Multiphase flow in porous media is important in many natural and industrial processes, including geologic CO 2 sequestration, enhanced oil recovery, and water infiltration into soil. Although it is well known that the wetting properties of porous media can vary drastically depending on the type of media and pore fluids, the effect of wettability on multiphase flow continues to challenge our microscopic and macroscopic descriptions. Here, we study the impact of wettability on viscously unfavorable fluid-fluid displacement in disordered media by means of high-resolution imaging in microfluidic flow cells patterned with vertical posts. By systematically varying the wettability of the flow cell over a wide range of contact angles, we find that increasing the substrate's affinity to the invading fluid results in more efficient displacement of the defending fluid up to a critical wetting transition, beyond which the trend is reversed. We identify the pore-scale mechanisms-cooperative pore filling (increasing displacement efficiency) and corner flow (decreasing displacement efficiency)-responsible for this macroscale behavior, and show that they rely on the inherent 3D nature of interfacial flows, even in quasi-2D media. Our results demonstrate the powerful control of wettability on multiphase flow in porous media, and show that the markedly different invasion protocols that emerge-from pore filling to postbridging-are determined by physical mechanisms that are missing from current pore-scale and continuum-scale descriptions.porous media | capillarity | wettability | microfluidics | pattern formation M ultiphase flow in porous media is important in many natural and industrial processes, including geologic CO 2 sequestration (1), enhanced oil recovery (2), water infiltration into soil (3), and transport in polymer electrolyte fuel cells (4). Much of the research on multiphase flow in porous media has focused on the effect of fluid properties and flow conditions. Much less emphasis has been given to the fluids' affinity to the porous media (i.e., wettability), even though wettability has a profound influence on fluid-fluid interactions in the presence of a solid surface (5-7). Despite recent advances in our ability to accurately measure wettability under reservoir conditions (8, 9), and to engineer wettability in the subsurface (10-13), the complex physics of wetting continues to challenge our microscopic and macroscopic descriptions (14).Fluid-fluid displacement in the presence of a solid surface can be characterized as either drainage or imbibition, depending on the system's wettability. Drainage refers to the regime where the invading fluid is less wetting to the solid surface than the defending fluid. Imbibition refers to the opposite case, where the invading fluid is more wetting to the solid surface than the defending fluid. Drainage in porous media has been studied extensively through laboratory experiments and computer simulations (15-18), and we now have a fairly good understanding of the different displacement ...

[1] Relative permeabilities are the key descriptors in classical formulations of multiphase flow in porous media. Experimental evidence and an analysis of pore-scale physics demonstrate conclusively that relative permeabilities are not single functions of fluid saturations and that they display strong hysteresis effects. In this paper, we evaluate the relevance of relative permeability hysteresis when modeling geological CO 2 sequestration processes. Here we concentrate on CO 2 injection in saline aquifers. In this setting the CO 2 is the nonwetting phase, and capillary trapping of the CO 2 is an essential mechanism after the injection phase during the lateral and upward migration of the CO 2 plume. We demonstrate the importance of accounting for CO 2 trapping in the relative permeability model for predicting the distribution and mobility of CO 2 in the formation. We conclude that modeling of relative permeability hysteresis is required to assess accurately the amount of CO 2 that is immobilized by capillary trapping and therefore is not available to leak. We also demonstrate how the mechanism of capillary trapping can be exploited (e.g., by controlling the injection rate or alternating water and CO 2 injection) to improve the overall effectiveness of the injection project.

