Influence of Clay Wettability Alteration on Relative Permeability

Abstract

Understanding the wettability of porous materials is important to model fluid flow in the subsurface. One of the critical factors that influences wetting in real reservoirs is the composition of geologic materials. The wetting properties for clay minerals can have a particularly strong impact on flow and transport. In this work, we analyze the chemical composition of a Mt. Simon sandstone core to resolve the microscopic structure of clay regions and assess how alterations to the local wetting properties influence multiphase transport based on core flooding experiments and relative permeability simulations. We show that whichever fluid has greater affinity toward clay minerals will tend to accumulate within these high surface area regions, leading to dramatic shifts in the relative permeability. This work establishes the essential importance of the mineral composition and associated wetting properties in the modeling of flow and transport in reservoir-scale systems. Plain Language Summary Surface interactions between fluid and solid materials have important consequences for underground fluid flow. Wettability refers to the relative preference for one fluid to coat the solid surface when multiple fluids are present. Exposure to different fluids can dramatically alter the wettability for mineral surfaces in geological systems, which can have a significant effect on multiphase flow in geological reservoirs. We show that alteration of the wetting properties for clay regions can dramatically alter the behavior for water and CO 2 to flow through reservoir rocks. The underlying causes for these effects are understood by examining microscopic fluid configurations obtained based on the composition of geologic materials. A deeper comprehension of CO 2 flow and transport behavior in a reservoir rock with high mineralogical heterogeneities will aid the CO 2 storage capacity prediction and reduce CO 2 leakage potential.

The Impact of Sub-Resolution Porosity on Numerical Simulations of Multiphase Flow

“…Alternatively, if water flows predominantly in the open pore space, surface contact angles should have relatively minor impact on relative permeability to water because of the competing effects noted above in the case of oil. In fact, an increase in water relative permeability with θ (opposite to that observed here) was reported by Fan et al (2020). A possible explanation of our results is that residual water flow in our simulated system relies on the combination of SRP and residual macropore water flow (previous studies have largely ignored the presence of SRP).…”

“…In these cases, SRP can impact permeability by a factor larger than 2 even when contributing only ∼2% of the total porosity (Churcher et al, 1991;Tanino and Blunt, 2012;Wu et al, 2019). In addition, recent evidence suggests that SRP also can have important impacts on multiphase flow, as shown by observations of dramatic changes in relative permeability curves and overall flow behaviour associated with differences in SRP wetting properties in mixed-wet or strongly-wetting rocks (Zou et al, 2018;Rücker et al, 2019;Fan et al, 2020;Garfi et al, 2020).…”

Evolution of Bentheimer Sandstone Wettability During Cyclic scCO2‐Brine Injections

“…In a more recent study, Ge et al (2022) also found that fines migration increased residual saturation of scCO 2 ; the authors attribute this effect also to pore throat blockage. Even in the absence of fines migration, the wettability of clay minerals can have a significant impact on relative permeability endpoints and subsequent trapping of scCO 2 (Fan et al, 2020). The Bentheimer sandstone cores investigated by Herring et al (2016) and further herein are largely comprised of quartz, but are unfired with K-feldspar and kaolinite present; so there is potential for clays to influence flow, and for fines migration (especially with respect to kaolinite) to occur.…”

Multiscale Characterization of Wettability in Porous Media

“…Recent micromodel experiments have also shown that displacement flow regimes are directly influenced by the spatial distribution of surface wettability (Zhao et al 2016). Various other works have also shown the importance of the wetting state when conducting core flooding experiments (Akai et al 2018, Zou et al 2018, Liu et al 2018 or numerical simulations (Fan et al 2020, Murison et al 2014, Singh et al 2019, Foroughi et al 2020.…”

“…There are no simple rules that quantify the wide range of observed relative permeability behaviors despite great efforts to find them (Blunt 2017). Experimental and simulation data often provide conflicting results, such as trends of residual oil saturation and endpoint relative permeability versus wettability (Fan et al 2020, Christensen and Tanino 2019, Jadhunandan and Morrow 1995. While relative permeability behavior is broadly understood as being dependent on surface wetting properties, pore structure, and residual fluid morphology, tools for quantifying these properties to an adequate level of detail have only recently become available.…”