions. Obtaining these flow functions is a challenging task, especially when three fluid phases coexist, such as during water-alternating-gas injection (WAG). We have recently developed a method for integration of pore-networks derived from micro CT images at different length-scales, thus capturing pore structures from different types of porosity. The network integration method honours the connectivity between different pore types, including micro-fractures, and their spatial distribution. In this work, we use these multi-scale networks as input for our three-phase flow pore-network model, which comprises a novel thermodynamic criterion for formation and collapse of oil layers that strongly depends on the fluid spreading behaviour and the rock wettability. The criterion affects in particular the oil relative permeability at low oil saturations and the accurate prediction of residual oil saturations. We generate three-phase flow functions for gas injection and WAG from networks with carbonate pore geometries and connectivities and we demonstrate the impact on residual saturations of the different types of porosity and the interaction with different realistic wettability scenarios. We also show that the network generated three-phase flow relative permeabilities are distinctly different from traditional models, such as Stone’s. The flow functions will be used in a heterogeneous carbonate reservoir model and to demonstrate their impact on the sweep efficiency.