CO2 In Saline Aquifers Research Articles

ECO2N V2.0: A TOUGH2 fluid property module for modeling CO2‐H2O‐NACL systems to elevated temperatures of up to 300°C

AbstractWe have improved ECO2N, the TOUGH2 fluid property module of the CO2‐H2O‐NaCl system. The major enhancements include: (i) the upper temperature limit is increased from 110 to about 300°C; (ii) the thermophysical properties of the CO2‐rich phase are more accurately calculated as a non‐ideal mixture of CO2 and H2O; (iii) the approach to calculate the specific enthalpy of dissolved CO2 has been improved to make the code more robust in modeling phase transitions under non‐isothermal conditions; and (iv) more sophisticated models for effective heat conductivity of formations saturated with supercritical CO2 have been provided. The new module includes a comprehensive description of the thermodynamic and thermophysical properties of H2ONaClCO2 mixtures, that reproduces fluid properties largely within experimental error for the temperature, pressure and salinity conditions 10°C < T < 300°C, P < 600 bar, and salinity up to halite saturation. This includes density, viscosity, and specific enthalpy of fluid phases as functions of temperature, pressure, and composition, as well as partitioning of mass components H2O, NaCl and CO2 among the different phases. ECO2N with the TOUGH2 reservoir simulator can be applied to a wide range of problems in geologic sequestration of CO2 in saline aquifers, and in enhanced geothermal reservoirs. ECO2N can describe both sub‐ and supercritical states of CO2, but applications that involve subcritical conditions are limited to systems in which there is no change of phase between liquid and gaseous CO2, and in which no mixtures of liquid and gaseous CO2 occur. © 2016 Society of Chemical Industry and John Wiley & Sons, Ltd.

Numerical investigation on effect of varying injection scenario and relative permeability hysteresis on CO2 dissolution in saline aquifer

In subsurface storage of CO2 in saline aquifer, dissolution trapping is presumed to be the most feasible trapping mechanism that ensures storage safety by initial immobilization of injected buoyant CO2. Time span for this natural mechanism is, however, spanning in terms of decades. Accelerating the rate of dissolution by imposing various reservoir engineering principles is the peer area of research interest. Though dissolution of CO2 depends on pressure of the system, pressure buildup during injection process could potentially create or activate fractures, providing migration pathways for buoyant CO2 that questions safety of storage. Attempt has been made in the present paper to understand the impact of various injection scenarios, such as water alternate gas (WAG), intermittent and intermittent WAG injection scenario, toward enhancing dissolution rate with associated minimal effect on pressure buildup. Numerical model conceptualizing immiscible two-phase flow has been developed. Effect of hysteresis of relative permeability has been considered, and solubility of CO2 in brine is computed using developed thermodynamic model. An enhanced dissolution rate of about 68 % has been observed in case of WAG scenario, however with associated disadvantage on drastic borehole pressure buildup. On the contrary, lesser borehole pressure buildup has been observed in intermittent injection case, while dissolution rate is significantly lesser when compared with WAG process. Interestingly, it has also been inferred from present study that intermittent WAG process plays a crucial role in eliminating the primary disadvantages of WAG and intermittent process with promising enhanced dissolution rate than WAG and intermittent processes.

Modeling of pressure evolution during multiple well injection of CO2 in saline aquifers

One of the key aspects of underground carbon dioxide disposal is the injection rate. This defines the amount of CO2 to be injected into a reservoir, and is limited by reservoir fracture pressure. Therefore, it is very important to determine all parameters which contribute to pressure build up to identify optimal injection design. When injection volumes are high, the rate is split between multiple injectors, making the optimization process time consuming for numerical simulations. As such analytical or semi analytical approaches can be very useful.In this paper, a fast semi-analytical approach to evaluate pressure distribution in saline aquifers during multiple well CO2 injection is presented. It is based on general 1-D solutions of the diffusivity equation for three regions (CO2, two-phase and brine) established in aquifers when injection is done using a single well. The boundaries of a two-phase region, where both CO2 and brine coexist in pores, depend on reservoir and fluid properties and assessed using a single numerical simulation, run to match the analytical solution for pressure distribution, and these values are kept constant when extending to multiple well scenarios. Extension to multiple well injection has been conducted using the superposition principle.The results of modeling were compared with the numerical simulations including single well injection and a variety of cases of multiple well injection, with differing numbers of injectors and their placement. Different reservoir properties, such as permeability, formation compressibility as well as vertical size have been considered. Good agreement between modeling and reservoir simulations was observed for all cases.The approach presented here can be used as a pre-screening tool for fast initial evaluation of potential injection sites as well as to suggest injection design ideas and optimization of well placement.

