Numerical Study of CO₂ Geological Storage in Saline Aquifers without the Risk of Leakage

Abstract

The purpose of this study is to reduce the risk of leakage of CO₂ geological storage by injecting the dissolved CO₂ solution instead of the supercritical CO₂ injection. The reservoir simulation method is used in this study to evaluate the contributions of the different trapping mechanisms, and the safety index method is used to evaluate the risk of CO₂ leakage. The function of the dissolved CO₂ solution injection is performed by a case study of a deep saline aquifer. Two scenarios are designed in this study: the traditional supercritical CO₂ injection and the dissolved CO₂ solution injection. The contributions of different trapping mechanisms, plume migrations, and the risk of leakage are evaluated and compared. The simulation results show that the risk of leakage via a natural pathway can be decreased by the approach of injecting dissolved CO₂ solution instead of supercritical CO₂. The amount of the CO₂ retained by the safe trapping mechanisms in the dissolved CO₂ solution injection scenario is greater than that in the supercritical CO₂ scenario. The process of CO₂ mineralization in the dissolved CO₂ solution injection scenario is also much faster than that in the supercritical CO₂ scenario. Changing the injection fluid from supercritical CO₂ to a dissolved CO₂ solution can significantly increase the safety of the CO₂ geological storage. The risk of CO₂ leakage from a reservoir can be eliminated because the injected CO₂ can be trapped totally by safe trapping mechanisms.

1. Introduction

Since the Industrial Revolution, the consumption of fossil fuels in transportation, industrial, electrical, and other sectors has resulted in a large increase in greenhouse gas emissions, thereby promoting environmental disasters, such as global warming. To promote environmental protection and to halt the consequences of climate change, remediation techniques are required to reduce anthropogenic CO₂ emissions to keep the rise in global temperatures below 2 °C above pre-industrial temperatures in the 21st century. Carbon capture and storage (CCS) is one of the solutions. CCS is a practical approach to cut down CO₂ emissions by means of a series of technologies, including the capture, transportation, and storage of CO₂. Deep saline aquifers have the largest CO₂ storage capacity in the geological storage options.

The most important issue for the CO₂ geological storage is the risk of leakage. For the storage to be, the risk of any leakage should be controlled to as low as possible. The evaluation of the risk of leakage is essential for public acceptance and public policy [1,2]. The risk of leakage can be reduced by a safe injection strategy with understanding the functions of different trapping mechanisms.

The traditional injection strategy is the supercritical CO₂ injection, i.e., CO₂ is injected into a reservoir as a mobile supercritical phase. The injected supercritical CO₂ is trapped below a non-permeable cap-rock in the beginning; this is structural trapping. The injected supercritical CO₂ plume migrates upward due to its buoyancy. The mobility of the supercritical CO₂ creates a higher risk of leakage for the CO₂ storage because, in this mechanism, it relies on the containment of the storage system. However, in the post-injection period, the residual gas, solubility, and mineralization trapping mechanisms will work to improve the safety of the storage since these trappings make the stored CO₂ as an immobile phase to effectively lower the risk of leakage [3,4,5].

An alternative method of CO₂ storage to the traditional supercritical CO₂ injection has been discussed in recent years. A novel method of CO₂ storage based on injecting a dissolved CO₂ solution has been proposed. CO₂ is dissolved in water, which is extracted from an aquifer at a surface facility before injection [6]. However, the CO₂ dissolution procedure at the surface facility requires compressing the water at high pressure and may cause unaffordable energy and costs. An alternative strategy of dissolving CO₂ involves the production of brine from the reservoir, followed by a re-injection where the brine mixes with the CO₂ in the wellbore of the injection well at a certain depth [7]. Significant advantages are attained by injecting CO₂ as a saturated solution with the brine [8].

When the CO₂ is dissolved in water, the density of the CO₂ solution is greater than that of the formation water. The CO₂ solution naturally sinks in the aquifer due to the gravity effect, and this can reduce the risk of leakage because the plume is moving away from the top of the reservoir (moving downward). Recently, research has been conducted concerning the injection of dissolved CO₂ solution into igneous rock (e.g., basalt). Instead of supercritical CO₂, CO₂ the dissolved in geothermal wastewater was injected into and stored in the formation. Because basaltic rocks are rich in calcium, magnesium, and iron (while also being more reactive in formation water than sedimentary rock), the bulk of the CO₂ is trapped by mineral trapping within a few years instead of thousands of years [9,10,11]. After the stored CO₂ transforms into carbonate minerals, the risk of CO₂ leakage can be eliminated, thereby enhancing the storage safety and public acceptance of this solution.

