Injection,Flow, and Mixing of CO<Subscript>2</Subscript> in Porous Media with Residual Gas

Geologic structures associated with depleted natural gas reservoirs are desirable targets for geologic carbon sequestration (GCS) as evidenced by numerous pilot and industrial-scale GCS projects in these environments world-wide. One feature of these GCS targets that may affect injection is the presence of residual CH₄. It is well known that CH₄ drastically alters supercritical CO₂ density and viscosity. Furthermore, residual gas of any kind affects the relative permeability of the liquid and gas phases, with relative permeability of the gas phase strongly dependent on the time-history of imbibition or drainage, i.e., dependent on hysteretic relative permeability. In this study, the effects of residual CH₄ on supercritical CO₂ injection were investigated by numerical simulation in an idealized one-dimensional system under three scenarios: (1) with no residual gas; (2) with residual supercritical CO₂; and (3) with residual CH₄. We further compare results of simulations that use non-hysteretic and hysteretic relative permeability functions. The primary effect of residual gas is to decrease injectivity by decreasing liquid-phase relative permeability. Secondary effects arise from injected gas effectively incorporating residual gas and thereby extending the mobile-gas plume relative to cases with no residual gas. Third-order effects arise from gas mixing and associated compositional effects on density that effectively create a larger plume per unit mass. Non-hysteretic models of relative permeability can be used to approximate some parts of the behavior of the system, but fully hysteretic formulations are needed to accurately model the entire system.     

An Experimental Study of CO<Subscript>2</Subscript> Exsolution and Relative Permeability Measurements During CO<Subscript>2</Subscript> Saturated Water Depressurization

Dissolution of CO₂ into brine is an important and favorable trapping mechanism for geologic storage of CO₂. There are scenarios, however, where dissolved CO₂ may migrate out of the storage reservoir. Under these conditions, CO₂ will exsolve from solution during depressurization of the brine, leading to the formation of separate phase CO₂. For example, a CO₂ sequestration system with a brine-permeable caprock may be favored to allow for pressure relief in the sequestration reservoir. In this case, CO₂-rich brine may be transported upwards along a pressure gradient caused by CO₂ injection. Here we conduct an experimental study of CO₂ exsolution to observe the behavior of exsolved gas under a wide range of depressurization. Exsolution experiments in highly permeable Berea sandstones and low permeability Mount Simon sandstones are presented. Using X-ray CT scanning, the evolution of gas phase CO₂ and its spatial distribution is observed. In addition, we measure relative permeability for exsolved CO₂ and water in sandstone rocks based on mass balances and continuous observation of the pressure drop across the core from 12.41 to 2.76 MPa. The results show that the minimum CO₂ saturation at which the exsolved CO₂ phase mobilization occurs is from 11.7 to 15.5%. Exsolved CO₂ is distributed uniformly in homogeneous rock samples with no statistical correlation between porosity and CO₂ saturation observed. No gravitational redistribution of exsolved CO₂ was observed after depressurization, even in the high permeability core. Significant differences exist between the exsolved CO₂ and water relative permeabilities, compared to relative permeabilities derived from steady-state drainage relative permeability measurements in the same cores. Specifically, very low CO₂ and water relative permeabilities are measured in the exsolution experiments, even when the CO₂ saturation is as high as 40%. The large relative permeability reduction in both the water and CO₂ phases is hypothesized to result from the presence of disconnected gas bubbles in this two-phase flow system. This feature is also thought to be favorable for storage security after CO₂ injection.     

