To date, numerous studies have shown that “smart water” flooding can enhance the oil recovery of carbonate reservoirs by altering the rock wettability. In particular, the Ca2+, Mg2+, and SO4 2– ions in smart water play important roles in altering the wettability of carbonate rocks, although their symbiotic effects are still under debate. In this study, we employ both macro- and microscopic methods, including ζ-potential measurements, contact angle measurements, and micro X-ray computed tomography (μ-CT) scanning to examine the effects of several “smart waters”, e.g., increasing SO4 2– concentrations or decreasing Ca2+ and Mg2+ concentrations in seawater, in changing the wettability of Austin chalk. ζ-potential results confirm that the surface potentials of chalk samples become more negative in smart waters than in seawater. Contact angle results suggest that smart waters are more effective in making the chalk surface more water-wet than seawater. However, seawater with four times the SO4 2– concentration (SW4SO) and seawater with one-fourth of the Ca2+ concentration (SW0.25Ca) show more potential in enhancing the alteration of chalk wettability compared to other smart waters. The μ-CT images offer a microscopic view of the fluid distribution in the porous media of chalk samples after flooding with seawater and followed by SW4SO or SW0.25Ca, which shows that SW4SO contributes to the increase in water-wetness in nanopores (or subscale porous structure), whereas SW0.25 contributes to the increase in water-wetness in micropores. In addition, the “effective contact angles” of chalk samples decreases approximately 10° after SW4SO and SW0.25Ca flooding, resulting in an increase in the “microscopic oil recovery” by 18.6 and 20.2%, respectively. Thus, this result suggests that SW0.25Ca is more effective in enhancing the water-wetness of chalk samples than SW4SO.

Advances in high-resolution micro computed tomography (micro-CT) allow obtaining high-quality rock images with a resolution of up to a few micrometres. Novel direct numerical simulation methods provide the opportunity to precisely predict the flow properties in the resolved pore space. However, a large fraction of porosity lies below the resolution of modern micro-CT scanners. These, so called, micro-pores may significantly affect the physics of flow in geologically complex dual-porosity heterogeneous formations (carbonates, shales, and coals) and are currently not accounted for in traditional micro-CT based simulations. In this work, we have employed a multiphase multi-scale Darcy-Brinkman approach to simulate immiscible two-phase flow in a hybrid system containing both macro-porous solid-free regions and a micro-porous permeable matrix. This approach solves the Navier-Stokes based volume of fluid equations system in macro-pores and accounts for multiphase Darcy equations in micro-porous regions. By combining available information on micro-porosity with relative permeability curves estimated from the synthetically generated image with both macro- and micro-porous regions fully resolved, we solve the inverse problem to account for micro-porous contribution in our Darcy-Brinkman simulation. This approach allows us to estimate relative-permeability curves in the micro-porous region and correct the multi-scale simulation so it coincides with the data from the fully-resolved image. As a result, we were able to account for the impact of micro-porosity on the residual saturation and correct the shape of relative permeability curves and their end-points in the micro-porous domain. The proposed approach provides a workflow which can be used to history-match the Darcy-Brinkman pore-scale simulation with core-scale petrophysical data with respect to the relative permeability. Thus, it is possible to account for heterogeneity in complex rock formations by incorporating the whole range of porosity. The inclusion of micro-porosity in pore-scale image-based simulations for predicting relative permeability curves may help in a more reliable modelling and estimation of filed-scale subsurface flows, production profiles, recoverable reserves and carbon capture and storage mechanisms.

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Ion-tuned waterflooding is a novel enhanced oil recovery method that involves modifying the ionic composition of the injected water (sea) to change the wetting properties of reservoir rocks. Currently, there is, however, no agreement among researchers on the mechanisms of the ion-tuned effect (ITE). In this study, we have conducted a pore-scale study to directly visualize the changes in oil recovery and contact angle alteration in carbonate rock samples. This was achieved by completing a series of core-flooding experiments with alternated ion composition of brines and micro-CT imaging. In addition, these results were correlated with macro- and nanoscale measurements represented by sessile-drop contact angle and DLVO-based contact angle calculation. The results show that, for both ways, either an increase or a decrease in the calcium concentration in the injected water leads to an increase in water wettability and, therefore, increased recovery. When comparing the evidence among the studies of macro-, pore-, and nanoscales, it becomes clear that electrical double-layer expansion is a dominant mechanism at a low calcium concentration, while surface ion exchange is due primarily to a high calcium concentration. It is also noteworthy that plain seawater is proven to be an effective wettability-altering agent for carbonates.

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