Search

Hypothesis: The wetting behaviour is a key property of a porous medium that controls hydraulic conductivity in multiphase flow. While many porous materials, such as hydrocarbon reservoir rocks, are initially wetted by the aqueous phase, surface active components within the non-wetting phase can alter the wetting state of the solid. Close to the saturation endpoints wetting phase fluid films of nanometre thickness impact the wetting alteration process. The properties of these films depend on the chemical characteristics of the system. Here we demonstrate that surface texture can be equally important and introduce a novel workflow to characterize the wetting state of a porous medium. Experiments: We investigated the formation of fluid films along a rock surface imaged with atomic force microscopy using zeta-potential measurements and a computational model for drainage. The results were compared to spontaneous imbibition test to link sub-pore-scale and core-scale wetting characteristics of the rock. Findings: The results show a dependency between surface coverage by oil, which controls the wetting alteration, and the macroscopic wetting response. The surface-area coverage is dependent on the capillary pressure applied during primary drainage. Close to the saturation endpoint, where the change in saturation was minor, the oil-solid contact changed more than 80%. (C) 2019 The Authors. Published by Elsevier Inc.

Hypothesis: The macroscopic movement of subsurface fluids involved in CO2 storage, groundwater, and petroleum engineering applications is controlled by interfacial forces in the pores of rocks. Recent advances in modelling these systems has arisen from approaches simulating flow through a digital representation of the complex pore structure. However, further progress is limited by difficulties in characterising the spatial distribution of the wetting state within the pore structure. In this work, we show how observations of the fluid coverage of mineral surfaces within the pores of rocks can be used as the basis for a quantitative 3D characterisation of heterogeneous wetting states throughout rock pore structures. Experiments: We demonstrate the approach with water–oil fluid pairs on rocks with distinct lithologies (sandstone and carbonate) and wetting states (hydrophilic, intermediate wetting, and heterogeneously wetting). Findings: Fluid surface coverage the within rock pores is a robust signal of the wetting state across varying rock types and wetting states. The wetting state can be quantified and the resulting 3D maps can be used as a deterministic input to pore scale models. These may be applied to multiphase flow problems in porous media ranging from soil science to fuel cells.

Hypothesis Emerging energy-related technologies deal with multiscale hierarchical structures, intricate surface morphology, non-axisymmetric interfaces, and complex contact lines where wetting is difficult to quantify with classical methods. We hypothesise that a universal description of wetting on multiscale surfaces can be developed by using integral geometry coupled to thermodynamic laws. The proposed approach separates the different hierarchy levels of physical description from the thermodynamic description, allowing for a universal description of wetting on multiscale surfaces. Theory and Simulations The theoretical framework is presented followed by application to limiting cases of wetting on multiscale surfaces. Limiting cases include those considered in the Wenzel, Cassie-Baxter, and wicking state models. Wetting characterisation of multiscale surfaces is explored by conducting simulations of a fluid droplet on a structurally rough surface and a chemically heterogeneous surface. Findings The underlying origin of the classical wetting models is shown to be rooted within the proposed theoretical framework. Integral geometry provides a topological-based wetting metric that is not contingent on any type of wetting state. The wetting metric is demonstrated to account for multiscale features along the common line in a scale consistent way; providing a universal description of wetting for multiscale surfaces.

The rate of emulsification in surfactant/oil/water systems is influenced by transport of chemicals and mixing of the fluid phases. In porous media applications, complex flow regimes are generated due to three-dimensional connectivity and irregular cross-sections of the pores facilitating the mixing for emulsification. The properties of the resulting emulsified phase depend on the interplay of flow, mixing and emulsification kinetics of the surfactant/oil/water system. Emulsification can be relatively quick. Direct visualization of the process and compositional gradients in three-dimensional pore space during flow requires imaging at few seconds time intervals. In this study, a flow unit was integrated in a synchrotron beamline-based fast X-ray computed micro-tomography set-up. Non-destructive three-dimensional visualization of multi phase flow inside a porous rock at flow conditions became viable. An oil saturated rock sample was first flooded with water, followed by surfactant solution to mobilize the remaining oil by miscible displacement. The sample was continuously imaged during injection; the scans were made at time intervals of 7–60 s. The presence of an emulsified phase in addition to the oil and the aqueous phases required a more advanced image processing workflow compared to the workflows used for the immiscible fluid systems. A newly developed image processing technique was adopted; the grey levels in the images were correlated with the local oil content in the emulsified fluid regions. The visual extractions of the pore space showed that the emulsification occurred within seconds. Compositional gradients were observed in the emulsified phase as the injected surfactant solution reached the remote locations in the pore space. While a significant fraction of the oil was displaced within few seconds, the compositional gradients persisted over several millimeter length for several minutes, illustrating a sequence of mobilization and solubilization of the oil phase. The ability to interpret such compositional gradients in real time in porous space brings capability to study interfacial phenomena in applications where in situ emulsification occurs under flow.