The whole process of transforming the CO₂ phase through a different trapping mechanism plays an essential role in evaluating the risk of CO₂ leakage, no matter whether it is in the traditional supercritical CO₂ injection or the dissolved CO₂ solution injection. This is the first paper to discuss the differences in the trapping mechanisms between injecting the dissolved CO₂ and injecting supercritical CO₂ into a reservoir in sedimentary basins. Because the difference in the process of trapping mechanisms would affect the mobility of stored CO₂ and the leakage risk, the differences in injecting different fluid should be discussed. Sedimentary rock is less rich in calcium, magnesium, and iron than igneous rock, but the transformation of the injected dissolved CO₂ into carbonate minerals can still be faster than that achieved by the traditional supercritical CO₂ injection because the solubility trapping mechanism can occur immediately in the reservoir.

Therefore, the purpose of this research is to study the elimination of the risk of leakage of CO₂ geological storage by injecting the dissolved CO₂ solution instead of the supercritical CO₂ injection. Specifically, the transformation process of trapping mechanisms of the different injected phase CO₂ in a sedimentary basin is discussed in this study. The contributions of the different trapping mechanisms are evaluated by the reservoir simulation, and the risk of CO₂ leakage is estimated from the safety index method. This study uses a case study to perform the function of the dissolved CO₂ solution injection in a deep saline aquifer. The traditional supercritical CO₂ injection and the dissolved CO₂ solution injection scenarios are designed in this study, and the contributions of different trapping mechanisms, plume migrations, and the risk of leakage are evaluated and compared.

2. Methodology

To effectively assess the leakage risk of CO₂ storage, the safety index (SFI) was used in this study. The SFI was estimated by the dynamic number of moles of CO₂ retained by the trapping mechanisms after CO₂ had been injected into the target reservoir. The safety index was defined as [12]:

$$SFI=(n_{C{O}_{2(res)}}+n_{C{O}_{2(aq)}}+n_{C{O}_{2(ion)}}+n_{C{O}_{2(\min )}})/n_{C{O}_{2(inj)}}$$

(1)

where $n_{C{O}_{2(res)}}$ is the number of moles of the CO₂ retained by the residual gas mechanism as immobile supercritical phase; $n_{C{O}_{2(aq)}}$ is the number of moles of the CO₂ retained by the solubility trapping mechanism; $n_{C{O}_{2(ion)}}$ is the moles of the CO₂ retained by the ionic trapping mechanism; $n_{C{O}_{2(min)}}$ is the number of moles of the CO₂ retained by the mineral trapping mechanism, and $n_{C{O}_{2(inj)}}$ is the number of moles of injected CO₂.

The residual gas trapping mechanism plays an essential role in trapping supercritical CO₂ in a saline aquifer. In the porous media, supercritical CO₂ can be trapped by capillary and wettability effects as an immobile phase [13,14]. When the imbibition curve is different from the drainage curve for the relative permeability of the gas (k_rg), the residual gas exists. In this study, the imbibition and drainage curves of the relative permeability of the gas were designed using Land’s model [15]. For the solubility trapping mechanism, the solubility of gas in the water is important because a large amount of CO₂ is able to be dissolved in the saline. Because the dissolution rate of the gas phase in the aqueous phase is rapid, the aqueous and gas phase are able to be assumed to be in thermodynamic equilibrium. The solubility trapping mechanism in a saline aquifer can be modeled by the phase equilibrium controlled by the equivalent fugacities between the aqueous (f_maq) and gas phases (f_mg):

$${\mathrm{f}}_{\mathrm{m}\mathrm{g}}={\mathrm{f}}_{\mathrm{m}\mathrm{a}\mathrm{q}},\mathrm{m}=1,\dots ,{\mathrm{N}}_{\mathrm{c}}$$

(2)

The Peng–Robinson equation of state (PR-EOS) was adopted to compute the gas fugacity, f_mg, of component m [16]. The fugacity of component m in the aqueous phase, f_maq, can be computed by Henry’s law:

$${\mathrm{f}}_{\mathrm{m}\mathrm{a}\mathrm{q}}={\mathrm{y}}_{\mathrm{m}\mathrm{a}\mathrm{q}}\cdot {\mathrm{H}}_{\mathrm{m}}$$

(3)

where H_m is Henry’s law constant (atm·L/mol) for component m at a given p and T.

Henry’s constant, which is affected by the temperature, pressure, and salinity of the saline, can be normally expressed as follows at a constant temperature:

$$\ln {\mathrm{H}}_{\mathrm{m}}=\ln {\mathrm{H}}_{\mathrm{m}}^{*}+\frac{\overline{{\mathrm{v}}_{\mathrm{m}}}(\mathrm{p}-{\mathrm{p}}^{*})}{\mathrm{R}\mathrm{T}})$$

(4)

where H_m* is the Henry’s law constant (atm·L /mol) of component m at p* and T; R is the gas constant; and $\overline{{\mathrm{v}}_{\mathrm{m}}}$ is the partial molar volume of component m in solution.

