Injection and Storage of CO<Subscript>2</Subscript> in Deep Saline Aquifers: Analytical Solution for CO<Subscript>2</Subscript> Plume Evolution During Injection

Injection of fluids into deep saline aquifers is practiced in several industrial activities, and is being considered as part of a possible mitigation strategy to reduce anthropogenic emissions of carbon dioxide into the atmosphere. Injection of CO₂ into deep saline aquifers involves CO₂ as a supercritical fluid that is less dense and less viscous than the resident formation water. These fluid properties lead to gravity override and possible viscous fingering. With relatively mild assumptions regarding fluid properties and displacement patterns, an analytical solution may be derived to describe the space–time evolution of the CO₂ plume. The solution uses arguments of energy minimization, and reduces to a simple radial form of the Buckley–Leverett solution for conditions of viscous domination. In order to test the applicability of the analytical solution to the CO₂ injection problem, we consider a wide range of subsurface conditions, characteristic of sedimentary basins around the world, that are expected to apply to possible CO₂ injection scenarios. For comparison, we run numerical simulations with an industry standard simulator, and show that the new analytical solution matches a full numerical solution for the entire range of CO₂ injection scenarios considered. The analytical solution provides a tool to estimate practical quantities associated with CO₂ injection, including maximum spatial extent of a plume and the shape of the overriding less-dense CO₂ front.     

Effect of Vertical Heterogeneity on Long-Term Migration of CO<Subscript>2</Subscript> in Saline Formations

For deep injection of CO₂ in thick saline formations, the movements of both the free gas phase and dissolved CO₂ are sensitive to variations in vertical permeability. A simple model for vertical heterogeneity was studied, consisting of a random distribution of horizontal impermeable barriers with a given overall volume fraction and distribution of lengths. Analytical results were obtained for the distribution of values for the permeability, and compared to numerical simulations of deep CO₂ injection and convection in heterogeneous formations, using multiple realizations for the permeability distribution. It is shown that for a formation of thickness H, the breakthrough times in two dimensions for deep injection scale as H ² for moderate injection rates. In comparison to heterogeneous shale distributions, a homogeneous medium with equivalent effective vertical permeability has a longer breakthrough time for deep injection, and a longer onset time for convection.     

Stability of a fluid in a horizontal saturated porous layer: effect of non-linear concentration profile, initial, and boundary conditions

Carbon dioxide injected into saline aquifers dissolves in the resident brines increasing their density, which might lead to convective mixing. Understanding the factors that drive convection in aquifers is important for assessing geological CO₂ storage sites. A hydrodynamic stability analysis is performed for non-linear, transient concentration fields in a saturated, homogenous, porous medium under various boundary conditions. The onset of convection is predicted using linear stability analysis based on the amplification of the initial perturbations. The difficulty with such stability analysis is the choice of the initial conditions used to define the imposed perturbations. We use different noises to find the fastest growing noise as initial conditions for the stability analysis. The stability equations are solved using a Galerkin technique. The resulting coupled ordinary differential equations are integrated numerically using a fourth-order Runge–Kutta method. The upper and lower bounds of convection instabilities are obtained. We find that at high Rayleigh numbers, based on the fastest growing noise for all boundary conditions, both the instability time and the initial wavelength of the convective instabilities are independent of the porous layer thickness. The current analysis provides approximations that help in screening suitable candidates for homogenous geological CO₂ sequestration sites.     

Numerical Simulations of the Thermal Impact of Supercritical CO<Subscript>2</Subscript> Injection on Chemical Reactivity in a Carbonate Saline Reservoir

