Carbonate-hosted hydrocarbon reservoirs are known to be weakly-to moderately oil-wet, but the pore-scale wettability distribution is poorly understood. Moreover, micropores, which often dominate in carbonate reservoirs, are usually assumed to be water-wet and their role in multi-phase flow is neglected. Modelling the wettability of carbonates using pore network models is challenging, because of our inability to attribute appropriate chemical characteristics to the pore surfaces and oversimplification of the pore shapes. Here, we implement a qualitatively plausible wettability alteration scenario in a two-phase flow network model that captures a diversity of pore shapes. The model qualitatively reproduces patterns of wettability alteration recently observed in microporous carbonates via high-resolution imaging. To assess the combined importance of pore-space structure and wettability on petrophysical properties, we consider a homogeneous Berea sandstone network and a heterogeneous microporous carbonate network, whose disconnected coarse-scale pores are connected through a sub-network of fine-scale pores. Results demonstrate that wettability effects are significantly more profound in the carbonate network, as the wettability state of the micropores controls the oil recovery.

project BG Group, Chevron, Dong Energy and Wintershall for funding and for permission to publish this work. We thank the Edinburgh Parallel Computing Centre (EPCC) for allowing access to the BGQ machine and computational time. Kevin Stratford acknowledges support from UK EPSRC grant EP/J007404.

While carbonate reservoirs are recognized to be weakly‐to‐moderately oil‐wet at the core‐scale, pore‐scale wettability distributions remain poorly understood. In particular, the wetting state of micropores (pores <5 µm in radius) is crucial for assessing multiphase flow processes, as microporosity can determine overall pore‐space connectivity. While oil‐wet micropores are plausible, it is unclear how this may have occurred without invoking excessively high capillary pressures. Here we develop a novel mechanistic wettability alteration scenario that evolves during primary drainage, involving the release of small polar non‐hydrocarbon compounds from the oil‐phase into the water‐phase. We implement a diffusion/adsorption model for these compounds that triggers a wettability alteration from initially water‐wet to intermediate‐wet conditions. This mechanism is incorporated in a quasi‐static pore‐network model to which we add a notional time‐dependency of the quasi‐static invasion percolation mechanism. The model qualitatively reproduces experimental observations where an early rapid wettability alteration involving these small polar species occurred during primary drainage. Interestingly, we could invoke clear differences in the primary drainage patterns by varying both the extent of wettability alteration and the balance between the processes of oil invasion and wetting change. Combined, these parameters dictate the initial water saturation for waterflooding. Indeed, under conditions where oil invasion is slow compared to a fast and relatively strong wetting change, the model results in significant non‐zero water saturations. However, for relatively fast oil invasion or small wetting changes, the model allows higher oil saturations at fixed maximum capillary pressures, and invasion of micropores at moderate capillary pressures.

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