The chemical reactions that take place between components in the aqueous phase and between carbonate minerals and aqueous CO₂ are crucial in this study. The components in the aqueous phase were composed of soluble gas components, N_c, and components that only exist in the aqueous phase, N_a. It may be assumed that N_m is the number of mineral components, N_aq is the number of components in the aqueous phase (N_aq = N_c + N_a), and N_ct is the total number of components (N_ct = N_aq + N_m). The chemical reaction in the aqueous phase between species has the stoichiometry of [14]:

$${\displaystyle \sum _{\mathrm{k}=1}^{{\mathrm{N}}_{\mathrm{a}\mathrm{q}}}{\mathrm{v}}_{\mathrm{k}\mathsf{\alpha }}^{\mathrm{a}}{\mathrm{A}}_{\mathrm{k}}=0,\mathsf{\alpha }=1,\dots ,{\mathrm{R}}_{\mathrm{a}\mathrm{q}}}$$

(5)

where R_aq is defined as the number of chemical reactions between aqueous components, v_k is the stoichiometric coefficient of component k in the chemical reaction, and A_k is the chemical symbol for the k aqueous species.

The precipitation/dissolution chemical reactions for minerals have the stoichiometry [14]:

$${\displaystyle \sum _{\mathrm{k}=1}^{{\mathrm{N}}_{\mathrm{c}\mathrm{t}}}{\mathrm{v}}_{\mathrm{k}\mathsf{\beta }}^{\mathrm{m}}{\mathrm{A}}_{\mathrm{k}}=0,\mathsf{\beta }=1,\dots ,{\mathrm{R}}_{\mathrm{m}\mathrm{n}}}$$

(6)

where R_mm is the number of reactions between the minerals and aqueous components.

The chemical reactions in the aqueous phase would be expressed by chemical equilibrium reactions because the chemical reactions that occurred in the components in the aqueous phase are usually relatively faster than the mineral precipitation/dissolution reactions. The dissolution or precipitation chemical reactions for minerals can then be described as rate-dependent reactions.

The chemical equilibrium reactions can be computed using chemical equilibrium constants [14,17], and the governing equations are

$${\mathrm{Q}}_{\mathsf{\alpha }}-{\mathrm{K}}_{\mathrm{e}\mathrm{q},\mathsf{\alpha }}=0,\mathsf{\alpha }=1,\dots ,{\mathrm{R}}_{\mathrm{a}\mathrm{q}}$$

(7)

$${\mathrm{Q}}_{\mathsf{\alpha }}={\displaystyle \prod }_{k=1}^{n_{Aq}}{\alpha }_k^{v_{k\alpha }}$$

(8)

where Q_α is the activity product, K_eq,α is the chemical equilibrium constant for the aqueous reaction α, α_k is the activity of component k, and v_ka are the stoichiometry coefficients.

The activities a_k are associated with the molality m_k (moles per kg of H₂O):

$${\mathrm{a}}_{\mathrm{k}}={\mathsf{\gamma }}_{\mathrm{k}}{\mathrm{m}}_{\mathrm{k}},\mathrm{k}=1,\dots ,{\mathrm{N}}_{\mathrm{a}\mathrm{q}}$$

(9)

where γ_k is the activity coefficient and equals 1 for an ideal solution.

Nevertheless, for most cases, the B-dot model is used to describe the non-ideal and preferred model for ionic activity coefficients [14,17]:

$$\log {\gamma }_i=-\frac{A_{\gamma }{z}_i^2\sqrt{I}}{1+{\dot{a}}_i{B}_r\sqrt{I}}+\dot{B}I$$

(10)

where A_r, B_r and $\dot{B}$ are temperature dependent parameters, ${\dot{a}}_i$ is the ion size parameter, and I is the ionic strength, which can be expressed by:

$$I=\frac{1}{2}{\displaystyle \sum _{k=1}^{n_{aq}}{m}_k{z}_k^2}$$

(11)

where z_k is the charge of the k-th ion.

As for the dissolution/precipitation reaction of mineral, the rate law is as follows [14,17]:

$$r_{\beta }={\mathsf{Â}}_{\beta }{k}_{\beta }\left(1-\frac{Q_{\beta }}{K_{eq,\beta }}\right)$$

(12)

where $r_{\beta }$ is the rate of the mineral reaction, ${\mathsf{Â}}_{\beta }$ is the reactive surface area for mineral β, $k_{\beta }$ is the rate constant of the mineral reaction, and the activity product, $Q_{\beta }$, is analogous to the activity product for the aqueous chemical equilibrium reactions:

$${\mathrm{Q}}_{\mathsf{\beta }}={\displaystyle \prod }_{\mathrm{k}=1}^{{\mathrm{n}}_{\mathrm{A}\mathrm{q}}}{\mathsf{\alpha }}_{\mathrm{k}}^{{\mathrm{v}}_{\mathrm{k}\mathsf{\beta }}}$$

(13)