Geological sequestration of CO₂ offers a promising solution for reducing net emissions of greenhouse gases into the atmosphere. This emerging technology must make it possible to inject CO₂ into deep saline aquifers or oil- and gas-depleted reservoirs in the supercritical state (P > 7.4MPa and T > 31.1°C) to achieve a higher density and therefore occupy less volume underground. Previous experimental and numerical simulations have demonstrated that massive CO₂ injection in saline reservoirs causes a major disequilibrium of the physical and geochemical characteristics of the host aquifer. The near-well injection zone seems to constitute an underground hydrogeological system particularly impacted by supercritical CO₂ injection and the most sensitive area, where chemical phenomena (e.g. mineral dissolution/precipitation) can have a major impact on the porosity and permeability. Furthermore, these phenomena are highly sensitive to temperature. This study, based on numerical multi-phase simulations, investigates thermal effects during CO₂ injection into a deep carbonate formation. Different thermal processes and their influence on the chemical and mineral reactivity of the saline reservoir are discussed. This study underlines both the minor effects of intrinsic thermal and thermodynamic processes on mineral reactivity in carbonate aquifers, and the influence of anthropic thermal processes (e.g. injection temperature) on the carbonates’ behaviour.     

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.     

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.     

Onset of instability in CO2 sequestration into saline aquifer: scaling relationship and the effect of perturbed boundary

Storage and disposal of greenhouse gases in saline aquifers is an important solution for reduction of these gases from atmosphere. Understanding the concepts and mechanisms involved in the storage process, especially natural convection and their impact on long-term fate of injected CO₂ are essential. Natural convection is an effective mechanism which increases solubility of carbon dioxide in the storage process. In this work, injection of carbon dioxide into aquifer is numerically simulated. First, numerical criteria are developed to provide numerical accuracy and stability by mesh resolution. Then, changes in input wave number in surface perturbation and order of element used in finite element method were analyzed. It was found that depending on Rayleigh number, there is a wave number at which instability occurs earlier and grows faster. Also, onset of CO₂ convective mixing in saline aquifers was obtained and correlated for a number of field cases. Results show that onset of convection can be approximated by a scaling relationship for dimensionless time as a function of inverse square of Rayleigh number, Ra ^?2, for Rayleigh range used in this work. This scaling relationship provides a predictive tool for onset of convection and also long-term fate of disposed CO₂ in large scale geological sequestration.     

The Footprint of the CO<Subscript>2</Subscript> Plume during Carbon Dioxide Storage in Saline Aquifers: Storage Efficiency for Capillary Trapping at the Basin Scale

We study a sharp-interface mathematical model of CO₂ 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 CO₂ 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 CO₂ plume, and the time scale required for complete trapping. The capillary trapping coefficient and the mobility ratio between CO₂ and brine emerge as the key parameters in the assessment of CO₂ 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.     

Quantification of Density-Driven Natural Convection for Dissolution Mechanism in CO<Subscript>2</Subscript> Sequestration

Dissolution of CO₂ into brine causes the density of the mixture to increase. The density gradient induces natural convection in the liquid phase, which is a favorable process of practical interest for CO₂ storage. Correct estimation of the dissolution rate is important because the time scale for dissolution corresponds to the time scale over which free phase CO₂ has a chance to leak out. However, for this estimation, the challenging simulation on the basis of convection–diffusion equation must be done. In this study, pseudo-diffusion coefficient is introduced which accounts for the rate of mass transferring by both convection and diffusion mechanisms. Experimental tests in fluid continuum and porous media were performed to measure the real rate of dissolution of CO₂ into water during the time. The pseudo diffusion coefficient of CO₂ into water was evaluated by the theory of pressure decay and this coefficient is used as a key parameter to quantify the natural convection and its effect on mass transfer of CO₂. For each experiment, fraction of ultimate dissolution is calculated from measured pressure data and the results are compared with predicted values from analytical solution. Measured CO₂ mass transfer rate from experiments are in reasonable agreement with values calculated from diffusion equation performed on the basis of pseudo-diffusion coefficient. It is suggested that solving diffusion equation with pseudo diffusion coefficient herein could be used as a simple and rapid tool to calculate the rate of mass transfer of CO₂ in CCS projects.     

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.     

