Feasibility of Carbon Dioxide Storage Resource Use within Climate Change Mitigation Scenarios for the United States.

To progress decarbonization in the United States, numerous techno-economic models that project CO2 storage deployment at annual injection rates of 0.3-1.7 Gt year-1 by 2050 have been built. However, these models do not consider many geological, technical, or socio-economic factors that could impede the growth of geological storage resource use, and there is uncertainty about the feasibility of the resulting projections. Here, we evaluate storage scenarios across four major modeling efforts. We apply a growth modeling framework using logistic curves to analyze the feasibility of growth trajectories under constraints imposed by the associated storage resource availability. We show that storage resources are abundant, and resources of the Gulf Coast alone would be sufficient to meet national demand were it not for transport limitations. On the contrary, deployment trajectories require sustained average annual (exponential) growth at rates of >10% nationally for two of the three reports and between 3% and 20% regionally across four storage hubs projected in both reports with regional resolution. These rates are high relative to historical rates of growth in analogous large scale energy infrastructure in the United States. Projections for California appear to be particularly infeasible. Future modeling efforts should be constrained to more realistic deployment trajectories, which could be done with simple constraints from the type of modeling framework presented here.

An Estimate of the Amount of Geological CO2 Storage over the Period of 1996-2020.

The climate impact of carbon capture and storage depends on how much CO2 is stored underground, yet databases of industrial-scale projects report capture capacity as a measure of project size. We review publicly available sources to estimate the amount of CO2 that has been stored by facilities since 1996. We organize these sources into three categories corresponding to the associated degree of assurance: (1) legal assurance, (2) quality assurance through auditing, and (3) no assurance. Data were found for 20 facilities, with an aggregate capture capacity of 36 Mt of CO2 year-1. Combining data from all categories, we estimate that 29 Mt of CO2 was geologically stored in 2019 and there was cumulative storage of 197 Mt over the period of 1996-2020. These are climate relevant scales commensurate with recent cumulative and ongoing emissions impacts of renewables in some markets, e.g., solar photovoltaics in the United States. The widely used capture capacity is in aggregate 19-30% higher than storage rates and is not a good proxy for estimating storage volumes. However, the discrepancy is project-specific and not always a reflection of project performance. This work provides a snapshot of storage amounts and highlights the need for uniform reporting on capture and storage rates with quality assurance.

Determination of the spatial distribution of wetting in the pore networks of rocks.

HYPOTHESIS: The macroscopic movement of subsurface fluids involved in CO2 storage, groundwater, and petroleum engineering applications is controlled by interfacial forces in the pores of rocks. Recent advances in modelling these systems has arisen from approaches simulating flow through a digital representation of the complex pore structure. However, further progress is limited by difficulties in characterising the spatial distribution of the wetting state within the pore structure. In this work, we show how observations of the fluid coverage of mineral surfaces within the pores of rocks can be used as the basis for a quantitative 3D characterisation of heterogeneous wetting states throughout rock pore structures. EXPERIMENTS: We demonstrate the approach with water-oil fluid pairs on rocks with distinct lithologies (sandstone and carbonate) and wetting states (hydrophilic, intermediate wetting, and heterogeneously wetting). FINDINGS: Fluid surface coverage the within rock pores is a robust signal of the wetting state across varying rock types and wetting states. The wetting state can be quantified and the resulting 3D maps can be used as a deterministic input to pore scale models. These may be applied to multiphase flow problems in porous media ranging from soil science to fuel cells.

Storage of Carbon Dioxide in Saline Aquifers: Physicochemical Processes, Key Constraints, and Scale-Up Potential.

