Reactive Transport Modeling of CO₂-Brine–Rock Interaction on Long-Term CO₂ Sequestration in Shihezi Formation

Abstract

Carbon Capture and Storage (CCS) is attracting increasing scientific attention. Although experiments can explore the chemical process of CO₂ sequestration, they are limited in time. CO₂ geological storage will last hundreds and thousands of years, even much longer, so the numerical simulation method is used to conduct kinetic batch modeling and reactive transport modeling. The geochemical simulation tool—TOUGHREACT—is used to imitate CO₂-brine–rock interactions at the Shihezi Formation in the Ordos basin. The mechanisms of CO₂-brine–rock interaction and their effects on the reservoir are discussed, especially the change in structure and properties. K-feldspar and albite will dissolve as the main primary minerals. However, calcite and quartz will dissolve first and precipitate last. In addition, siderite and ankerite also appear as precipitation minerals. Mineral dissolution and precipitation will alter the formation of petrophysical parameters, such as porosity and permeability, which play significant roles in the geological storage environments. Although the CO₂-brine–rock interaction rate may be small, it is an ideal way of geological storage. Regardless of what minerals dissolve and precipitate, they will improve the dissolution of CO₂. The interaction between rock and brine with dissolved CO₂ can promote the amount of mineralization of CO₂, called mineral trapping, which has a positive effect on the long-term feasibility of CO₂ storage.

1. Introduction

Greenhouse gases, especially CO₂, have increased rapidly and led to climate change with severe potential consequences. Novel technologies are proposed for carbon dioxide (CO₂) capture, storage, and utilization. For example, hydrogenation of CO₂ is an important representative among CO₂ utilization [1,2]. In addition, in situ catalytic hydrogenation of CO₂ during steam-based enhanced oil recovery not only enhances the oil-recovery factor but also reduces CO₂ emission significantly [3]. Carbon Capture and Storage technology (CCS) is the best scheme to reduce carbon emissions under the condition of existing technological means, which is gradually attracting people’s attention [4,5]. As an important part of CCS technology, the study of CO₂ geological storage is of great significance for the development of CCS technology [6]. At present, research institutions and scholars from the United States, Norway, Canada, Germany, Australia, China, and other countries have carried out various studies on CCS and achieved fruitful results [7,8]. Some commercial CO₂ geological sequestration projects in many countries have also been launched, a large amount of experience and field data have been accumulated in CCS engineering, and some important progresses have been made [9]. Europe and North America have carried out CCS projects since the 1990s, such as Norway, Canada, and the United States. Australia and New Zealand are not far behind. China’s CCS research started relatively late, and there is still some gap with the international advanced level [10,11,12].

According to the criteria given by the IPCC, the site for CO₂ sequestration should be guaranteed to remain more than 99% (probability greater than 90%) after 100 years and more than 99% (probability greater than 66%) after 1000 years. Although some key factors of caprock are essential to judge whether the storage site is safe, the influence of CO₂ injection on reservoirs cannot be ignored either [13,14,15,16]. Therefore, it is of great significance to study the influence of CO₂ injection on reservoirs. CO₂-brine-rock interactions are important for CO₂ migration and storage safety. The interaction type includes dissolution and precipitation. The former may lead to increases in porosity and permeability, which facilities CO₂ migration; the latter may lead to decreases in porosity and permeability, which may hinder CO₂ migration in porous media. For CO₂ sequestration safety, CO₂ can be mineralized in the form of carbonatite through CO₂-brine-rock interactions. It is the idealist storage mechanism in CO₂ geological storage.

At present, the research methods of CO₂-brine-rock reaction during CO₂ geological storage mainly include laboratory test and numerical simulation [17]. Results of the CO₂-brine-rock reaction and the influence on long-term CO₂ storage for reservoir performance can be directly observed by physical experiments, and the risk of leakage can be evaluated accordingly [11,12]. However, there are some limitations for laboratory investigation. On the one hand, it is almost impossible to simulate geological conditions in the laboratory, especially for long-term geochemical reactions. On the other hand, there are a limited number of natural cores to carry out experiments [18,19]. It is necessary to figure out effects of geochemical reactions on reservoir physical properties by numerical simulations.

