A mixture theory approach to model co- and counter-current two-phase flow in porous media accounting for viscous coupling

It is well known that relative permeabilities can depend on the flow configuration and they are commonly lower during counter-current flow as compared to co-current flow. Conventional models must deal with this by manually changing the relative permeability curves depending on the observed flow regime. In this paper we use a novel two-phase momentum-equation-approach based on general mixture theory to generate effective relative permeabilities where this dependence (and others) is automatically captured. In particular, this formulation includes two viscous coupling effects: (i) Viscous drag between the flowing phases and the stagnant porous rock; (ii) viscous drag caused by momentum transfer between the flowing phases. The resulting generalized model will predict that during co-current flow the faster moving fluid accelerates the slow fluid, but is itself decelerated, while for counter-current flow they are both decelerated. The implications of these mechanisms are demonstrated by investigating recovery of oil from a matrix block surrounded by water due to a combination of gravity drainage and spontaneous imbibition, a situation highly relevant for naturally fractured reservoirs. We implement relative permeability data obtained experimentally through co-current flooding experiments and then explore the model behavior for different flow cases ranging from counter-current dominated to co-current dominated. In particular, it is demonstrated how the proposed model seems to offer some possible interesting improvements over conventional modeling by providing generalized mobility functions that automatically are able to capture more correctly different flow regimes for one and the same parameter set.