Understanding the pore-scale dynamics of two-phase fluid flow in permeable media is important in many processes such as water infiltration in soils, oil recovery, and geo-sequestration of CO₂. The two most important processes that compete during the displacement of a non-wetting fluid by a wetting fluid are pore-filling or piston-like displacement and snap-off; this latter process can lead to trapping of the non-wetting phase. We present a three-dimensional dynamic visualization study using fast synchrotron X-ray micro-tomography to provide new insights into these processes by conducting a time-resolved pore-by-pore analysis of the local curvature and capillary pressure. We show that the time-scales of interface movement and brine layer swelling leading to snap-off are several minutes, orders of magnitude slower than observed for Haines jumps in drainage. The local capillary pressure increases rapidly after snap-off as the trapped phase finds a position that is a new local energy minimum. However, the pressure change is less dramatic than that observed during drainage. We also show that the brine-oil interface jumps from pore-to-pore during imbibition at an approximately constant local capillary pressure, with an event size of the order of an average pore size, again much smaller than the large bursts seen during drainage.

We used X-ray micro-tomography to image the in situ wettability, the distribution of contact angles, at the pore scale in calcite cores from a producing hydrocarbon reservoir at subsurface conditions. The contact angle was measured at hundreds of thousands of points for three samples after twenty pore volumes of brine flooding.We found a wide range of contact angles with values both above and below 90°. The hypothesized cause of wettability alteration by an adsorbed organic layer on surfaces contacted by crude oil after primary drainage was observed with Scanning Electron Microscopy (SEM) and identified using Energy Dispersive X-ray (EDX) analysis. However, not all oil-filled pores were altered towards oil-wet conditions, which suggests that water in surface roughness, or in adjacent micro-porosity, can protect the surface from a strong wettability alteration. The lowest oil recovery was observed for the most oil-wet sample, where the oil remained connected in thin sheet-like layers in the narrower regions of the pore space. The highest recovery was seen for the sample with an average contact angle close to 90°, with an intermediate recovery in a more water-wet system, where the oil was trapped in ganglia in the larger regions of the pore space.

Liquid invasion into a porous medium is a phenomenon of great importance in both nature and technology. Despite its enormous importance, there is a surprisingly sparse understanding of the processes occurring on the scale of individual pores and of how these processes determine the global invasion pattern. In particular, the exact influence of the wettability remains unclear besides the limiting cases of very small or very large contact angles of the invading fluid. Most quantitative pore-scale experiments and theoretical considerations have been conducted in effectively two-dimensional (2D) micromodels and Hele–Shaw geometries. Although these pioneering works helped to unravel some of the physical aspects of the displacement processes, the relevance of 2D models has not always been appreciated for natural porous media. With the availability of X-ray microtomography, 3D imaging has become a standard for exploring pore-scale processes in porous media. Applying advanced postprocessing routines and synchrotron microtomography, researchers can image even slow flow processes in real time and extract relevant material parameters like the contact angle from the interfaces in the pore space. These advances are expected to boost both theoretical and experimental understanding of pore-scale processes in natural porous media.

We have investigated the effect of wettability of carbonate rocks on the morphologies of remaining oil after sequential oil and brine injection in a capillary‐dominated flow regime at elevated pressure. The wettability of Ketton limestone was altered in situ using an oil phase doped with fatty acid which produced mixed‐wet conditions (the contact angle where oil contacted the solid surface, measured directly from the images, θ=180°, while brine‐filled regions remained water‐wet), whereas the untreated rock (without doped oil) was weakly water‐wet (θ=47 ± 9°). Using X‐ray micro‐tomography, we show that the brine displaces oil in larger pores during brine injection in the mixed‐wet system, leaving oil layers in the pore corners or sandwiched between two brine interfaces. These oil layers, with an average thickness of 47 ± 17 µm, may provide a conductive flow path for slow oil drainage. In contrast, the oil fragments into isolated oil clusters/ganglia during brine injection under water‐wet conditions. Although the remaining oil saturation in a water‐wet system is about a factor of two larger than that obtained in the mixed‐wet rock, the measured brine‐oil interfacial area of the disconnected ganglia is a factor of three smaller than that of oil layers.

Underground hydrogen (H₂) storage is a potentially viable solution for large-scale cyclic H₂ storage; however, the behavior of H₂ at subsurface pressure and temperature conditions is poorly known. This work investigates if the pore-scale displacement processes in H₂-brine systems in a porous sandstone can be sufficiently well defined to enable effective and economic storage operations. In particular, this study investigates trapping, dissolution, and wettability of H₂-brine systems at the pore-scale, at conditions that are realistic for subsurface H₂ storage. We have performed in situ X-ray imaging during a flow experiment to investigate pore-scale processes during H₂ injection and displacement in a brine saturated Bentheimer sandstone sample at temperature and pressure conditions representative of underground reservoirs. Two injection schemes were followed for imbibition: displacement of H₂ with H₂-equilibrated brine and with non-H₂-equilibrated brine. The results from the two cycles were compared with each other. The sandstone was found to be wetting to the brine and non-wetting to H₂ after both displacement cycles, with average contact angles of 54° and 53° for H₂-equilibrated and non-H₂-equilibrated brine respectively. We also found a higher recovery of H₂ (43.1%) when displaced with non-H₂-equilibrated brine compared to that of H₂-equilibrated brine (31.6%), indicating potential dissolution of H₂ in the unequilibrated imbibing brine at reservoir conditions. Our results suggest that underground H₂ storage may indeed be a suitable strategy for energy storage, but considerable further research is needed to fully comprehend the pore-scale interactions at reservoir conditions.

Darcy‐scale multiphase flow in geological formations is significantly influenced by the wettability of the fluid‐solid system. So far it has not been understood how wettability impacts the pore‐scale flow regimes within rocks, which were in most cases regarded as an alteration from the base case of strongly water‐wet conditions by adjustment of contact angles. In this study, we directly image the pore‐scale flow regime in a carbonate altered to a mixed‐wet condition by aging with crude oil to represent the natural configuration in an oil reservoir with fast synchrotron‐based X‐ray computed tomography. We find that the pore‐scale flow regime is dominated by ganglion dynamics in which the pore space is intermittently filled with oil and brine. The frequency and size of these fluctuations are greater than in water‐wet rock such that their impact on the overall flow and relative permeability cannot be neglected in modeling approaches.