During imbibition, initially connected oil is displaced until it is trapped as immobile clusters. While initial and final states have been well described before, here we image the dynamic transient process in a sandstone rock using fast synchrotron‐based X‐ray computed microtomography. Wetting film swelling and subsequent snap off, at unusually high saturation, decreases nonwetting phase connectivity, which leads to nonwetting phase fragmentation into mobile ganglia, i.e., ganglion dynamics regime. We find that in addition to pressure‐driven connected pathway flow, mass transfer in the oil phase also occurs by a sequence of correlated breakup and coalescence processes. For example, meniscus oscillations caused by snap‐off events trigger coalescence of adjacent clusters. The ganglion dynamics occurs at the length scale of oil clusters and thus represents an intermediate flow regime between pore and Darcy scale that is so far dismissed in most upscaling attempts.

In multiphase flow in porous media the consistent pore to Darcy scale description of two-fluid flow processes has been a long-standing challenge. Immiscible displacement processes occur at the scale of individual pores. However, the larger scale behavior is described by phenomenological relationships such as relative permeability, which typically uses only fluid saturation as a state variable. As a consequence pore scale properties such as contact angle cannot be directly related to Darcy scale flow parameters. Advanced imaging and computational technologies are closing the gap between the pore and Darcy scale, supporting the development of new theory. We utilize fast x-ray microtomography to observe pore-scale two-fluid configurations during immiscible flow and initialize lattice Boltzmann simulations that demonstrate that the mobilization of disconnected nonwetting phase clusters can account for a significant fraction of the total flux. We show that fluid topology can undergo substantial changes during flow at constant saturation, which is one of the underlying causes of hysteretic behavior. Traditional assumptions about fluid configurations are therefore an oversimplification. Our results suggest that the role of fluid connectivity cannot be ignored for multiphase flow. On the Darcy scale, fluid topology and phase connectivity are accounted for by interfacial area and Euler characteristic as parameters that are missing from our current models.

The macroscopic description of the hysteretic behavior of two‐phase flow in porous media remains a challenge. It is not obvious how to represent the underlying pore‐scale processes at the Darcy‐scale in a consistent way. Darcy‐scale thermodynamic models do not completely eliminate hysteresis and our findings indicate that the shape of displacement fronts is an additional source of hysteresis that has not been considered before. This is a shortcoming because effective process behavior such as trapping efficiency of CO₂ or oil production during water flooding are directly linked to pore‐scale displacement mechanisms with very different front shape such as capillary fingering, flat frontal displacement, or cluster growth. Here we introduce fluid topology, expressed by the Euler characteristic of the nonwetting phase (χ_n), as a shape measure of displacement fronts. Using two high‐quality data sets obtained by fast X‐ray tomography, we show that χ_n is hysteretic between drainage and imbibition and characteristic for the underlying displacement pattern. In a more physical sense, the Euler characteristic can be interpreted as a parameter describing local fluid connectedness. It may provide the closing link between a topological characterization and macroscopic formulations of two‐phase immiscible displacement in porous rock. Since fast X‐ray tomography is currently becoming a mature technique, we expect a significant growth in high‐quality data sets of real time fluid displacement processes in the future. The novel measures of fluid topology presented here have the potential to become standard metrics needed to fully explore them.

Pore-scale images obtained from a synchrotron-based X-ray computed micro-tomography (µCT) imbibition experiment in sandstone rock were used to conduct Navier–Stokes flow simulations on the connected pathways of water and oil phases. The resulting relative permeability was compared with steady-state Darcy-scale imbibition experiments on 5cm large twin samples from the same outcrop sandstone material. While the relative permeability curves display a large degree of similarity, the endpoint saturations for the µCT data are 10% in saturation units higher than the experimental data. However, the two datasets match well when normalizing to the mobile saturation range. The agreement is particularly good at low water saturations, where the oil is predominantly connected. Apart from different saturation endpoints, in this particular experiment where connected pathway flow dominates, the discrepancies between pore-scale connected pathway flow simulations and Darcy-scale steady-state data are minor overall and have very little impact on fractional flow. The results also indicate that if the pore-scale fluid distributions are available and the amount of disconnected non-wetting phase is low, quasi-static flow simulations may be sufficient to compute relative permeability. When pore-scale fluid distributions are not available, fluid distributions can be obtained from a morphological approach, which approximates capillary-dominated displacement. The relative permeability obtained from the morphological approach compare well to drainage steady state whereas major discrepancies to the imbibition steady-state experimental data are observed. The morphological approach does not represent the imbibition process very well and experimental data for the spatial arrangement of the phases are required. Presumably for modeling imbibition relative permeability an approach is needed that captures moving liquid-liquid interfaces, which requires viscous and capillary forces simultaneously

Porous materials with pore sizes spanning the range from molecular to macroscopic dimensions (from angstroms to centimeters) are essential in electrochemical, thermoelectric, nuclear, and solar power sources and in the extraction of oil, gas, and geothermal heat. To enable the clean, fast, and efficient conversion of energy, the porous structure must be designed to allow, modulate, or block the flow of energy transfer vectors. The most important energy streams are mass, charge, heat, radiation, and pressure, and they must be optimized while packing the optimal surface area per device volume. In this Review, we analyze the physical processes that enable energy transfer in porous structures, highlighting recent advances in the design, characterization, modeling, and fundamental understanding of porosity that have enabled breakthroughs across the landscape of energy technologies.

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.