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Modelling Wettability Alteration in Microporous Carbonate Rocks


Understanding the wettability of a rock is essential to optimise oil recovery. The wetting behaviour of a system from pore to pore is difficult to assess since no accurate measurement technique is available. In fact, the commonly used classification system for mixed-wettability states, exclusively correlated with pore size (mixed-wet small, mixed-wet large and fractionally wet), is found to be insufficient to describe complex wettability configurations. Particularly, microporous carbonates display a highly unpredictable distribution of wettability due to the heterogeneity of their multi-scale pore space. Indeed, the presence of microporosity (pores that are >10μm in diameter) adds complexity to the task since its wetting characteristics have been largely unknown. Nonetheless, recent experimental results from Marathe et al. (2012) suggested the existence of a unifying pattern of wettability on micrite particles that may simplify the modelling of wettability in carbonate rocks. In this paper, we modelled the physically-based wettability alteration mechanism based on the tightly correlated concepts of disjoining pressure and thin-films collapse. We incorporated the model into an existing state-of-the-art two-phase flow network model, and were able to reproduce the pore-scale wettability trends observed from experimental FESEM images. For the obtained wettability distribution, we checked the connectivity of the oil-wet fraction. We further presented capillary pressure and relative permeability curves during drainage and imbibition, and analysed the pore filling behaviour.