Modeling of CO<Subscript>2</Subscript> Leakage up Through an Abandoned Well from Deep Saline Aquifer to Shallow Fresh Groundwaters

This article presents a numerical modeling application using the code TOUGHREACT of a leakage scenario occurring during a CO₂ geological storage performed in the Jurassic Dogger formation in the Paris Basin. This geological formation has been intensively used for geothermal purposes and is now under consideration as a site for the French national program of reducing greenhouse gas emissions and CO₂ geological storage. Albian sandstone, situated above the Dogger limestone is a major strategic potable water aquifer; the impacts of leaking CO₂ due to potential integrity failure have, therefore, to be investigated. The present case–study illustrates both the capacity and the limitations of numerical tools to address such a critical issue. The physical and chemical processes simulated in this study have been restricted to: (i) supercritical CO₂ injection and storage within the Dogger reservoir aquifer, (ii) CO₂ upwards migration through the leakage zone represented as a 1D vertical porous medium to simulate the cement–rock formation interface in the abandoned well, and (iii) impacts on the Albian aquifer water quality in terms of chemical composition and the mineral phases representative of the porous rock by estimating fluid–rock interactions in both aquifers. Because of CPU time and memory constraints, approximation and simplification regarding the geometry of the geological structure, the mineralogical assemblages and the injection period (up to 5 years) have been applied to the system, resulting in limited analysis of the estimated impacts. The CO₂ migration rate and the quantity of CO₂ arriving as free gas and dissolving, firstly in the storage water and secondly in the water of the overlying aquifer, are calculated. CO₂ dissolution into the Dogger aquifer induces a pH drop from about 7.3 to 4.9 limited by calcite dissolution buffering. Glauconite present in the Albian aquifer also dissolves, causing an increase of the silicon and aluminum in solution and triggering the precipitation of kaolinite and quartz around the intrusion point. A sensitivity analysis of the leakage rate according to the location of the leaky well and the variability of the petro-physical properties of the reservoir, the leaky well zone and the Albian aquifers is also provided.     

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.     

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.     

Modeling Gas Transport in the Shallow Subsurface During the ZERT CO<Subscript>2</Subscript> Release Test

We used the multiphase and multicomponent TOUGH2/EOS7CA model to carry out predictive simulations of CO₂ injection into the shallow subsurface of an agricultural field in Bozeman, Montana. The purpose of the simulations was to inform the choice of CO₂ injection rate and design of monitoring and detection activities for a CO₂ release experiment. The release experiment configuration consists of a long horizontal well (70 m) installed at a depth of approximately 2.5 m into which CO₂ is injected to mimic leakage from a geologic carbon sequestration site through a linear feature such as a fault. We estimated the permeability of the soil and cobble layers present at the site by manual inversion of measurements of soil CO₂ flux from a vertical-well CO₂ release. Based on these estimated permeability values, predictive simulations for the horizontal well showed that CO₂ injection just below the water table creates an effective gas-flow pathway through the saturated zone up to the unsaturated zone. Once in the unsaturated zone, CO₂ spreads out laterally within the cobble layer, where liquid saturation is relatively low. CO₂ also migrates upward into the soil layer through the capillary barrier and seeps out at the ground surface. The simulations predicted a breakthrough time of approximately two days for the 100kg d⁻¹ injection rate, which also produced a flux within the range desired for testing detection and monitoring approaches. The seepage area produced by the model was approximately five meters wide above the horizontal well, compatible with the detection and monitoring methods tested. For a given flow rate, gas-phase diffusion of CO₂ tends to dominate over advection near the ground surface, where the CO₂ concentration gradient is large, while advection dominates deeper in the system.     

Evaluation of Potential Changes in Groundwater Quality in Response to CO<Subscript>2</Subscript> Leakage from Deep Geologic Storage

