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...

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.

We study the displacement of immiscible fluids in deformable, noncohesive granular media. Experimentally, we inject air into a thin bed of water-saturated glass beads and observe the invasion morphology. The control parameters are the injection rate, the bead size, and the confining stress. We identify three invasion regimes: capillary fingering, viscous fingering, and "capillary fracturing," where capillary forces overcome frictional resistance and induce the opening of conduits. We derive two dimensionless numbers that govern the transition among the different regimes: a modified capillary number and a fracturing number. The experiments and analysis predict the emergence of fracturing in fine-grained media under low confining stress, a phenomenon that likely plays a fundamental role in many natural processes such as primary oil migration, methane venting from lake sediments, and the formation of desiccation cracks.

We study a sharp-interface mathematical model of CO 2 migration in deep saline aquifers, which accounts for gravity override, capillary trapping, natural groundwater flow, and the shape of the plume during the injection period. The model leads to a nonlinear advection-diffusion equation, where the diffusive term is due to buoyancy forces, not physical diffusion. For the case of interest in geological CO 2 storage, in which the mobility ratio is very unfavorable, the mathematical model can be simplified to a hyperbolic equation. We present a complete analytical solution to the hyperbolic model. The main outcome is a closed-form expression that predicts the ultimate footprint on the CO 2 plume, and the time scale required for complete trapping. The capillary trapping coefficient and the mobility ratio between CO 2 and brine emerge as the key parameters in the assessment of CO 2 storage in saline aquifers. Despite the many approximations, the model captures the essence of the flow dynamics and therefore reflects proper dependencies on the mobility ratio and the capillary trapping coefficient, which are basin-specific. The expressions derived here have applicability to capacity estimates by capillary trapping at the basin scale.

Injection of carbon dioxide (CO2) into geological formations is widely regarded as a promising tool for reducing global atmospheric CO2 emissions. To evaluate injection scenarios, estimate reservoir capacity and assess leakage risks, an accurate understanding of the subsurface spreading and migration of the plume of mobile CO2 is essential. Here, we present a complete solution to a theoretical model for the subsurface migration of a plume of CO2 due to natural groundwater flow and aquifer slope, and subject to residual trapping. The results show that the interplay of these effects leads to non-trivial behaviour in terms of trapping efficiency. The analytical nature of the solution offers insight into the physics of CO2 migration, and allows for rapid, basin-specific capacity estimation. We use the solution to explore the parameter space via the storage efficiency, a macroscopic measure of plume migration. In a future study, we shall incorporate CO2 dissolution into the migration model and study the importance of dissolution relative to capillary trapping and the impact of dissolution on the storage efficiency.