CO2 Plume Evolution and Pressure Buildup of Large-scale CO2 Injection into Saline Aquifers in Sanzhao Depression, Songliao Basin, China

Large-scale injection of carbon dioxide (CO₂) into saline aquifers in sedimentary basins is a promising approach to mitigate global climate change. Songliao Basin, a large continental clastic sedimentary basin in northeastern China, is one of the great potential candidate sites for future CO₂ storage in China. In this paper, a three-dimensional CO₂ storage model was built to evaluate the CO₂ plume evolution and pressure buildup of large-scale CO₂ injection into the saline aquifers in the Sanzhao Depression of the Songliao Basin. CO₂ was injected into the aquifers through five wells, each with an annual injection rate of 3 Mt over 50?years. The results show that the clastic Yaojia formation at the depth between 900 and 1,600 m with thickness of 150 m might be the favorable layer to store a considerable amount of CO₂, and the overlying Nenjiang formation could ensure long-term CO₂ containment. The relative low permeability of the upper part of the Yaojia formation seems to play a role of a secondary seal on carbon storage. In current injection scenario, CO₂ plume migrates into the formations in the southeast of the depression, which could have potential risk of polluting the freshwater. Therefore, the injection site should stay far away from the southeast of the depression. Moreover, it is very crucial to investigate the permeability distribution of the Yaojia formation because it significantly dominates the CO₂ plume migration. After only 6?months of injection, the pressure buildup at each injection site is affected by pressure interference from neighboring sites. The maximum pressure buildup in the formations is 7.8?MPa after 50?years of injection, and it can even reach 10.5?MPa when the injection layers are with lower permeability. The maximum pressure buildup at the bottom of the Nenjiang formation is 6.7?MPa. The gradient of maximum limited formation pressure is about 18?MPa/km, which might cause fractures to open in the formations of the Sanzhao Depression. Continuous injection of CO₂ for 50?years may not cause damage to the caprock even when the lower permeability occurred in the upper part of the Yaojia formation. The safety of CO₂ storage will be enhanced if the upper part of the storage formation has lower permeability than the lower part.     

Characteristics of Salt-Precipitation and the Associated Pressure Build-Up during CO<Subscript>2</Subscript> Storage in Saline Aquifers

Mitigation and control of borehole pressure at the bottom of an injection well is directly related to the effective management of well injectivity during geologic carbon sequestration activity. Researchers have generally accepted the idea that high rates of CO₂ injection into low permeability strata results in increased bottom-hole pressure in a well. However, the results of this study suggested that this is not always the case, due to the occurrence of localized salt precipitation adjacent to the injection well. A series of numerical simulations indicated that in some cases, a low rate of CO₂ injection into high permeability formation induced greater pressure build-up. This occurred because of the different types of salt precipitation pattern controlled by buoyancy-driven CO₂ plume migration. The first type is non-localized salt precipitation, which is characterized by uniform salt precipitation within the dry-out zone. The second type, localized salt precipitation, is characterized by an abnormally high level of salt precipitation at the dry-out front. This localized salt precipitation acts as a barrier that hampers the propagation of both CO₂ and pressure to the far field as well as counter-flowing brine migration toward the injection well. These dynamic processes caused a drastic pressure build-up in the well, which decreased injectivity. By modeling a series of test cases, it was found that low-rate CO₂ injection into high permeability formation was likely to cause localized salt precipitation. Sensitivity studies revealed that brine salinity linearly affected the level of salt precipitation, and that vertical permeability enhanced the buoyancy effect which increased the growth of the salt barrier. The porosity also affected both the level of localized salt precipitation and dry-out zone extension depending on injection rates. High temperature injected CO₂ promoted the vertical movement of the CO₂ plume, which accelerated localized salt precipitation, but at the same time caused a decrease in the density of the injected CO₂. The combination of these two effects eventually decreased bottomhole pressure. Considering the injectivity degradation, a method is proposed for decreasing the pressure build-up and increasing injectivity by assigning a ‘skin zone’ that represents a local region with a transmissivity different from that of the surrounding aquifer.     