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.

Convective dissolution of CO2 in saline aquifers: Progress in modeling and experiments

The dissolution of carbon dioxide (CO2) in deep saline aquifer water is recognized as one of the fundamental mechanisms in the subsurface for storing significant quantities of CO2. One fundamental physical effect of CO2 dissolution is the slight increase in water density in the layer in contact with the buoyant free-phase CO2 plume. Under specific conditions, this may lead to gravitational instability and the onset of free convection, significantly accelerating the dissolution of the free-phase CO2 by bringing CO2 in contact with a larger volume of aquifer water. It is also feasible to enhance CO2 dissolution using engineering methodologies such as injecting water on top of the plume of CO2. The objective of this review is to provide a perspective on the progress in modeling and experimental observations of physical aspects of CO2 dissolution in deep saline aquifers. We review the published research efforts concerning the physical effects of CO2 dissolution in formation water, the conditions under which process can be accelerated either naturally, such as by free convection, or by use of engineering methodologies, and the effects of CO2 dissolution on CO2 storage. Finally, we discuss areas in need of further research.

Scaling Analysis of the Convective Mixing in Porous Media for Geological Storage of CO2: An Experimental Approach

Prediction of the behavior of convective mixing and the effectiveness of this mechanism is essential for permanent sequestration of CO2 in deep saline aquifers. Simulation of the diffusion–convection mechanism at a large scale is very expensive and time-consuming; therefore, scaling relationships can be used to find suitable candidates for storage sites. In this study, scaling analysis is performed for the convective mixing of CO2 in saline aquifers based on experimental results. The scaling relationships are presented for the prediction of convective dissolution behavior. In the presented scaling analysis, different systems with a wide range of Rayleigh numbers were used. All experiments were conducted in a dissolution cell with different ranges of grain sizes. The pressure decay data are used to determine the dissolution rate of CO2, Sherwood number, and convective flux. In addition, the fraction of ultimate dissolution is calculated for each experiment to investigate the mixing regimes (convective mixing and diffusive mixing). The results indicate that the mixing of CO2 in water can be approximated by a scaling relationship for the Sherwood number and convective flux. These relations can be used in the implementation of large-scale CO2 storage in deep saline aquifers.

Experimental study of density-driven convection effects on CO2 dissolution rate in formation water for geological storage

Permanent storage of CO2 in saline aquifers is known as one of the best methods for carbon dioxide sequestration. Understanding the role of convection in CO2 dissolution of saline aquifers – which affects the long-term fate of the injected CO2 and the security of storage – is extremely important. In this paper, two types of experiments are performed; first, visualization experiment in Hele–Shaw cell; and second, quantitative experiments at elevated pressure. These experiments are used to investigate the effect of Density-Driven Convection (DDC) on CO2 dissolution rate in saline aquifers. For this aim; first, visualization test is performed in a Hele–Shaw cell to observe convective instabilities and its effect on dissolution rate. Afterward, quantitative tests are performed, in which four parameters are calculated: Total Dissolution, Diffusion Dissolution (DD), Convection Dissolution (CD), and CO2 Convective Flux (FCO2). Through employing these parameters, the behavior of convection and its effects on CO2 dissolution rate based on the scaled experiments is shown, and two scaling relationships one between Rayleigh and Sherwood number and the other one between CO2 Convective Flux and Rayleigh number are developed. Such scaling relationships provide an estimation of the maximum convective dissolution of CO2 in saline aquifers which would be useful for assessing suitable CO2 storage sites.