CO2 storage in saline aquifers offers a realistic means of achieving globally significant reductions in greenhouse gas emissions at the scale of billions of tonnes per year. We review insights into the processes involved using well-documented industrial-scale projects, supported by a range of laboratory analyses, field studies, and flow simulations. The main topics we address are (a) the significant physicochemical processes, (b) the factors limiting CO2 storage capacity, and (c) the requirements for global scale-up.Although CO2 capture and storage (CCS) technology can be considered mature and proven, it requires significant and rapid scale-up to meet the objectives of the Paris Climate Agreement. The projected growth in the number of CO2 injection wells required is significantly lower than the historic petroleum industry drill rates, indicating that decarbonization via CCS is a highly credible and affordable ambition for modern human society. Several technology developments are needed to reduce deployment costs and to stimulate widespread adoption of this technology, and these should focus on demonstration of long-term retention and safety of CO2 storage and development of smart ways of handling injection wells and pressure, cost-effective monitoring solutions, and deployment of CCS hubs with associated infrastructure.

Mechanisms controlling fluid breakup and reconnection during two-phase flow in porous media.

The use of Darcy's law to describe steady-state multiphase flow in porous media has been justified by the assumption that the fluids flow in continuously connected pathways. However, a range of complex interface dynamics have been observed during macroscopically steady-state flow, including intermittent pathway flow where flow pathways periodically disconnect and reconnect. The physical mechanisms controlling this behavior have remained unclear, leading to uncertainty concerning the occurrence of the different flow regimes. We observe that the fraction of intermittent flow pathways is dependent on the capillary number and viscosity ratio. We propose a phase diagram within this parameter space to quantify the degree of intermittent flow.

Intermittent fluid connectivity during two-phase flow in a heterogeneous carbonate rock.

Subsurface fluid flow is ubiquitous in nature, and understanding the interaction of multiple fluids as they flow within a porous medium is central to many geological, environmental, and industrial processes. It is assumed that the flow pathways of each phase are invariant when modeling subsurface flow using Darcy's law extended to multiphase flow, a condition that is assumed to be valid during steady-state flow. However, it has been observed that intermittent flow pathways exist at steady state even at the low capillary numbers typically encountered in the subsurface. Little is known about the pore structure controls or the impact of intermittency on continuum scale flow properties. Here we investigate the impact of intermittent pathways on the connectivity of the fluids for a carbonate rock. Using laboratory-based micro computed tomography imaging we observe that intermittent pathway flow occurs in intermediate-sized pores due to the competition between both flowing fluids. This competition moves to smaller pores when the flow rate of the nonwetting phase increases. Intermittency occurs in poorly connected pores or in regions where the nonwetting phase itself is poorly connected. Intermittent pathways lead to the interrupted transport of the fluids; this means they are important in determining continuum scale flow properties, such as relative permeability. The impact of intermittency on flow properties is significant because it occurs at key locations, whereby the nonwetting phase is otherwise disconnected.

Minimal surfaces in porous media: Pore-scale imaging of multiphase flow in an altered-wettability Bentheimer sandstone.

High-resolution x-ray imaging was used in combination with differential pressure measurements to measure relative permeability and capillary pressure simultaneously during a steady-state waterflood experiment on a sample of Bentheimer sandstone 51.6 mm long and 6.1 mm in diameter. After prolonged contact with crude oil to alter the surface wettability, a refined oil and formation brine were injected through the sample at a fixed total flow rate but in a sequence of increasing brine fractional flows. When the pressure across the system stabilized, x-ray tomographic images were taken. The images were used to compute saturation, interfacial area, curvature, and contact angle. From this information relative permeability and capillary pressure were determined as functions of saturation. We compare our results with a previously published experiment under water-wet conditions. The oil relative permeability was lower than in the water-wet case, although a smaller residual oil saturation, of approximately 0.11, was obtained, since the oil remained connected in layers in the altered wettability rock. The capillary pressure was slightly negative and 10 times smaller in magnitude than for the water-wet rock, and approximately constant over a wide range of intermediate saturation. The oil-brine interfacial area was also largely constant in this saturation range. The measured static contact angles had an average of 80^{∘} with a standard deviation of 17^{∘}. We observed that the oil-brine interfaces were not flat, as may be expected for a very low mean curvature, but had two approximately equal, but opposite, curvatures in orthogonal directions. These interfaces were approximately minimal surfaces, which implies well-connected phases. Saddle-shaped menisci swept through the pore space at a constant capillary pressure and with an almost fixed area, removing most of the oil.