The rate of formation/consumption of the different aqueous species is expressed by:

$${\mathrm{r}}_{\mathrm{k}\mathsf{\beta }}={\mathrm{v}}_{\mathrm{k}\mathsf{\beta }}\cdot {\mathrm{r}}_{\mathsf{\beta }}$$

(14)

The rate constant of the mineral reaction can be calculated at a different temperature, T, using the reference temperature, T₀:

$$k_{\beta }=k_{0\beta }\exp \left[-\frac{E_{a\beta }}{R}\left(\frac{1}{T}-\frac{1}{T_0}\right)\right]$$

(15)

where $E_{a\beta }$ is the activation energy for reaction β (J/mol) and $k_{0\beta }$ is the reaction rate constant for reaction β at T₀ (mol/m²s).

To compute the reactive surface area of the mineral reaction, the change in the moles of minerals via dissolution/precipitation is involved:

$${\mathsf{Â}}_{\beta }={\mathsf{Â}}_{\beta }^{\circ }\cdot \frac{N_{\beta }}{N_{\beta }^{\circ }}$$

(16)

where ${\mathsf{Â}}_{\beta }^{\circ }$ is the initial reactive surface, N_β is the number of mineral β moles per unit gridblock of the volume at a given time, and $N_{\beta }^{\circ }$ is the number of mineral β moles per unit gridblock of the initial bulk volume.

3. Geological Description

The case study was based on a potential target site, the Y-field in Northwestern Taiwan, for CO₂ geological storage. The target formation for this study is the Yutengping (YTP) sandstone formation, which is a deep saline aquifer in the Y-field. The YTP sandstone formation is overlain by the Chinshiu (CS) Shale, which is a thick shale formation regionally distributed in Northwestern Taiwan. The thickness of the CS Shale is about 200 m. Due to the thickness and the extremely low permeability, the CS Shale is considered to be a caprock with great integrity that can prevent the leakage of the injected CO₂ stored in the reservoir. The Shihliufen (SLF) Shale, which is the formation under the YTP sandstone, is the impermeable underburden for the CO₂ geological storage in the storage system.

The structural map of the YTP sandstone formation is shown in Figure 1. The YTP sandstone formation in the Y-field is an anticline structure sealed by two faults. The strike of the anticline axis is NE to SW. The formation top of the YTP sandstone is about 1240–1500 m. There are 11 pre-existing wells that were used to produce gas from the deeper formation, and they were the geological investigation wells for the CO₂ storage in the Y-field.

Based on the analysis of the core and the well logging interpretation of the wells, the YTP sandstone formation, with a thickness of about 250–300 m, can be divided into 7 sub-formations, including thick sandstone layers and inter-layer thin-shale layers. An example of the lithology of the sublayers from the well logging interpretation is shown in Figure 2. The structural map was digitized and then used to construct the geological grid system for the reservoir simulation. The thickness of each sub-formation was calculated by the Ordinary Kriging method from the results of the well logging interpretation of each pre-existing well. The top view of the three-dimensional model of the YTP sandstone formation is shown in Figure 3.

4. Simulation Model Design

The General Equation of state Model simulator (GEM simulator) (GEM 2015.10, Computer Modelling Group LTD., Calgary, AB, Canada) developed by the Computer Modelling Group (CMG) was used in this study to simulate the complex processes of CO₂ storage by coupling the multiphase fluid flow and geochemical mechanisms. The GEM simulator is a commercial compositional simulator based on the Equation of State (EOS). The greenhouse gas module (GHG module) of the GEM simulator, which was used to simulate the complex process of trapping mechanism, included the convective and dispersive transportations of the components, the thermodynamic equilibrium between the gas/aqueous phases, the chemical reactions that occurred in the formation water, and the mineral reactions reacted with the mineral in the porous media [13,14,18].

The formation in the study area was discretized into 45 × 29 × 7 grid blocks. The x and y dimensions of each grid block were 580 × 570 ft. The reservoir parameters, such as porosity and permeability, were assigned differently between lithologies, as shown in

Table 1. Reservoir parameters and initial conditions.

Parameter		Unit	Value
Porosity	Sand	frac.	0.25
	Shaly Sand	frac.	0.23
	Sandy Shale	frac.	0.05
	Shale	frac.	0.025
Permeability	Sand	mD	530
	Shaly Sand	mD	200
	Sandy Shale	mD	0.001
	Shale	mD	0.0001
Formation Pressure @ 5400 ft		psi	2445
Formation Temperature @ 5400 ft		°F	162

. The sand and shaly sand layers act as a reservoir in the YTP sandstone formation, while the sandy shale and shale layers act as a barrier inter-layer in the YTP sandstone formation. For the relative permeability curves this study used, the irreducible water saturation was set at 0.2, and the maximum residual gas saturation was assigned to be 0.4 for the residual gas trapping mechanism modeling. The formation temperature of the YTP sandstone formation was 162 °F, and the initial pressure was 2445 psi at a reference depth of 5400 ft. In this study, the Luchukeng (LCK), Touhuanping (THP), and Lungkang (LK) faults were designed as no-flow boundaries, and there is an open boundary at the west of the study area.