The Influence of Temperature on Chemical Fluid-Rock Reactions in Geological CO2 Sequestration

For a Bunter formation in the German Federal State of North Rhine Westphalia, we use numerical models to consider reactions between the supercritical, aqueous, and solid phases. These reactions may occur in a CO2-water system representing a saline aquifer CO2 storage scenario. Thus, the models are used for determining the extent of fluid–rock reactions during mineral dissolution or precipitation. In particular, we study the effect of temperature by comparing results for our system set at 100 °C and at 58 °C. Results show that the abundance of dissolved ions changes as a result of elevated temperature. For the entire 10,000-year simulation period, the overall geochemical behavior of the Bunter reservoir rock at the Minden site is explained in terms of different mineral transformations, although some of them are not changed significantly. This mainly comprises the alteration of carbonate minerals such as calcite, and aluminium silicates such as oligoclase, chlorite, illite, albite, kaolinite, and Na-smectite. Another chemical behavior derives from the generation and consumption of new secondary minerals such as dawsonite, pyrite, and Ca-smectite. In contrast to a system temperature of 58 °C, the mineralogical transformations of other minerals such as siderite, ankerite, dolomite, and magnesite are not observed at 100 °C. Also, the numerical simulation results show that at elevated temperature, the dominant role played by hydrodynamic mechanism dwarfs the role of other trapping mechanisms including dissolution and mineralization. Results also demonstrate how geological, petrophysical, and geochemical data can be integrated to estimate quantitatively the magnitude of the fluid–rock reactions. These reactions may entail new geotechnical problems, such as rock self-fracturing which ultimately decreases the CO2 sequestration projects security.

Completion of Five Years of Safe CO2 Injection and Transition to the Post-closure Phase at the Ketzin Pilot Site

The Ketzin pilot site for geological storage of CO2 in the German Federal State of Brandenburg about 25km west of Berlin was the first European pilot site for onshore storage of CO2 in saline aquifers. A total amount of 67 kt of CO2 was injected without any safety issues between June 2008 and August 2013 when injection ceased and the site entered the post-closure phase. Research and activities on site will continue in order to address and finally close the entire life cycle of the storage site. Within the post-closure phase the multidisciplinary monitoring program will further be applied and a stepwise abandonment of the five wells is foreseen which has already started with the partial plugging of one observation well in fall 2013.

Migration of exsolved CO2 following depressurization of saturated brines

AbstractGeologic disposal of supercritical CO2 in saline aquifers and depleted oil and gas fields will cause large volumes of brine to become saturated with dissolved CO2 at concentrations of 40 g/l or more. As CO2 dissolves in brine, the brine density increases slightly. This property favors the long‐term storage security of the CO2 because the denser brine is less likely to move upwards toward shallower depths. However, there are plausible mechanisms by which the CO2‐laden brine could be transported to a shallower depth, where the CO2 would come out of solution (exsolve), forming a mobile CO2 gas phase. Recent laboratory experiments of the exsolution process show that the CO2 phase relative permeability measured during exsolution is on the order of 1000 times lower than the relative permeability measured during a conventional CO2 core flood. Numerical simulations of upward brine migration through an open fault were performed using TOUGH2‐ECO2N with the two types of relative permeability functions. When traditional core flood relative permeabilities are used, upward flow of a CO2 saturated brine leads to exsolution and the development of a highly mobile CO2 gas phase. When relative permeabilities measured during exsolution are used, the tendency for the exsolved CO2 to migrate as a separate phase is greatly reduced, and the exsolved CO2 can partially block brine flow through the open fault. For the conditions considered, use of the exsolution relative permeability functions reduced the upward CO2 flux by about a factor of four compared to the case with core flood relative permeability functions. © 2013 Society of Chemical Industry and John Wiley & Sons, Ltd

Effects of complex sandstone–shale sequences of a storage formation on the risk of CO2 leakage: Case study from Taiwan

The purpose of this study was to develop a method for evaluating the risk of CO2 leakage, and to study the effects of complex bedded sandstone–shale sequences of a storage formation on the risk of CO2 leakage by using the case of a deep saline aquifer CO2 sequestration demonstration project in Taiwan. The risk of CO2 leakage for any kind of storage site with or without complex lithology was evaluated using the safety index (SFI), which was defined in this study and calculated from the combined contributions of all of the safe trapping mechanisms. The risk of CO2 leakage quantitatively evaluated using the SFI was dynamic over the span of CO2 storage time.The engineering strategies of maximizing the contributions of the safe trapping mechanisms can lower the risk of CO2 leakage in a storage formation with complex bedded sandstone–shale sequences by choosing an appropriate well location based on the SFI. The presence of Fe/Mg minerals lowers the risk of CO2 leakage. The transmissibility of the injection layer was not a mitigating factor for the risk of CO2 leakage. For the risk assessment of any kind of CO2 storage formation with or without complex lithologies, the best scenario should be decided based on the estimation of the SFI, which is the standard criterion used in this study.