CO<Subscript>2</Subscript> injection into saline carbonate aquifer formations I: laboratory investigation

Although there are a number of mathematical modeling studies for carbon dioxide (CO₂) injection into aquifer formations, experimental studies are limited and most studies focus on injection into sandstone reservoirs as opposed to carbonate ones. This study presents the results of computerized tomography (CT) monitored laboratory experiments to analyze permeability and porosity changes as well as to characterize relevant chemical reactions associated with injection and storage of CO₂ in carbonate formations. CT monitored experiments are designed to model fast near well bore flow and slow reservoir flows. Highly heterogeneous cores drilled from a carbonate aquifer formation located in South East Turkey were used during the experiments. Porosity changes along the core plugs and the corresponding permeability changes are reported for different CO₂ injection rates and different salt concentrations of formation water. It was observed that either a permeability increase or a permeability reduction can be obtained. The trend of change in rock properties is very case dependent because it is related to distribution of pores, brine composition and thermodynamic conditions. As the salt concentration decreases, porosity and the permeability decreases are less pronounced. Calcite deposition is mainly influenced by orientation, with horizontal flow resulting in larger calcite deposition compared to vertical flow.     

Investigation of CO<Subscript>2</Subscript> Plume Behavior for a Large-Scale Pilot Test of Geologic Carbon Storage in a Saline Formation

The hydrodynamic behavior of carbon dioxide (CO₂) injected into a deep saline formation is investigated, focusing on trapping mechanisms that lead to CO₂ plume stabilization. A numerical model of the subsurface at a proposed power plant with CO₂ capture is developed to simulate a planned pilot test, in which 1,000,000 metric tons of CO₂ is injected over a 4-year period, and the subsequent evolution of the CO₂ plume for hundreds of years. Key measures are plume migration distance and the time evolution of the partitioning of CO₂ between dissolved, immobile free-phase, and mobile free-phase forms. Model results indicate that the injected CO₂ plume is effectively immobilized at 25 years. At that time, 38% of the CO₂ is in dissolved form, 59% is immobile free phase, and 3% is mobile free phase. The plume footprint is roughly elliptical, and extends much farther up-dip of the injection well than down-dip. The pressure increase extends far beyond the plume footprint, but the pressure response decreases rapidly with distance from the injection well, and decays rapidly in time once injection ceases. Sensitivity studies that were carried out to investigate the effect of poorly constrained model parameters permeability, permeability anisotropy, and residual CO₂ saturation indicate that small changes in properties can have a large impact on plume evolution, causing significant trade-offs between different trapping mechanisms.     

Supercritical CO2-Brine Relative Permeability Experiments in Reservoir Rocks��Literature Review and Recommendations

The relative permeability of carbon dioxide (CO₂) to brine influences the injectivity and plume migration when CO₂ is injected in a reservoir for CO₂ storage or enhanced oil recovery (EOR) purposes. It is common practice to determine the relative permeability of a fluid by means of laboratory measurements. Two principal approaches are used to obtain a relative permeability data: steady state and unsteady state. Although CO₂ has been employed in enhanced oil recovery, not much data can be found in the open literature. The few studies available report wide ranges for CO₂ relative permeability in typical sedimentary rocks such as Berea sandstone, dolomite, and others. The experimental setups vary for each study, employing steady and unsteady state approaches, different experimental parameters such as temperature, pressure, rock type, etc. and various interpretation methods. Hence, it is inherently difficult to compare the data and determine the origin of differences. It is evident that more experiments are needed to close this knowledge gap on relative permeability. This article concludes that standards for lab measurements need to be defined a. to establish a reliable CO₂-brine relative permeability measurement method that can be repeated under the same conditions in any lab and b. to enable comparison of the data to accurately predict the well injection and fluid migration behavior in the reservoir.     

Pressure Buildup During CO<Subscript>2</Subscript> Injection into a Closed Brine Aquifer

CO₂ injected into porous formations is accommodated by reduction in the volume of the formation fluid and enlargement of the pore space, through compression of the formation fluids and rock material, respectively. A critical issue is how the resulting pressure buildup will affect the mechanical integrity of the host formation and caprock. Building on an existing approximate solution for formations of infinite radial extent, this article presents an explicit approximate solution for estimating pressure buildup due to injection of CO₂ into closed brine aquifers of finite radial extent. The analysis is also applicable for injection into a formation containing multiple wells, in which each well acts as if it were in a quasi-circular closed region. The approximate solution is validated by comparison with vertically averaged results obtained using TOUGH2 with ECO2N (where many of the simplifying assumptions are relaxed), and is shown to be very accurate over wide ranges of the relevant parameter space. The resulting equations for the pressure distribution are explicit, and can be easily implemented within spreadsheet software for estimating CO₂ injection capacity.     

