Modelling the effect of wettability distributions on oil recovery from microporous carbonate reservoirs

Carbonate-hosted hydrocarbon reservoirs are often weakly- to moderately oil-wet. Such wettability states are reached after oil migration through a series of chemical processes which are only understood in outline even though wettability is fundamental to prediction of multi-phase flow behaviour. Modelling the pore-scale wettability features of carbonates using pore-network models is challenging due to both our inability to incorporate appropriate chemical characteristics to the pore surfaces as well as the over-simplification of pore shapes which are known to be highly complex, particularly where micropores are an important part of the pore network. Indeed, the role of micropores on fluid flow has often been neglected, as has their wettability state, since they are usually assumed to be water-wet. Here, we implement a qualitatively plausible wettability alteration scenario in a developed two-phase flow network model that captures a great diversity of complex pore shapes. This developed model qualitatively reproduces patterns of wettability alteration recently observed in microporous carbonates via high-resolution imaging. In order to assess the combined importance of both pore space structure and wettability distribution on petrophysical properties, we consider two dissimilar pore networks: a homogeneous Berea sandstone network and a heterogeneous and multiscale carbonate network whose disconnected macropores are connected through a sub-network of micropores. Results demonstrate that wettability effects are significantly more profound in the carbonate network model, as the wettability state of the micropores controls the oil recovery efficiency.