The parameters of the EOS for CO₂ and saline were based on the database of the library component in CMG’s Winprop simulator (Winprop 2015.10, Computer Modelling Group LTD., Calgary, AB, Canada). To compute the component properties of the CO₂-brine binary mixtures, the PR-EOS were used to model the behavioral calculations. Henry’s law [19] was adopted to compute the fugacities of CO₂ between the gas and aqueous phases.

The GEM simulator is based on the fully-coupled approach to solving the compositional multiphase fluid flow and the geochemical reactions. The approach was used to solve all parameters through the simultaneous convergence of all equations associated with fluid flow and chemical reaction by Newton’s method. The main equations involved the equation(s) of volume constraint, component material balance, phase equilibrium, chemical equilibrium, and mineral balance. The Jacobian matrix in Newton’s method was solved by Incomplete lower–upper factorization with the generalized minimal residual iterative method [14].

The molality of primary components in the saline of the target formation was analyzed in the laboratory using a water sample that was collected from the YTP formation in the near field. To convert the results of the molality of primary components of the saline from the laboratory condition to the reservoir condition, the Solmineq.88, which is a geochemical aqueous equilibrium model, was adopted [20]. The rock samples collected from drilling in the YTP formation and CS shale were used to analyze the chemical and mineralogical compositions through X-ray fluorescence and X-ray diffraction. The analyzed results presented that the primary minerals in the YTP sandstone formation include quartz, anorthite, muscovite, and kaolinite.

To compute the chemical reaction in the aqueous phase and the mineral reaction paths of the rock–brine–CO₂ occurred in the target formation, GAMSPath, which is the geochemical reaction path model, was adopted in this study [21]. From the results of the geochemical reaction paths, the mineral trapping mechanisms in the target formation can be simplified to 5 chemical reactions in the aqueous phase and 4 geochemical mineral reactions, as shown in

Table 2. Chemical reactions of the aqueous phase and mineral reactions used in this study. (The reaction rate constant was adopted from the Thibeau et al. (2007) [22]).

Intra-Aqueous Chemical Reactions	Keq at 33 °C
Al(OH)2+ + 2H+ $\leftrightarrow$ Al3+ + 2H2O	4.75
CO2(aq) + H2O $\leftrightarrow$ H+ + HCO3-	−6.35
CO32- + H+ $\leftrightarrow$ HCO3-	10.31
KOH + H+ $\leftrightarrow$ K+ + H2O	15.43
OH- + H+ $\leftrightarrow$ H2O	13.74
Geochemical Mineral Reactions	k0β at T0
Anorthite + 8H+ $\leftrightarrow$ 4H2O + Ca2+ + 2Al3+ + 2SiO2(aq)	25.72 at 33 °C
Calcite + H+ $\leftrightarrow$ Ca2+ + HCO3-	1.6 at 33 °C
Kaolinite + 6H+ $\leftrightarrow$ 5H2O + 2Al3+ + 2SiO2(aq)	6.77 at 33 °C
Muscovite + 6H+ $\leftrightarrow$ 6H2O + K+ + 3Al3+ + 3SiO2(aq)	12 at 25 °C

. The molality of the primary aqueous components of the saline and the volume percentages of the minerals in the formation are shown in

Table 3. Initial molality of the primary aqueous components of the saline at the reservoir conditions and the volume percentages of the minerals in the rock used in the simulation model.

Primary Species	Molality (mole/kg)	Mineral	Volume Percentage (%)
H+	8.90 × 10−9	Anorthite	13.15%
Ca2+	8.75 × 10−5	Kaolinite	3.77%
K+	6.68 × 10−5	Calcite	0%
Al3+	7.24 × 10−11	Muscovite	6.43%
SiO2	2.35 × 10−8	Quartz	73.65%

.

A schematic diagram of the injection process used in this study is shown in Figure 4. Using the up-dip of the anticline in the Y-formation, an up-dip injection well was designed to prevent the injected free-moved supercritical CO₂ splitting from the target anticline. The perforated intervals of the injection well were assumed to be the sandstone layer and the three shaly sand layers. A scenario analysis was performed for two injection fluids: traditional supercritical CO₂ and dissolved CO₂ solution. This case study was designed by injecting 0.2 million tons of CO₂ per year for 10 years via the one injection well. The simulation period was designed for 1000 years to observe the transformation process of trapping mechanisms after the injection period. For the dissolved CO₂ injection scenario, the CO₂ concentration of the injected solution was 1.005 (mole/kg·H₂O), considering the CO₂ solubility at the initial static bottom-hole pressure (1980 psi) and formation temperature (162 °F). The injection rate of the injected solution was 68,460 bbl/day. Because a large volume of water was required in the dissolved CO₂ injection scenario, one pre-existing well was assigned as the production well from which water in the YTP formation was produced at the rate required for the water supply.