Injection operation and operational pressure–temperature monitoring at the CO2 storage pilot site Ketzin, Germany—Design, results, recommendations

The Ketzin pilot site for geological storage of CO2 in the German Federal State of Brandenburg about 25km west of Berlin is the only German CO2 storage site and has been the first European pilot site for on-shore storage of CO2 in saline aquifers. Continuous injection of CO2 started on June 30th, 2008, and a total of 61,396t of CO2 have been injected by September 2012. The injected CO2 was predominantly food-grade with a purity>99.9%, only from May to June 2011, 1515tCO2 from the Schwarze Pumpe oxyfuel pilot plant with a purity of >99.7% have been injected. The injection is accompanied by a comprehensive operational monitoring program. The program includes continuous measurements of flow rate, fill levels of intermediate storage tanks 1 and 2, outlet pressure and temperature for the injection plant, wellhead pressures (WHP) and casing pressures 1 and 2 for all wells, bottom hole pressure (BHP), bottom hole temperature (BHT) and distributed temperature sensing (DTS) along the injection tubing for the injection well Ktzi 201, BHP for the two observation wells Ktzi 202 (from March 2010 to October 2011) and Ktzi 200 (since October 2011), and above-zone pressure monitoring in shallow observation well P300. This operational pressure–temperature monitoring successfully ensured and proved a safe, smooth and reliable injection operation. A vital part of the operational P–T data comes from the downhole P–T measurements, which are recommended for any CO2 storage site. Without this downhole information, it would not have been possible to provide the complete picture of CO2 injection. The recommended downhole installation design of P–T tools distinguishes CO2 storage from the operational engineering of underground storage of natural gas, where BHP monitoring can be done via WHP recording. The DTS safety monitoring along the injection tubing supported typical operational processes as conditioning of the CO2 and improvement of injection rate and injection temperature and will be beneficial to any CO2 storage project. The above-zone pressure monitoring gives no hints to any hydraulic connection or CO2 leakage through or failure of the cap rock.

Strength of geopolymer cured in saline water in ambient conditions

Results of geopolymer cement tests in saline water curing are reported. Saline water exposed curing is relevant to wellbore cements used for geo-sequestration of CO2 in saline aquifer. The conventional Portland cement based oil well cements have unfavourable results when cured in saline water. However, geopolymer based cements cured in saline water showed higher strength results than the ones cured in normal water. The reason for this behaviour is not readily apparent, and hence microstructure investigations, namely, scanning electron microscopy, Energy-dispersive X-ray spectroscopy and X-ray diffraction were performed. Saline water cured geopolymer samples also were found to have lower sorptivity test results than normal water cured samples. Improved properties of geopolymers when cured in saline water is found to be related to reduced leaching of reactants from the samples rather than the result of ingress of saline water into the samples. Geopolymers tested are made from fly ash with small amount of slag (9%), and were cured at room temperature.

Influence of Capillary Pressure and Injection Rate as well as Heterogeneous and Anisotropic Permeability on CO2 Transport and Displacement Efficiency in Water-Saturated Porous Media

Greenhouse gas emission from industrial production and human living has been widely recognized as one of the primary reasons which cause global climate warming. CO2 sequestration in saline aquifers plays an important role in effectively reducing the greenhouse gas emission. Numerical modeling can be used to quantitatively analyze the effect of some formation properties on the storage processes of CO2 in saline aquifers. Magnetic resonance imaging (MRI) technology may be used to observe the evolution of CO2 plume through time in porous rocks and hence provide an effective means for validate the reliability of the numerical modeling. Based on a combined use of the numerical modeling and the MRI measurement of the vertical injection of the supercritical CO2 into water-saturated rock cores, this study presents a lab-scale investigation on the influence of the heterogeneous and anisotropic permeability, the CO2 injection rate and capillary pressure on the transport of CO2 plume as well as the CO2 utilization efficiency of subsurface space in saline aquifers. Our results indicate: 1) both the heterogeneity and the anisotropy of permeability can enhance the CO2 displacement efficiency. Ignoring these two permeability properties can cause the obvious deviation in the predicted CO2 saturation and transport processes by the model; 2) the enhanced sequestration efficiency by the anisotropy depends on the degree and spatial extension of itself. If the approximately stochastically distributed permeability anisotropy represents natural conditions, specifying the constant ratio of the vertical permeability to the horizontal one in the model to mimic the real permeability can lead to the obvious over-estimation of the CO2 displacement efficiency. Besides, the displacement front of the CO2 plume tends to pass through the region with the higher vertical permeability, thus forming the anomalistic shape of the displacement front; 3) the capillary pressure can influence the CO2 utilization efficiency in the rock core significantly, and tends to inhibit the movement of pore water, which accordingly lowers the CO2 displacement efficiency; 4) the CO2 injection rate can largely affect the CO2 displacement efficiency. The final CO2 saturation of CO2 in the rock core is notably enhanced with the increasing injection rate.