Concern has been expressed that carbon dioxide (CO₂) leaking from deep geological storage could adversely impact water quality in overlying potable aquifers by mobilizing hazardous trace elements. In this article, we present a systematic evaluation of the possible water quality changes in response to CO₂ intrusion into aquifers currently used as sources of potable water in the United States. The evaluation was done in three parts. First, we developed a comprehensive geochemical model of aquifers throughout the United States, evaluating the initial aqueous abundances, distributions, and modes of occurrence of selected hazardous trace elements in a large number of potable groundwater quality analyses from the National Water Information System (NWIS) database. For each analysis, we calculated the saturation indices (SIs) of several minerals containing these trace elements. The minerals were initially selected through literature surveys to establish whether field evidence supported their postulated presence in potable water aquifers. Mineral assemblages meeting the criterion of thermodynamic saturation were assumed to control the aqueous concentrations of the hazardous elements at initial system state as well as at elevated CO₂ concentrations caused by the ingress of leaking CO₂. In the second step, to determine those hazardous trace elements of greatest concern in the case of CO₂ leakage, we conducted thermodynamic calculations to predict the impact of increasing CO₂ partial pressures on the solubilities of the identified trace element mineral hosts. Under reducing conditions characteristic of many groundwaters, the trace elements of greatest concern are arsenic (As) and lead (Pb). In the final step, a series of reactive-transport simulations was performed to investigate the chemical evolution of aqueous As and Pb after the intrusion of CO₂ from a storage reservoir into a shallow confined groundwater resource. Results from the reactive-transport model suggest that a significant increase of aqueous As and Pb concentrations may occur in response to CO₂ intrusion, but that the maximum concentration values remain below or close to specified maximum contaminant levels (MCLs). Adsorption/desorption from mineral surfaces may strongly impact the mobilization of As and Pb.     

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.     

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.     

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 Injection into Saline Carbonate Aquifer Formations II: Comparison of Numerical Simulations to Experiments

Sequestration of carbon dioxide in geological formations is an alternative way of managing extra carbon. Although there are a number of mathematical modeling studies related to this subject, experimental studies are limited and most studies focus on injection into sandstone reservoirs as opposed to carbonate ones. This study describes a fully coupled geochemical compositional equation-of-state compositional simulator (STARS) for the simulation of CO₂ storage in saline aquifers. STARS models physical phenomena including (1) thermodynamics of sub- and supercritical CO₂, and PVT properties of mixtures of CO₂ with other fluids, including (saline) water; (2) fluid mechanics of single and multiphase flow when CO₂ is injected into aquifers; (3) coupled hydrochemical effects due to interactions between CO₂, reservoir fluids, and primary mineral assemblages; and (4) coupled hydromechanical effects, such as porosity and permeability change due to the aforementioned blocking of pores by carbonate particles and increased fluid pressures from CO₂ injection. Matching computerized tomography monitored laboratory experiments showed the uses of the simulation model. In the simulations dissolution and deposition of calcite as well as adsorption of CO₂ that showed the migration of CO₂ and the dissociation of CO₂ into HCO₃ and its subsequent conversion into carbonate minerals were considered. It was observed that solubility and hydrodynamic storage of CO₂ is larger compared to mineral trapping.     

Modeling of Rocks and Cement Alteration due to CO<Subscript>2</Subscript> Injection in an Exploited Gas Reservoir

The injection of CO₂ in exploited natural gas reservoirs as a means to reduce greenhouse gas (GHG) emissions is highly attractive as it takes place in well-known geological structures of proven integrity with respect to gas leakage. The injection of a reactive gas such as CO₂ puts emphasis on the possible alteration of reservoir and caprock formations and especially of the wells’ cement sheaths induced by the modification of chemical equilibria. Such studies are important for injectivity assurance, wellbore integrity, and risk assessment required for CO₂ sequestration site qualification. Within a R&D project funded by Eni, we set up a numerical model to investigate the rock–cement alterations driven by the injection of CO₂ into a depleted sweet natural gas pool. The simulations are performed with the TOUGHREACT simulator (Xu et al. in Comput Geosci 32:145–165, 2006) coupled to the TMGAS EOS module (Battistelli and Marcolini in Int J Greenh Gas Control 3:481–493, 2009) developed for the TOUGH2 family of reservoir simulators (Pruess et al. in TOUGH2 User’s Guide, Version 2.0, 1999). On the basis of field data, the system is considered in isothermal (50°C) and isobaric (128.5 bar) conditions. The effects of the evolving reservoir gas composition are taken into account before, during, and after CO₂ injection. Fully water-saturated conditions were assumed for the cement sheath and caprock domains. The gas phase does not flow by advection from the reservoir into the interacting domains so that molecular diffusion in the aqueous phase is the most important process controlling the mass transport occurring in the system under study.