5. Results and Discussion

5.1. Supercritical CO₂ Scenario

The injection profile of the supercritical CO₂ scenario is shown in Figure 5. The initial bottom-hole pressure was about 2000 psi. With the continuous injection of supercritical CO₂, the bottom-hole pressure rose to about 2250 psi after 10 years of injection. Based on the evaluation result of the maximum sustainable pressure in the YTP formation in this target site, the smallest evaluated value of the maximum sustainable pressure was about 1100 psi [23]. In the supercritical CO₂ scenario, the pressure increment induced by CO₂ injection was just about 250 psi, so it would not lead to a geomechanical failure occurring in the target reservoir. After the well shut-in, since the supercritical CO₂ is accumulated at the top of the anticline, the well bottom-hole pressure would decrease slowly. At the end of the simulation, the bottom-hole pressure was about 2120 psi, which was higher than the initial bottom-hole pressure. Because the increment of the bottom-hole pressure was not very great, the buildup of the bottom hole pressure was considered safe over this injection period and post-injection period.

Based on the simulation results of the spatial distribution of CO₂ saturation (Figure 6), the CO₂ plume expanded to its largest size when the injection well was shut-in (10 years). After that, the plume gradually shrank due to the contribution of the solubility trapping mechanism. At the end of the simulation period (1000 years), the CO₂ plume area was smaller than the largest size due to the contributions of the solubility, ionic, and mineral trapping mechanisms. Since the density of supercritical CO₂ was smaller than that of the formation water and the trapping mechanisms associated with geochemical reactions occur slowly, the CO₂ plume was still located at the top of the anticline in the YTP formation at the end of the simulation.

The spatial distribution of the CO₂ molality is shown in Figure 7. The plume of the CO₂ dissolved in the saline of the formation was similar to that of the supercritical CO₂. The plume of the CO₂ molality expanded slightly in the early stages after the injection well was shut-in because of the downward migration of the CO₂-saturated water with a high density caused by CO₂ dissolution. In the later stages, the plume of the CO₂ molality shrank due to the contributions of the ionic and mineral trapping mechanism. However, the plume of the CO₂ molality was still located at the top of the anticline in the YTP formation at the end of the simulation.

The spatial distribution of the change in the moles of calcite is shown in Figure 8. At the end of the injection, there was no significant mineral precipitation. The contribution of the mineral trapping mechanism becomes significant after hundreds of years. CO₂ in the HCO₃^- and CO₃^2- forms achieved via ionization and dissociation results in the precipitation of calcite. At the end of the simulation, the calcite precipitated in the region near the plume of the CO₂ molarity.

The evolution profiles of kaolinite, calcite, muscovite, and anorthite are shown in Figure 9. Anorthite, which is a calcium-rich mineral which is non-carbonate in the formation, dissolves to provide calcium to the formation water caused by formed carbonic acid in the formation water. Calcite and kaolinite precipitate resulting from the calcium ions, which are from the dissolution of anorthite. In regions with a decrease in pH due to CO₂ dissolution, the dissociation of muscovite releases potassium ions into the formation water and leads to the precipitation of kaolinite. The geochemical reactions of the minerals did not achieve a balance between dissolution and precipitation at the end of the simulation. The trend of the dissolution of anorthite and trend of the precipitation of calcite and kaolinite showed that the amount of CO₂ trapped by the mineral trapping mechanism would be greater if the simulation time were increased.

5.2. Dissolved CO₂ Scenario

The injection profile of the dissolved CO₂ scenario is shown in Figure 10. With the continuous injection of the CO₂ solution, the bottom-hole pressure rose to about 2350 psi after the 10-year injection period. In the dissolved CO₂ scenario, the pressure increment induced by injecting the CO₂ solution was about 350 psi. Although the pressure increment in the dissolved CO₂ scenario was higher than that in the supercritical CO₂ scenario, it was still less than the sustainable pressure constraint of 1100 psi, and geomechanical failure will not happen in the target reservoir. After the well shut-in, the pressure decreased quickly because of the balance of the formation pressure in the aquifer is fast due to the convection. At the end of the simulation, the bottom-hole pressure was close to the initial bottom-hole pressure.

The spatial distribution of the CO₂ molality is shown in Figure 11. The plume of the CO₂ dissolved in the saline in the formation was located at the top of the anticline in the YTP formation at the end of the injection process. Because of the effect of the production well, during the injection period, the direction of the migration of the CO₂ plume was slightly toward the production well. After the shut-in of the injection well, the area of the plume of the CO₂ molarity expanded because of the downward migration of the higher-density CO₂ solution in comparison to the formation water. The shape of the plume of the CO₂ molarity changed due to the structure of the YTP formation in the Y-field. After 500 years, the majority of the plume of high CO₂ concentration had disappeared as the result of the contributions of the geochemical reactions (i.e., ionic and mineral trapping mechanisms).