New Trapping Mechanism in Carbon Sequestration

The modes of geologic storage of CO₂ are usually categorized as structural, dissolution, residual, and mineral trapping. Here we argue that the heterogeneity intrinsic to sedimentary rocks gives rise to a fifth category of storage, which we call local capillary trapping. Local capillary trapping occurs during buoyancy-driven migration of bulk phase CO₂ within a saline aquifer. When the rising CO₂ plume encounters a region (10⁻² to 10⁺¹m) where capillary entry pressure is locally larger than average, CO₂ accumulates beneath the region. This form of storage differs from structural trapping in that much of the accumulated saturation will not escape, should the integrity of the seal overlying the aquifer be compromised. Local capillary trapping differs from residual trapping in that the accumulated saturation can be much larger than the residual saturation for the rock. We examine local capillary trapping in a series of numerical simulations. The essential feature is that the drainage curves (capillary pressure versus saturation for CO₂ displacing brine) are required to be consistent with permeabilities in a heterogeneous domain. In this work, we accomplish this with the Leverett J-function, so that each grid block has its own drainage curve, scaled from a reference curve to the permeability and porosity in that block. We find that capillary heterogeneity controls the path taken by rising CO₂. The displacement front is much more ramified than in a homogeneous domain, or in a heterogeneous domain with a single drainage curve. Consequently, residual trapping is overestimated in simulations that ignore capillary heterogeneity. In the cases studied here, the reduction in residual trapping is compensated by local capillary trapping, which yields larger saturations held in a smaller volume of pore space. Moreover, the amount of CO₂ phase remaining mobile after a leak develops in the caprock is smaller. Therefore, the extent of immobilization in a heterogeneous formation exceeds that reported in previous studies of buoyancy-driven plume movement.     

Application of X-ray CT investigation of CO<Subscript>2</Subscript>–brine flow in porous media

A clear understanding of two-phase flows in porous media is important for investigating CO₂ geological storage. In this study, we conducted an experiment of CO₂/brine flow process in porous media under sequestration conditions using X-ray CT technique. The flow properties of relative permeability, porosity heterogeneity, and CO₂ saturation were observed in this experiment. The porous media was packed with glass beads having a diameter of 0.2 mm. The porosity distribution along the flow direction is heterogeneous owing to the diameter and shape of glass beads along the flow direction. There is a relationship between CO₂ saturation and porosity distribution, which changes with different flow rates and fractional flows. The heterogeneity of the porous media influences the distribution of CO₂; moreover, gravity, fractional flows, and flow rates influence CO₂ distribution and saturation. The relative permeability curve was constructed using the steady-state method. The results agreed well with the relative permeability curve simulated using pore-network model.     

Dissolution of CO2 From Leaking Fractures in Saline Formations

Leakage of CO₂ through fractures in saline formations will increase the CO₂??brine interface and promote CO₂ dissolution. We use a 2D, finite difference MATLAB model to simulate dissolution rates from a vertical fracture, with CO₂ flowing through it, in a secondary storage formation. The instigation of convection currents increases dissolution rates leading to higher dissolution in higher Rayleigh number systems. Comparison of our results with fracture flow rates shows that for typical fracture apertures dissolution from a fracture is small relative to the amount of CO₂ flowing through the fracture. Temporal and spatial variations in fracture permeability may reduce fracture flow rates and increase the relative amount of CO₂ dissolved from the fracture compared to the CO₂ flowing through the fracture. Further work on CO₂ dissolution in relation to fracture heterogeneity, flow of CO₂ within fractures and the interaction of multiple fractures will improve our ability to predict CO₂ dissolution rates for site characterisation.     