“Coal-to-Liquid Chemical Exhaust Capture and Storage in Deep Saline Aquifer” was the first CCS project in China [10], which was a whole-process demonstration project. This project was implemented by the Shenhua Group that was a super-large coal enterprise ranking first in the world. The Shihezi Formation is one of the five target areas in the Ordos basin. We study changes in reservoir properties that are influenced by CO₂ injection. CO₂ migration, CO₂-brine-rock interaction, and their effects on the reservoir are investigated by numerical simulation. In particular, the influence of the CO₂-brine–rock reaction on reservoir physical properties is discussed on a large time scale, which provides theoretical guidance for long-term safe CO₂ storage projects.

2. CO₂ Storage Area and Major Interactions

2.1. Background

Geological formations, used for large volumes of CO₂ storage, can be categorized: saline aquifer formations, depleted oil and gas reservoirs, storage as a part of CO₂ EOR projects, coal bed storage, and other formations including volcanic rocks (especially basalt) and underground caverns. The first two are the main classes of these porous reservoirs. Generally, CO₂ storage sites need to be deeper than 800 m to ensure that CO₂ is in a dense form as a super-critical phase. At a depth of around 1 km or more, the reservoir potentially contains low-permeably sealing units for long-term trapping of CO₂.

The most distinctive feature is porousness and high permeability in the reservoir of the Ordos basin, where not only are oil, gas, and coal resources abundant, but the brine is also widely distributed. This means that there is tremendous potential for CO₂ sequestration. Based on the analysis of strata in the Ordos basin, the northeastern part of the basin has the geological conditions for CO₂ storage and has been chosen as the target area for CCS. Now, the first CCS demonstration and storage basin of China has been built in the Ordos basin [10].

Based on domestic and foreign CO₂ storage experience, the existing geological data, and stratigraphic characteristics, there are five candidate areas for CO₂ storage in the Ordos Basin: Triassic Liujiagou Formation reservoir-caprock association, Permian Shiqianfeng Formation reservoir-caprock association, Permian Shihezi Formation reservoir-caprock association, Permian Shanxi Formation reservoir-caprock association, and Ordovician Majiagou Formation reservoir-cap association. The reservoir types of the above five reservoir-cap assemblages are all sandstone, with the highest content of quartz as the reservoir mineral. Geological data of the numerical model are from the Shihezi Formation [10].

2.2. Numerical Model and Kinetics of CO₂-Brine-Rock Interaction

2.2.1. Description of Numerical Model

The numerical models are based on the Shihezi Formation in the Ordos Basin, whose data are from the real geological data. The depth of the storage site is between 1650 m and 1850 m, the formation pressure is 16.5 MPa, and the temperature is 55–75 °C. The CO₂ migration process in the reservoir is described in a 2D model. At the same time, CO₂-brine-rock interactions, including dissolution or precipitation, are simulated to investigate changes in minerals in the reservoir, as well as both porosity and permeability. The model thickness of the reservoir is 100 m, and the longitude distance is 5 km. The CO₂ injection well is located at the lower left, as shown in Figure 1. Vertically, it is divided into 20 layers, and the mesh size of each layer is 5 m. In the lateral direction, there are 51 grids, and the grid size increases gradually from left to right. The number of grids is 1020 in total in the conceptual model.

2.2.2. Kinetics of CO₂-Brine-Rock Interaction

To represent a geochemical system, a subset of $N_C$ aqueous species are selected as the basis species, while other ones are called secondary species including aqueous complexes, precipitated minerals, and gaseous species [20]. In TOUGHREACT, the kinetic rate is calculated according to basis species that are used to describe the CO₂-brine-rock interaction [21]:

$$r_n=f\left(c_1,c_2,\cdots ,c_{N_C}\right)=\pm k_n{A}_n{\left|1-{\Omega }_n^{\theta }\right|}^{\eta },n=\mathrm{1,2},\cdots ,N_q$$

where $r_n$ is positive representing mineral precipitation, and negative represents dissolution. $A_n$ stands for the specific reactive surface area. ${\Omega }_n$ is the kinetic saturation of reactive mineral, and can be calculated by ${\Omega }_n=K_n^{-1}\prod c_j^v{\gamma }_j^v$, where $K_n$ is the equilibrium constant of the n-th mineral, and $c_j^v$ and ${\gamma }_j^v$ are the molar concentration and thermodynamic activity coefficient of j-th basis species in the v-th aqueous complex, respectively. Parameters of both $\theta$ and $\eta$ are usually set to 1. The kinetic rate constant $k_n$ can be calculated by the following equation:

$$k=k_{25}\cdot \mathit{exp}\left[\frac{E_a}{R}\left(\frac{1}{T}-\frac{1}{298.15}\right)\right]$$

where $k_{25}$ is the kinetic rate constant at 25 °C (mol/m²s), $E_a$ is the activation energy (J/mol), $R$ is the gas constant (8.31 J/mol K), and $T$ is the temperature (K).