Geothermal Energy Production at Geologic CO2 Sequestration sites: Impact of Thermal Drawdown on Reservoir Pressure

Recent geotechnical research shows that geothermal heat can be efficiently mined by circulating carbon dioxide through naturally permeable rock formations -- a method called CO2 Plume Geothermal -- the same geologic reservoirs that are suitable for deep saline aquifer CO2 sequestration or enhanced oil recovery. This paper describes the effect of thermal drawdown on reservoir pressure buildup during sequestration operations, revealing that geothermal heat mining can decrease overpressurization by 10% or more.

Relative permeability and non-wetting phase plume migration in vertical counter-current flow settings

In this work, we investigate the impact of co-current to counter-current flow reversals on the migration dynamics of a non-wetting phase plume in a porous medium. The presented results and observations have direct application to CO2 injection into saline aquifers where a less dense CO2-rich plume migrates during and following the injection period. Counter-current gravity segregation experiments were performed in a vertical glass-bead pack with brine and iC8 as analog fluids to mimic the behavior of a CO2/brine system of relevance to CO2 sequestration processes. Four-electrode resistivity measurements were used to monitor the migration of the non-wetting phase (iC8) by relating the resistivity index (RI) to the brine saturation. The observations are compared with numerical calculations to demonstrate that standard co-current relative permeability measurements are inadequate to reproduce the experimental observations. A reduction in the relative permeability of both phases, in particular for the non-wetting phase, is required to improve the agreement between experimental observations and numerical calculations. Numerical calculations based on co-current input data predicts a much faster migration of the non-wetting phase to the top of the column than what is observed in the segregation experiments. Our findings demonstrate that counter-current flow affects the phase's mobilities, because of interfacial coupling, and should therefore be considered in the modeling of injection/storage of CO2 in saline aquifers: simulation of CO2/brine dynamics based on co-current relative permeability measurements is likely to render estimates of migration time/distance in significant error.

Continuum-scale convective mixing in geological CO2 sequestration in anisotropic and heterogeneous saline aquifers

Deep saline aquifers are important geological formations for CO2 sequestration. It has been known that dissolution of CO2 increases brine density, which results in downward density-driven convection and consequently greatly enhances CO2 sequestration. In this study, a continuum-scale lattice Boltzmann model is used to investigate convective mixing of CO2 in saline aquifers. It is found that increasing permeability in either the vertical or horizontal direction accelerates the development of convective mixing. In a heterogeneous aquifer, increasing heterogeneity hampers the onset of convective mixing, because the heterogeneous permeability field results in a large portion of low-velocity region which reduces the instability of the system. The critical time for the onset of instability depends mainly on the coefficient of variation (COV) of the permeability field, and is insensitive to the correlation length. This implies that within the scale of critical time, mass transport is dominated by diffusion, and thus depends mainly on fine-scale heterogeneity controlled by COV. We derived an empirical formula for estimating the critical time, which leads to good estimates for all combinations of COV and correlation length. Fingering, channeling, and dispersion are the three mechanisms for mass transport. In dispersion, dissolved mass is approximately proportional to the square root of time, while in fingering and channeling it is approximately proportional to time. Mass transport by channeling depends significantly on permeability structure, while by fingering it is controlled by gravitational instability. It is also found that larger volumes of CO2 can be stored in heterogeneous aquifers because of higher mass dissolution rates.