Impact of Capillary Pressure, Salinity and In situ Conditions on CO2 Injection into Saline Aquifers

This article presents a numerical investigation of the combined effects of capillary pressure, salinity and in situ thermodynamic conditions on CO₂-brine-rock interactions in a saline aquifer. We demonstrate that the interrelations between capillary pressure, salinity, dissolution and drying-out affect CO₂ injectivity and storage capacity of a saline aquifer. High capillary forces require a high injection pressure for a given injection rate. Depending on salinity, the increase in injection pressure due to capillary forces can be offset by the dissolution of CO₂ in formation water and its compressibility. Higher capillary forces also reduce gravity segregation, and this gives a more homogeneous CO₂ plume which improves the dissolution of CO₂. The solubility of CO₂ in formation water decreases with increasing salinity which requires an increased injection pressure. Higher salinity and capillary pressure can even block the pores, causing an increased salt precipitation. Simulations with various pressure-temperature conditions and modified salinity and capillary pressure curves demonstrate that, with the injection pressures similar for both cold and warm basins at a given injection rate, CO₂ dissolves about 10% more in the warm basin water than in the cold basin. The increase in dissolution lowers the injection pressure compensating the disadvantage of low CO₂ density and compressibility for storage in warm basins.     

Influence of Permeability Heterogeneity on Miscible CO<Subscript>2</Subscript> Flooding Efficiency in Sandstone Reservoirs: An Experimental Investigation

In this study, we systematically investigate the effect of core-scale heterogeneity on the performance of miscible CO₂ flooding under various injection modes (secondary and tertiary). Manufactured heterogeneous core plugs are used to simulate vertical and horizontal heterogeneity that may be present in a reservoir. A sample with vertical heterogeneity (i.e. a layered sample) is constructed using two axially cut half plugs each with a distinctly different permeability value. In these samples, the permeability ratio (PR) defines the ratio between the permeabilities of adjacent half plugs. Horizontal heterogeneity (i.e. a composite sample) is introduced by stacking two or three short cylindrical core segments each with a different permeability value. Our special sample construction techniques have also enabled us to investigate the effect of permeability ratio and crossflow in layered samples and axial arrangement of core segments in composite samples on the ultimate recovery of the floods. Core flooding experiments are conducted with an n-Decane–brine–CO₂ system at a pore pressure of 17.2 MPa and a temperature of 343 K. At this temperature, the minimum miscibility pressure of CO₂ with n-Decane is 12.6–12.7 MPa so it is expected that at 17.2 MPa CO₂ is fully miscible with n-Decane. The results obtained for both the composite and layered samples indicate that CO₂ injection would achieve the highest recovery factor (RF) when performed under the secondary mode (e.g. layered: 79.00%, composite: 89.83%) compared with the tertiary mode (e.g. layered: 73.2%, composite: 86.2%). This may be attributed to the effect of water shielding which impedes the access of the injected CO₂ to the residual oil under the tertiary injection mode. It is also found that the oil recovery from a layered sample decreases noticeably with an increase in the PR as higher PR makes the displacement more uneven due to CO₂ channelling. The RFs of 93.4, 87.89, 77.9 and 69.8% correspond to PRs of 1, 2.5, 5, and 12.5, respectively. In addition, for the layered samples, crossflow was found to have an important role during the recovery process; however, due to excessive channelling, this effect tends to diminish as PR increases. Compared with the layered heterogeneity, the effect of composite heterogeneity on the RF seems to be very subtle as the RF is found to be almost independent from the permeability sequence along the length of a composite sample. This outcome may have been caused by the small diameter of the plugs resulting in invariable 1-D floods.     

An Extended-FEM Model for CO2 Leakage Through a Naturally Fractured Cap-Rock During Carbon Dioxide Sequestration