The above equation can be expressed in a more complicated form:

$$k=k_{25}^n\cdot \mathit{exp}\left[\frac{-E_a^n}{R}\left(\frac{1}{T}-\frac{1}{298.15}\right)\right]+k_{25}^{{\mathrm{H}}^{+}}\cdot \mathit{exp}\left[\frac{-E_a^{{\mathrm{H}}^{+}}}{R}\left(\frac{1}{T}-\frac{1}{298.15}\right)\right]a_{{\mathrm{H}}^{+}}^{n_{{\mathrm{H}}^{+}}}+k_{25}^{\mathrm{O}{\mathrm{H}}^{-}}\cdot \mathit{exp}\left[\frac{-E_a^{\mathrm{O}{\mathrm{H}}^{-}}}{R}\left(\frac{1}{T}-\frac{1}{298.15}\right)\right]a_{\mathrm{O}{\mathrm{H}}^{-}}^{n_{\mathrm{O}{\mathrm{H}}^{-}}}$$

where n, ${\mathrm{H}}^{+}$, and $\mathrm{O}{\mathrm{H}}^{-}$ stand for the neutral, acid, and base mechanism, respectively; $E_a^n$, $-E_a^{{\mathrm{H}}^{+}}$, and $-E_a^{\mathrm{O}{\mathrm{H}}^{-}}$ are the corresponding activity energies; $k_{25}^n$, $k_{25}^{{\mathrm{H}}^{+}}$, and $k_{25}^{\mathrm{O}{\mathrm{H}}^{-}}$ are kinetic rate constants at 25 °C; $a_{{\mathrm{H}}^{+}}^{n_{{\mathrm{H}}^{+}}}$ and $a_{\mathrm{O}{\mathrm{H}}^{-}}^{n_{\mathrm{O}{\mathrm{H}}^{-}}}$ are activities of ${\mathrm{H}}^{+}$ and $\mathrm{O}{\mathrm{H}}^{-}$, respectively, calculated by $a_{{\mathrm{H}}^{+}}^{n_{{\mathrm{H}}^{+}}}={\gamma }_{{\mathrm{H}}^{+}}{c}_{{\mathrm{H}}^{+}}$ and $a_{\mathrm{O}{\mathrm{H}}^{-}}^{n_{\mathrm{O}{\mathrm{H}}^{-}}}={\gamma }_{\mathrm{O}{\mathrm{H}}^{-}}{c}_{\mathrm{O}{\mathrm{H}}^{-}}$, where ${\gamma }_{{\mathrm{H}}^{+}}$, $c_{{\mathrm{H}}^{+}}$, ${\gamma }_{\mathrm{O}{\mathrm{H}}^{-}}$, and $c_{\mathrm{O}{\mathrm{H}}^{-}}$ are thermodynamic activity coefficients and molar concentrations of ${\mathrm{H}}^{+}$ and $\mathrm{O}{\mathrm{H}}^{-}$, respectively. For CO₂ sequestration, the acidity and basicity of brine in the reservoir will vary, which will result in different reactions for acid and base mechanisms.

2.3. Parameters of Numerical Simulation and Geochemical Interactions

The reservoir is modeled as porous media, the parameters of which are detailed in

Table 1. Parameters of numerical model [22].

Parameter	Reservoir
Thickness (m)	100
Temperature (°C)	50
Pressure (MPa)	20.0
Density of rock (kg/m3)	2400
Porosity (%)	12.0
Horizontal permeability (m2)	5.47 × 10−15
Vertical permeability (m2)	5.47 × 10−15
Liquid relative permeability	$\begin{array}{cc}{k}_{rl}=\left\{\begin{array}{c}\sqrt{S^{*}}{\left\{1-{\left(1-{\left(S^{*}\right)}^{\frac{1}{m}}\right)}^m\right\}}^2\hfill \\ 1\hfill \end{array}\right.& \begin{array}{c}{S}_l<S_{ls}\\ S_l\ge S_{ls}\end{array}\end{array}$, $S^{*}=\frac{\left(S_l-S_{lr}\right)}{\left(1-S_{lr}\right)}$, $m=0.457$, $S_{lr}=0.300$
Gas relative permeability	$\begin{array}{cc}{k}_{rg}=\left\{\begin{array}{c}1-k_{rl}\hfill \\ {\left(1-\widehat{S}\right)}^2\left(1-{\widehat{S}}^2\right)\hfill \end{array}\right.& \begin{array}{c}{S}_{gr}=0\\ S_{gr}>0\end{array}\end{array}$, $\widehat{S}=\frac{\left(S_l-S_{lr}\right)}{\left(1-S_{lr}-S_{gr}\right)}$, $S_{gr}=0.05$
Capillary pressure	$P_c=-P_0{\left[{\left(S^{*}\right)}^{\frac{-1}{m}}-1\right]}^{1-m}$, $P_{max}\le P_c\le 0$, $m=0.457$, $S_{lr}=0.200$, $P_{max}=1.00\times {10}^7\mathrm{P}\mathrm{a}$, $P_{0}7.71\times {10}^5\mathrm{P}\mathrm{a}$,