The spatial distribution of the change in moles of calcite is shown in Figure 12. At the end of the injection, there was no significant mineral precipitation. The contribution of the mineral trapping mechanism appeared after 100 years. In the early stages, the calcite precipitated near the top of the anticline, where the plume of the CO₂ molarity was. Because the plume of the CO₂ molarity migrated downward, the calcite precipitated at the bottom of the YTP formation in the later stages. The calcite precipitated both at the top of the anticline and the bottom of the YTP formation in the Y-field at the end of the simulation period (1000 years).

The evolution profiles of kaolinite, calcite, muscovite, and anorthite are shown in Figure 13. The geochemical reactions of the minerals occurred at a fast rate in the dissolved-CO₂ injection scenario. The majority of the injected CO₂ was transformed into carbonate minerals after 400 years. The rate of the geochemical reactions thereby decreased. The balance between the dissolution and precipitation geochemical reactions of the minerals was achieved after about 600 years.

5.3. Comparison of the Supercritical CO₂ and Dissolved CO₂ Scenarios

Based on the simulation results of the spatial distribution of the CO₂ molality in these two scenarios described above (Figure 14), the plume area of the supercritical CO₂ scenario was smaller than that of the dissolved CO₂ scenario when the injection well was shut-in (10 years). In the supercritical CO₂ scenario, the highest molality of CO₂ in the aqueous phase was located near the wellbore. At the end of the simulation period (1000 years), the plume area of the supercritical CO₂ scenario decreased due to the contributions of the ionic and mineral trapping mechanisms. However, the plume area of the dissolved CO₂ scenario disappeared because of the fast rate at which the geochemical reaction occurred to form carbonate.

The spatial distributions of the change in moles of calcite in these two scenarios are shown in Figure 15. When the injection well was shut-in (10 years), in both scenarios, there was no significant mineral precipitation. The contribution of the mineral trapping mechanism became significant after hundreds of years. At the end of the simulation period, the calcite precipitated at the top of the anticline in the supercritical CO₂ scenario. This occurred because the majority of the injected CO₂ was still located at the top of the anticline in the YTP formation as a result of the low density of supercritical CO₂. In the dissolved CO₂ scenario, at the end of the simulation period (1000 years), the calcite mostly precipitated at the bottom of the YTP formation because the plume of the CO₂ solution moved downward. The area of the calcite distribution in the dissolved CO₂ scenario was much larger than that of the supercritical CO₂ scenario. This occurred because the process of transforming the CO₂ in an aqueous phase into a mineral phase is shorter than the process of transforming CO₂ in a supercritical phase into a mineral phase.

The evolution profiles of kaolinite, calcite, muscovite, and anorthite in these two scenarios are shown in Figure 16. Calcite, kaolinite, and muscovite are precipitation-phase minerals that occur when CO₂ was injected into the YTP formation. Anorthite is a dissolution-phase mineral that provides a source of calcium in the formation water. The rate of the geochemical reactions of the minerals was much faster in the dissolved CO₂ scenario than that in the supercritical CO₂ scenario. In the dissolved CO₂ scenario, the majority of the injected CO₂ was transformed into the carbonate minerals after 400 years, and the balance between dissolution and precipitation reactions of the minerals was achieved after about 600 years. Compared to the dissolved CO₂ scenario, the geochemical reactions of the minerals did not achieve such a balance after 1000 years in the supercritical CO₂ scenario in the YTP formation.

The contributions of the different trapping mechanisms in these two scenarios are shown in Figure 17. In the supercritical CO₂ scenario, when the injection well was shut-in (10 years), 71.93% of the total 2-million tons of injected CO₂ was trapped by structural trapping, and 9.88%, 17.70%, 0.48%, and 0.01% of the injected CO₂ was stored by residual gas, solubility, ionic, and mineral trapping, respectively. Ten years after the injection well was shut-in (i.e., 20 years of simulation time), 56.81%, 24.41%, 17.67%, 1.03%, and 0.08% of injected CO₂ was stored by structural, residual gas, solubility, ionic, and mineral trapping, respectively. One-hundred years after the injection well was shut-in (110 years of simulation time), 47.68%, 31.58%, 16.63%, 1.69%, and 2.42% of the injected CO₂ was stored by structural, residual gas, solubility, ionic, and mineral trapping, respectively. At the end of the simulation (1000 years of simulation time), 32.26%, 30.16%, 13.89%, 1.54%, and 22.15% of the injected CO₂ was stored by structural, residual gas, solubility, ionic, and mineral trapping, respectively.

