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We characterize the pore-scale fluid distributions, phase connectivity, and local capillary pressures during three-phase flow in a water-wet Berea sandstone sample. In this investigation, we use a set of x-ray micro-tomography images acquired during three-phase core-flooding experiments conducted on a miniature core sample. We use several image analysis techniques to analyze the pore-scale fluid occupancy maps and use this information to develop several insights related to pore occupancy, oil and gas cluster distribution, and interfacial curvature during the gas injection process. The results of our investigation show that the large-, intermediate-, and small-sized pores are mostly occupied with gas, oil, and brine, respectively, which is consistent with the wetting order of the fluids (i.e., gas, oil, and brine are the nonwetting, intermediate wetting, and wetting phases, respectively). In addition, the connectivity analysis reveals that a significant amount of the gas phase was in the form of disconnected ganglia separated from the connected invading cluster. The presence of these trapped nonwetting phase clusters during the drainage process is presumably attributed to Roof snap-off and Haines jump events, as well as the anti-ripening phenomenon. Moreover, the average local oil-water capillary pressures are found to be greater than the gas-oil counterparts. This observation is then related to the relative location of the interfaces in the pore space and the threshold capillary pressures at which the various displacement events take place.

Geomechanical deformation, which is mainly caused by the pore pressure variation induced by fluid extraction or injection, is commonly observed in environmental and petroleum subsurface systems. As the effective stress varies, the porosity and absolute permeability of the rock may change owing to the distortion and volumetric changes in the pore space induced by the grain movement (David et al., 1994;Dong et al., 2010;Fatt & Davis, 1952;Gray & Fatt, 1963). Meanwhile, the multiphase flow in the pore space may also be impacted. For instance, the threshold capillary pressure, which is the entering pressure required for one phase to enter a pore and displace other phases, and the effective permeability of each phase are all strongly affected by changes in the pore size and shape (Tiab & Donaldson, 2015). Moreover, the competition between the non-wetting phase displacement and the trapping mechanisms is significantly influenced by the aspect ratio, that is, the ratio of the pore size to throat size, which can likewise be affected by the stress conditions (Blunt, 2017;Yu & Wardlaw, 1986). Hence, understanding the impact of pore space deformation on multiphase flow in porous media is of great significance for various engineering processes that involve fluid flow in the subsurface, such as hydrocarbon recovery, groundwater remediation and management, CO 2 geosequestration, and hydrogen storage.Over the last few decades, numerous experimental studies have been dedicated to exploring the variation in relative permeabilities at different stress conditions. To simplify their experiments, the majority of the investigations to date measured the relative permeabilities by increasing the hydrostatic confining pressure (total stress) while the pore pressure was fixed (

Naturally fractured oil-wet carbonate reservoirs host a considerable fraction of oil reserves worldwide. However, the recovery factor in these reservoirs is typically low due to the inherent oil-wet characteristics of the carbonate rock and the limited interactions usually established between the fracture and matrix domains during enhanced oil recovery processes. This study was conceived to develop an improved fundamental understanding of the pore-scale displacement mechanisms responsible for oil recovery from naturally fractured oil-wet carbonates during secondary waterflooding and tertiary surfactant injection. To achieve this objective, a state-of-the-art multiphase core-flooding system integrated with a high-resolution micro-CT imaging platform was utilized to perform a series of flow experiments on a miniature fractured oil-wet carbonate sample at elevated pressure and temperature conditions. The fluid occupancy maps generated during the flow experiments were used to characterize the in situ wettability and capillary pressure, and track fracture displacement events, fracture–matrix interactions, and oil mobilization patterns at the pore scale. The results revealed that the surfactant solution reversed the wettability of both rough fracture walls and pore surfaces from an initially oil-wet state to a neutral-wet condition. This was accompanied by an order-of-magnitude reduction in the oil–water interfacial tension (IFT). The synergistic effects of wettability reversal and IFT reduction induced by surfactant injection were pivotal to decreasing the threshold pressure required for additional oil displacement from the rock matrix adjacent to the fracture. Additionally, notable evidence of fracture storage and displacement events at the pore scale was obtained in the form of wetting oil pockets and bridging events. Fracture oil pockets and bridges formed on the rough fracture walls and narrow aperture regions may enhance fracture–matrix interactions during base waterflooding by restricting brine flow through the higher-conductivity fracture. The collapse of such fracture oil storage features during the succeeding surfactant injection contributed considerably to the ultimate oil recovery from the combined media.

We present a detailed multi‐level investigation of steady‐state three‐phase flow processes in a water‐wet Berea sandstone sample. We use high‐resolution micro‐computed tomography images acquired during micro‐scale core‐flooding experiments which include successive gas injection, waterflooding, and nonspreading oil flooding steps. We develop and employ robust techniques to comprehensively characterize and probe the complex interrelationships between the pore‐scale three‐phase capillary pressures, fluid occupancy, displacement events, and the macroscopic flow behavior. The results demonstrate that the local capillary pressures involving the invading phase rise or drop in compliance with the changes in the macroscopic flow ratios. For instance, the gas‐oil capillary pressures were at their highest levels during the gas injection process (highest gas/oil fractional flow) and dropped during the subsequent processes. More importantly, the oil‐water capillary pressure is found to sharply rise during the gas injection process, implying that the gas‐displacing‐oil‐displacing‐water double displacements are the dominant double displacement mechanism during this experiment. For the waterflooding test, the local gas‐oil capillary pressures consistently decrease due to water‐displacing‐oil‐displacing‐gas double displacement events. Moreover, the results show that the variations in the gas‐liquid capillary pressures are more significant than those in the oil‐water capillary pressures. Also, the variations in all capillary pressures during gas injection are higher than in the subsequent processes. The higher variations in capillary pressure values are attributed to more localized and less uniform pore‐scale events across the medium. Finally, the capillary pressure gradients along the flow direction are incorporated in the three‐phase relative permeability measurements.