Effect of fluctuations on the onset of density-driven convection in porous media

We study the dissolution of CO2 in saline aquifers. The long diffusion times can be accelerated by orders of magnitude from mass transfer that origins from convection. Convection occurs at a critical time via a phase transition from the horizontally homogeneous diffusion state. To start the instability, perturbations that break the horizontal translation symmetry are necessary. We start with the basic equations and the boundary conditions, examine the linearized equations around the diffusive time and z-dependent base state and compare different definitions of the critical time found in the literature. Taking a simple model we show the role of fluctuations for delayed instabilities if the control parameter is slowly swept through the bifurcation point. Apart from the critical time we use a “visible” time where convection is manifested in the vertical CO2 transport. We specify the perturbations with respect to their strength and length scale, and compute the critical times for various cases by numerical integration of the basic equations in two spatial dimensions. Fluctuating concentration at the upper boundary, fluctuating porosity as well fluctuating permeability are studied in detail. For the permeability fluctuation, the compressibility of the fluid becomes important and the velocity field cannot be derived from a stream function. Our work also includes non-isothermal conditions with a prescribed vertical geothermal gradient and space dependent thermal conductivity. Temperature fields for different standard configurations are computed numerically and serve as starting condition for density-driven convection. Based on our work, we conclude that the visible time is much larger than the critical time. The visible time is a strong function of strength and length scale of the perturbations.

Effect of reactive surface area of minerals on mineralization trapping of CO2 in saline aquifers

The reactive surface area, an important parameter controlling mineral reactions, affects the amount of mineralization trapping of CO2 which affects the long-term CO2 storage. The effect of the reactive surface area on the mineralization trapping of CO2 was numerically simulated for CO2 storage in saline aquifers. Three kinds of minerals, including anorthite, calcite and kaolinite, are involved in the mineral reactions. This paper models the relationship between the specific surface area and the grain diameter of anorthite based on experimental data from literature (Brantley and Mellott, 2000). When the reactive surface areas of anorthite and calcite decrease from 838 to 83.8 m2/m3, the percentage of mineralization trapping of CO2 after 500 years decreases from 11.8% to 0.65%. The amount of dissolved anorthite and the amounts of precipitated kaolinite and calcite decrease significantly when the reactive surface areas of anorthite and calcite decrease from 838 to 83.8 m2/m3. Calcite is initially dissolved in the brine and then precipitates during the geochemical reactions between CO2-H2O and the minerals. Different reactive surface areas of anorthite and calcite lead to different times from dissolution to precipitation. The pH of the brine decreases with decreasing reactive surface areas of anorthite and calcite which influences the acidity of the saline aquifer. The gas saturation between the upper and lower parts of the saline aquifer increases with decreasing reactive surface areas of anorthite and calcite. The mass density distribution of brine solution shows that the CO2+brine solution region increases with decreasing reactive surface areas of anorthite and calcite.

Reactive transport simulation study of geochemical CO2 trapping on the Tokyo Bay model – With focus on the behavior of dawsonite

A long-term (up to 10ka) geochemical change in saline aquifer CO2 storage was studied using the TOUGHREACT simulator, on a 2-dimensional, 2-layered model representing the underground geologic and hydrogeologic conditions of the Tokyo Bay area that is one of the areas of the largest CO2 emissions in the world. In the storage system characterized by low permeability of reservoir and cap rock, the dominant storage mechanism is found to be solubility trapping that includes the dissolution and dissociation of injected CO2 in the aqueous phase followed by geochemical reactions to dissolve minerals in the rocks. The CO2–water–rock interaction in the storage system (mainly in the reservoir) changes the properties of water in a mushroom-like CO2 plume, which eventually leads to convective mixing driven by gravitational instability. The geochemically evolved aqueous phase precipitates carbonates in the plume front due to a local rise in pH with mixing of unaffected reservoir water. The carbonate precipitation occurs extensively within the plume after the end of its enlargement, fixing injected CO2 in a long, geologic period.Dawsonite, a Na–Al carbonate, is initially formed throughout the plume from consumption of plagioclase in the reservoir rock, but is found to be a transient phase finally disappearing from most of the CO2-affected part of the system. The mineral is unstable relative to more common types of carbonates in the geochemical evolution of the CO2 storage system initially having formation water of relatively low salinity. The exception is the reservoir-cap rock boundary where CO2 saturation remains very high throughout the simulation period.