If the risk of CO₂ leakage is defined by the amount of CO₂ stored by secure trapping mechanisms, the safety index (SFI) can be evaluated by the number of the moles of CO₂ retained by the safe trapping mechanisms (i.e., residual gas, solubility, ionic, and mineral trapping) [12]. The SFI for the supercritical CO₂ scenario was 0.2807 at the end of injection (10 years). In the post-injection period, the SFIs were 0.4319, 0.5232, 0.6774 at the simulation times of 20, 110, and 1000 years (Figure 18).

In the dissolved CO₂ scenario, when the injection well was shut-in (10 years), 0.15% of a total of 2 million tons of the injected CO₂ was stored by residual gas trapping, and 84.95%, 14.86%, and 0.04% of the injected CO₂ was stored by solubility, ionic, and mineral trapping, respectively. It is worth noting that there was a very small amount of CO₂ trapped by the residual gas trapping mechanism indicating that there was a small amount of supercritical CO₂ released from the CO₂ solution during the injection period because of the slightly high molarity of CO₂ in the aqueous phase near the wellbore of the injection well. The released supercritical CO₂ would be restricted by the hysteresis effect as the residual gas that is immobilized and trapped in the pore spaces of the rock. Therefore, all of the injected CO₂ was trapped by safe and low-risk trapping mechanisms, and the SFI for the dissolved CO₂ scenario was 1 at the end of injection (10 years).

Ten years after the injection well was shut-in (20 years of simulation time), 0.14%, 82.10%, 17.41%, and 0.35% of the injected CO₂ was stored by residual gas, solubility, ionic, and mineral trapping, respectively. One hundred years after the injection well was shut-in (110 years of simulation time), 0.05%, 66.15%, 18.51%, and 15.29% of the injected CO₂ was stored by residual gas, solubility, ionic, and mineral trapping, respectively. At the end of the simulation (1000 years of simulation time), 3.70%, 14.81%, and 81.49% of the injected CO₂ were stored by solubility, ionic, and mineral, respectively.

Compared to the supercritical CO₂ scenario, the SFI during both the injection period and during the total simulation period remained at 1, indicating that all the injected CO₂ was trapped by safe trapping mechanisms (Figure 18). The solubility trapping mechanism can occur immediately after CO₂ is injected into the reservoir. The transformation of CO₂ into solid carbonate is, therefore, faster. The majority of the injected CO₂ can be transformed into solid carbonate within hundreds of years. The rest of the injected CO₂ was trapped by the ionic trapping mechanism because a balance between the dissolution and precipitation of the minerals was reached, and the transformations from ionic phases into mineral phases stopped after about 600 years.

In conclusion, changing the injection fluid from supercritical CO₂ to dissolved CO₂ can increase the safety of the CO₂ storage significantly and eliminate the risk of CO₂ leakage from the reservoir due to the injected CO₂ being stored by secure trapping mechanisms. The simulation results showed that the geochemical reactions occurred more rapidly, consequently accelerating the rate of mineralization by means of the dissolved CO₂ injection. The plume of the CO₂ molarity was observed to disappear by the end of the simulation. The majority of the injected CO₂ was transformed into solid carbonate, which is chemically stable and environmentally benign.

6. Conclusions

The risk of leakage and the plume migration between the scenarios involving the injection of supercritical CO₂ and dissolved CO₂ into a reservoir were studied and discussed in this study. In the supercritical CO₂ injection scenario, the majority of the injected CO₂ was retained by the structural trapping. The supercritical CO₂ plume was still located at the top of the anticline after 1000 years. At this point, the contribution of the mineral trapping mechanism was about 22%, and the contribution of the structural trapping mechanism, which indicated the presence of mobile supercritical CO₂ that might migrate upward in the reservoir, was about 32%.

In the dissolved CO₂ solution injection scenario, the plume of the injected CO₂ migrated downward because of the higher density of the CO₂ solution than that of the formation water. The majority of the plume of CO₂ in the aqueous phase had disappeared after a few hundred years caused by the contributions of the ionic and mineral trapping mechanisms. The majority of the injected CO₂ was transformed into solid carbonate within hundreds of years.

The risk of acute CO₂ leakage related to mechanical or geomechanical failures can be controlled and reduced through well-regulated management of the injection rate and injection pressure. The risk of chronic leakage via a natural pathway can be decreased by the approach of injecting CO₂ solution instead of supercritical CO₂. The amount of the CO₂ retained by the safe trapping mechanisms in the dissolved CO₂ scenario was greater than that in the supercritical CO₂ scenario. In addition, the process of CO₂ mineralization was much faster than that in the supercritical CO₂ scenario. Changing the injection fluid from supercritical CO₂ to a dissolved CO₂ solution can significantly increase the safety of the CO₂ geological storage. It can also eliminate the risk of CO₂ leakage from the reservoir because the injected CO₂ can be trapped totally by safe trapping mechanisms. Therefore, the potential environmental impact of CO₂ storage can be reduced.