In this paper, a numerical model is developed for the assessment of carbon dioxide transport through naturally fractured cap-rocks during CO₂ sequestration in underground aquifers. The cap-rock contains two types of fracture with different length scales: micro-cracks (fissures) and macro-cracks (faults). The effect of micro-cracks is incorporated implicitly by modifying the intrinsic permeability tensor of porous matrix, while the macro-cracks are modeled explicitly using the extended finite element method (X-FEM). The fractured porous medium is decomposed into the porous matrix and fracture domain, which are occupied with two immiscible fluid phases, water and CO₂. The flow inside the matrix domain is governed by the Darcy law, while the flow within the fracture is modeled using the Poiseuille flow. The mass conservation law is fulfilled for each fluid phase at both porous matrix and fracture domain; moreover, the mass exchange between the matrix and fracture is guaranteed through the integral formulation of mass conservation law. Applying the X-FEM technique, the explicit representation of macro-cracks is modeled by enriching the standard finite element approximation space with an enrichment function. Finally, several numerical examples of CO₂ injection into a brine aquifer below a naturally fractured cap-rock are modeled in order to investigate the effects of cracks’ aperture and orientation as well as the temperature of aquifer and the depth of injection on the leakage pattern of the carbon dioxide through the cap-rock.

     

A Numerical Model of Tracer Transport in a Non-isothermal Two-Phase Flow System for {\text{ CO}}_2 Geological Storage Characterization

For the purpose of characterizing geologically stored $\text{ CO}_{2}Air sparging is an in situ soil/groundwater remediation technology, which involves the injection of pressurized air through air sparging well below the zone of contamination. To investigate the rate-dependent flow properties during multistep air sparging, a rule-based dynamic two-phase flow model was developed and applied to a 3D pore network which is employed to characterize the void structure of porous media. The simulated dynamic two-phase flow at the pore scale or microscale was translated into functional relationships at the continuum-scale of capillary pressure?Csaturation (P ^c?CS) and relative permeability??saturation (K _r?CS) relationships. A significant contribution from the air injection pressure step and duration time of each air injection pressure on both of the above relationships was observed during the multistep air sparging tests. It is observed from the simulation that at a given matric potential, larger amount of water is retained during transient flow than that during steady flow. Shorter the duration of each air injection pressure step, there is higher fraction of retained water. The relative air/water permeability values are also greatly affected by the pressure step. With large air injection pressure step, the air/water relative permeability is much higher than that with a smaller air injection pressure step at the same water saturation level. However, the impact of pressure step on relative permeability is not consistent for flows with different capillary numbers (N _ca). When compared with relative air permeability, relative water permeability has a higher scatter. It was further observed that the dynamic effects on the relative permeability curve are more apparent for networks with larger pore sizes than that with smaller pore sizes. In addition, the effect of pore size on relative water permeability is higher than that on relative air permeability.     

Reservoir storage and containment of greenhouse gases

This paper deals with the problem of disposal of industrial waste greenhouse gases (CO₂) into deep reservoirs. The simulator TOUGH2 was used to model the injection of 100 kg/s of CO₂ for 10 years into an aquifer 3 km deep with the object of evaluating the long-term storage prospects for this gas. Depending on the permeability structure above the injection point, some gas may escape to the surface. In the most favourable case, all of the gas dissolves into the water, and the resulting dense fluid settles in the aquifer over several thousand years. Consequently, underground storage provides a promising sink for reducing CO₂ emissions to the atmosphere.     

Enhanced CO<Subscript>2</Subscript> Storage and Sequestration in Deep Saline Aquifers by Nanoparticles: Commingled Disposal of Depleted Uranium and CO<Subscript>2</Subscript>

Geological storage of anthropogenic CO₂ emissions in deep saline aquifers has recently received tremendous attention in the scientific literature. Injected buoyant CO₂ accumulates at the top part of the aquifer under a sealing cap rock. Potential buoyant movement of CO₂ has caused some concern that the high-pressure CO₂ could breach the seal rock. However, CO₂ will diffuse into the brine underneath and generate a slightly denser fluid that may induce instability and convective mixing. Onset times of instability and convective mixing performance depend on the physical properties of the rock and fluids, such as permeability and density contrast. We present the novel idea of adding nanoparticles (NPs) to injected CO₂ to increase density contrast between the CO₂-rich brine and the underlying resident brine and, consequently, decrease onset time of instability and increase convective mixing. The analyses show that 0.001 volume fraction of NPs added to the CO₂ stream shortens onset time of mixing by approximately 80% and increases convective mixing by 50%. If it thus originally takes 5 years for the overlying CO₂ to start convective mixing, by adding NPs, onset time of mixing reduces to 1 year, and after initiation of convective mixing, mixing improves by 50%. A reduction of the CO₂ leakage risk ensues. In addition to other metallic NPs, use of processed depleted uranium oxide (DU) as the NPs is also proposed. DU-NPs are potentially stable and might be safely commingled with CO₂ to store in saline aquifers.     