In carbon capture and storage (CCS), CO 2 is captured at power plants and then injected underground into reservoirs like deep saline aquifers for long-term storage. While CCS may be critical for the continued use of fossil fuels in a carbon-constrained world, the deployment of CCS has been hindered by uncertainty in geologic storage capacities and sustainable injection rates, which has contributed to the absence of concerted government policy. Here, we clarify the potential of CCS to mitigate emissions in the United States by developing a storage-capacity supply curve that, unlike current large-scale capacity estimates, is derived from the fluid mechanics of CO 2 injection and trapping and incorporates injection-rate constraints. We show that storage supply is a dynamic quantity that grows with the duration of CCS, and we interpret the lifetime of CCS as the time for which the storage supply curve exceeds the storage demand curve from CO 2 production. We show that in the United States, if CO 2 production from power generation continues to rise at recent rates, then CCS can store enough CO 2 to stabilize emissions at current levels for at least 100 y. This result suggests that the large-scale implementation of CCS is a geologically viable climate-change mitigation option in the United States over the next century.carbon sequestration | pressure dissipation | residual trapping | solubility trapping C arbon dioxide is a well-documented greenhouse gas, and a growing body of evidence indicates that anthropogenic CO 2 emissions are a major contributor to climate change (1). One promising technology to mitigate CO 2 emissions is carbon capture and storage (CCS) (2-4). In the context of this study, CCS involves capturing CO 2 from the flue gas of power plants, compressing it into a supercritical fluid, and then injecting it into deep saline aquifers for long-term storage (4, 5). Compared with other mitigation technologies such as renewable energy, CCS is important because it may enable the continued use of fossil fuels, which currently supply >80% of the primary power for the planet (6, 7). We focus on CO 2 produced by power plants because electric power generation currently accounts for >40% of worldwide CO 2 emissions (8) and because power plants are large, stationary point sources of emissions where CO 2 capture technology will likely be deployed first (4). We further restrict our analysis to coal-and gas-fired power plants because they emit more CO 2 than any other type of plant: Since 2000, they have emitted ∼97% by mass of the total CO 2 produced by electricitygenerating power plants in the United States (9). We focus on storing this CO 2 in deep saline aquifers because they are geographically widespread and their storage capacity is potentially very large (4, 5).We define the storage capacity of a saline aquifer to be the maximum amount of CO 2 that could be injected and securely stored under geologic constraints, such as the aquifer's size and the integrity of its caprock. Regulatory, legal, and economic factors...

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19.12.14 KB. Ok to add published version to spiral after 6 months embargo - expires 15 March 201

The coupling between subsurface flow and geomechanical deformation is critical in the assessment of the environmental impacts of groundwater use, underground liquid waste disposal, geologic storage of carbon dioxide, and exploitation of shale gas reserves. In particular, seismicity induced by fluid injection and withdrawal has emerged as a central element of the scientific discussion around subsurface technologies that tap into water and energy resources. Here we present a new computational approach to model coupled multiphase flow and geomechanics of faulted reservoirs. We represent faults as surfaces embedded in a three-dimensional medium by using zero-thickness interface elements to accurately model fault slip under dynamically evolving fluid pressure and fault strength. We incorporate the effect of fluid pressures from multiphase flow in the mechanical stability of faults and employ a rigorous formulation of nonlinear multiphase geomechanics that is capable of handling strong capillary effects. We develop a numerical simulation tool by coupling a multiphase flow simulator with a mechanics simulator, using the unconditionally stable fixed-stress scheme for the sequential solution of two-way coupling between flow and geomechanics. We validate our modeling approach using several synthetic, but realistic, test cases that illustrate the onset and evolution of earthquakes from fluid injection and withdrawal.

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We study experimentally how wettability impacts fluid-fluid-displacement patterns in granular media. We inject a low-viscosity fluid (air) into a thin bed of glass beads initially saturated with a more-viscous fluid (a water-glycerol mixture). Chemical treatment of glass surfaces allows us to control the wetting properties of the medium and modify the contact angle θ from 5°(drainage) to 120°(imbibition). We demonstrate that wettability exerts a powerful influence on the invasion morphology of unfavorable mobility displacements: increasing θ stabilizes fluid invasion into the granular pack at all capillary numbers. In particular, we report the striking observation of a stable radial displacement at low capillary numbers, whose origin lies on the cooperative nature of fluid invasion at the pore scale.