Multidimensional Observations of Dissolution-Driven Convection in Simple Porous Media Using X-ray CT Scanning.

We present an experimental study of dissolution-driven convection in a three-dimensional porous medium formed from a dense random packing of glass beads. Measurements are conducted using the model fluid system MEG/water in the regime of Rayleigh numbers, R a = 2000 - 5000 . X-ray computed tomography is applied to image the spatial and temporal evolution of the solute plume non-invasively. The tomograms are used to compute macroscopic quantities including the rate of dissolution and horizontally averaged concentration profiles, and enable the visualisation of the flow patterns that arise upon mixing at a spatial resolution of about ( 2 × 2 × 2 ) mm 3 . The latter highlights that under this Ra regime convection becomes truly three-dimensional with the emergence of characteristic patterns that closely resemble the dynamical flow structures produced by high-resolution numerical simulations reported in the literature. We observe that the mixing process evolves systematically through three stages, starting from pure diffusion, followed by convection-dominated and shutdown. A modified diffusion equation is applied to model the convective process with an onset time of convection that compares favourably with the literature data and an effective diffusion coefficient that is almost two orders of magnitude larger than the molecular diffusivity of the solute. The comparison of the experimental observations of convective mixing against their numerical counterparts of the purely diffusive scenario enables the estimation of a non-dimensional convective mass flux in terms of the Sherwood number, S h = 0.025 R a . We observe that the latter scales linearly with Ra, in agreement with both experimental and numerical studies on thermal convection over the same Ra regime.

Computational Tools for Calculating log ß Values of Geochemically Relevant Uranium Organometallic Complexes.

Uranium (UVI) interacts with organic ligands, subsequently controlling its aqueous chemistry. It is therefore imperative to assess the binding ability of natural organic molecules. We evidence that density functional theory (DFT) can be used as a practical protocol for predicting the stability of UVI organic ligand complexes, allowing for the development of a relative stability series for organic complexes with limited experimental data. Solvation methods and DFT settings were benchmarked to suggest a suitable off-the-shelf solution. The results indicate that the IEFPCM solvation method should be employed. A mixed solvation approach improves the accuracy of the calculated stability constant (log ß); however, the calculated log ß are approximately five times more favorable than experimental data. Different basis sets, functionals, and effective core potentials were tested to check that there were no major changes in molecular geometries and Δr G. The recommended method employed is the B3LYP functional, aug-cc-pVDZ basis set for ligands, MDF60 ECP and basis set for UVI, and the IEFPCM solvation model. Using the fitting approach employed in the literature with these updated DFT settings allows fitting of 1:1 UVI complexes with root-mean-square deviation of 1.38 log ß units. Fitting multiple bound carboxylate ligands indicates a second, separate fitting for 1:2 and 1:3 complexes.

Dynamic fluid connectivity during steady-state multiphase flow in a sandstone.

The current conceptual picture of steady-state multiphase Darcy flow in porous media is that the fluid phases organize into separate flow pathways with stable interfaces. Here we demonstrate a previously unobserved type of steady-state flow behavior, which we term "dynamic connectivity," using fast pore-scale X-ray imaging. We image the flow of N2 and brine through a permeable sandstone at subsurface reservoir conditions, and low capillary numbers, and at constant fluid saturation. At any instant, the network of pores filled with the nonwetting phase is not necessarily connected. Flow occurs along pathways that periodically reconnect, like cars controlled by traffic lights. This behavior is consistent with an energy balance, where some of the energy of the injected fluids is sporadically converted to create new interfaces.

Pore Scale Observations of Trapped CO2 in Mixed-Wet Carbonate Rock: Applications to Storage in Oil Fields.