Laboratory Flow Experiments for Visualizing Carbon Dioxide-Induced,Density-Driven Brine Convection

Injection of carbon dioxide (CO₂) into saline aquifers confined by low- permeability cap rock will result in a layer of CO₂ overlying the brine. Dissolution of CO₂ into the brine increases the brine density, resulting in an unstable situation in which more-dense brine overlies less-dense brine. This gravitational instability could give rise to density-driven convection of the fluid, which is a favorable process of practical interest for CO₂ storage security because it accelerates the transfer of buoyant CO₂ into the aqueous phase, where it is no longer subject to an upward buoyant drive. Laboratory flow visualization tests in transparent Hele-Shaw cells have been performed to elucidate the processes and rates of this CO₂ solute-driven convection (CSC). Upon introduction of CO₂ into the system, a layer of CO₂-laden brine forms at the CO₂-water interface. Subsequently, small convective fingers form, which coalesce, broaden, and penetrate into the test cell. Images and time-series data of finger lengths and wavelengths are presented. Observed CO₂ uptake of the convection system indicates that the CO₂ dissolution rate is approximately constant for each test and is far greater than expected for a diffusion-only scenario. Numerical simulations of our system show good agreement with the experiments for onset time of convection and advancement of convective fingers. There are differences as well, the most prominent being the absence of cell-scale convection in the numerical simulations. This cell-scale convection observed in the experiments may be an artifact of a small temperature gradient induced by the cell illumination.     

Effects of CO<Subscript>2</Subscript> Compressibility on CO<Subscript>2</Subscript> Storage in Deep Saline Aquifers

The injection of supercritical CO₂ in deep saline aquifers leads to the formation of a CO₂ plume that tends to float above the formation brine. As pressure builds up, CO₂ properties, i.e. density and viscosity, can vary significantly. Current analytical solutions do not account for CO₂ compressibility. In this article, we investigate numerically and analytically the effect of this variability on the position of the interface between the CO₂-rich phase and the formation brine. We introduce a correction to account for CO₂ compressibility (density variations) and viscosity variations in current analytical solutions. We find that the error in the interface position caused by neglecting CO₂ compressibility is relatively small when viscous forces dominate. However, it can become significant when gravity forces dominate, which is likely to occur at late times of injection.     

Effect of Well Orientation (Vertical vs. Horizontal) and Well Length on the Injection of CO<Subscript>2</Subscript> in Deep Saline Aquifers

Simulations of CO₂ injection into confined saline aquifers were conducted for both vertical and horizontal injection wells. The metrics used in quantifying the performances of different injection scenarios included changes in pressure near the injection well, mass of CO₂ dissolved into brine (solubility trapping), and storage efficiency, all evaluated with an assumed injection period of 50 years. Metrics were quantified as functions of well length, well orientation, CO₂ injection rate, and formation anisotropy (ratio of vertical to horizontal conductivity). When equal well lengths are compared, there is not a significant difference between the predicted performances of horizontal and vertical wells. However, the length of a horizontal well may exceed the length of a vertical well because the length of the horizontal well is not constrained to the vertical thickness of the geologic formation. Simulations show that, as the length of the horizontal well is allowed to increase, the geologic formation can receive a significantly higher CO₂ injection rate without exceeding a maximum allowable pressure. This result is observed in both isotropic and anisotropic formations, and suggests that horizontal wells may be advantageous under pressure-limited conditions. However, the use of horizontal wells does not significantly improve the storage efficiency, and under strongly anisotropic conditions, a vertical well provides higher storage efficiency than a horizontal well. We conclude that horizontal wells may be preferable if the goal is to sequester a large amount of CO₂ in a short period of time, but do not offer a significant advantage in terms of long-term capacity of a potential repository.