Geologic CO2 storage has been identified as a key to avoiding dangerous climate change. Storage in oil reservoirs dominates the portfolio of existing projects due to favorable economics. However, in an earlier related work ( Al-Menhali and Krevor Environ. Sci. Technol. 2016 , 50 , 2727 - 2734 ) , it was identified that an important trapping mechanism, residual trapping, is weakened in rocks with a mixed wetting state typical of oil reservoirs. We investigated the physical basis of this weakened trapping using pore scale observations of supercritical CO2 in mixed-wet carbonates. The wetting alteration induced by oil provided CO2-wet surfaces that served as conduits to flow. In situ measurements of contact angles showed that CO2 varied from nonwetting to wetting throughout the pore space, with contact angles ranging 25° < θ < 127°; in contrast, an inert gas, N2, was nonwetting with a smaller range of contact angle 24° < θ < 68°. Observations of trapped ganglia morphology showed that this wettability allowed CO2 to create large, connected, ganglia by inhabiting small pores in mixed-wet rocks. The connected ganglia persisted after three pore volumes of brine injection, facilitating the desaturation that leads to decreased trapping relative to water-wet systems.

Capillary Trapping of CO2 in Oil Reservoirs: Observations in a Mixed-Wet Carbonate Rock.

Early deployment of carbon dioxide storage is likely to focus on injection into mature oil reservoirs, most of which occur in carbonate rock units. Observations and modeling have shown how capillary trapping leads to the immobilization of CO2 in saline aquifers, enhancing the security and capacity of storage. There are, however, no observations of trapping in rocks with a mixed-wet-state characteristic of hydrocarbon-bearing carbonate reservoirs. Here, we found that residual trapping of supercritical CO2 in a limestone altered to a mixed-wet state with oil was significantly less than trapping in the unaltered rock. In unaltered samples, the trapping of CO2 and N2 were indistinguishable, with a maximum residual saturation of 24%. After the alteration of the wetting state, the trapping of N2 was reduced, with a maximum residual saturation of 19%. The trapping of CO2 was reduced even further, with a maximum residual saturation of 15%. Best-fit Land-model constants shifted from C = 1.73 in the water-wet rock to C = 2.82 for N2 and C = 4.11 for the CO2 in the mixed-wet rock. The results indicate that plume migration will be less constrained by capillary trapping for CO2 storage projects using oil fields compared with those for saline aquifers.

Real-time tracking of CO2 injected into a subsurface coal fire through high-frequency measurements of the ¹³CO2 signature.

CO2 was injected into a coal fire burning at a depth of 15 m in the subsurface in southwestern Colorado, USA. Measurements were made of the ¹³CO2 isotopic signature of gas exhaust from an observation well and two surface fissures. The goal of the test was to determine (1) whether CO2 with a distinct isotopic signature could be used as a tracer to identify flow pathways and travel times in a combustion setting where CO2 was present in significant quantities in the gases being emitted from the coalbed fire, and (2) to confirm the existence of a self-propagating system of air-intake and combustion gas exhaust that has been previously proposed. CO2 was injected in three separate periods. The ¹³CO2 isotopic signature was measured at high frequency (0.5 Hz) before, during, and after the injection periods for gas flowing from fissures over the fire and from gas entering an observation well drilled into the formation just above the fire but near the combustion zone. In two cases, a shift in the isotopic signature of outgassing CO2 provided clear evidence that injected CO2 had traveled from the injection well to the observation point, while in a third case, no response was seen and the fissure could not be assumed to have a flowpath connected with the injection well. High-frequency measurements of the ¹³CO2 signature of gas in observation wells is identified as a viable technique for tracking CO2 injected into subsurface formations in real-time. In addition, a chimney-like coupled air-intake and exhaust outlet system feeding the combustion of the coal seam was confirmed. This can be used to further develop strategies for extinguishing the fire.