. Core samples are from the Shihezi Formation in the Ordos basin, and geological model parameters are from [11], including the minerals content and brine composition. The minerals content data are listed in

Table 2. Minerals content [11].

No.	Minerals	Content1 (V%) Case 1	Content2 (V%) Case 2	Content3 (V%) Case 3	Content4 (V%) Case 4
1	quartz	60.44	60.44	60.44	60.44
2	K-feldspar	4.50	4.50	12.00	12.00
3	albite	12.50	6.50	6.00	12.00
4	anorthite	8.00	14.00	7.00	1.50
5	calcite	3.00	3.00	3.00	5.00
6	illite	4.50	4.50	2.00	2.00
7	smectite-Ca	1.25	0.50	2.5	1.25
8	smectite-Na	1.25	2.00	2.5	1.25
9	chlorite	4.56	4.56	4.56	4.56

, and the brine composition is listed in

Table 3. Brine composition [11].

Composition	Concentration (mol/L)	Composition	Concentration (mol/L)
Ca2+	$1.6113\times {10}^{-1}$	${\mathrm{C}\mathrm{l}}^{-}$	$5.0558\times {10}^{-1}$
Na+	$1.6779\times {10}^{-1}$	${\mathrm{N}\mathrm{O}}_3^{-}$	$6.3000\times {10}^{-4}$
Mg2+	$8.2800\times {10}^{-3}$	${\mathrm{H}\mathrm{C}\mathrm{O}}_3^{-}$	$1.0300\times {10}^{-3}$
K+	$6.3000\times {10}^{-4}$	${\mathrm{S}\mathrm{O}}_4^{-}$	$1.6980\times {10}^{-4}$
Fe2+	$1.6980\times {10}^{-4}$

. The injection period is 30 years, and the simulation time is 2000 years. Here, some primary minerals are chosen to analyze the sensitivity of the numerical model. Based on the content of alkali feldspar and plagioclase, we set four cases for sensitivity analysis, which are classified by the compositions and contents of primary minerals.

3. Discussion of Numerical Simulation

3.1. CO₂ Migration

CO₂ will migrate upward with buoyancy after injection, some of which will move into both sides laterally because of the performance of caprock overlying the formation. Gas saturation (Sg) is used to describe the distribution of gaseous CO₂ after injection into the formation, as shown in Figure 2. Simulation results in Section 3.1, Section 3.2, Section 3.3 and Section 3.4 are based on Case 1. In the reservoir, Sg near the injection point in the vertical direction is much larger than the area far from the injection point. Once CO₂ is injected into the reservoir, gaseous CO₂ will migrate upward until reaching the caprock, and then spread in the lateral direction along caprock, as shown in Figure 2. During the CO₂ injection period, the horizontal distance is approximately 500 m, illustrated in Figure 2a. CO₂ will migrate horizontally and the largest distance from the injection point is about 600 m and a bit more, illustrated in Figure 2c,d. Moreover, the smaller the Sg value, the longer the time. During the migration of CO₂, the descending finger-like CO₂ distribution can be found from the region of the edge because the denser brine migrates downward. The reason is that CO₂ dissolves into the brine, which leads to greater brine density.

The residual sequestration amount depends upon the maximal CO₂ saturation. The larger the gas saturation, the larger the CO₂ sequestration amount. Gaseous CO₂ content is greatly reduced in the reservoir by comparison among Figure 2a–d. On the one hand, massive CO₂ is dissolved into the brine, producing ${\mathrm{H}\mathrm{C}\mathrm{O}}_3^{-}$, ${\mathrm{C}\mathrm{O}}_3^{2-}$, and ${\mathrm{H}}^{+}$, which promotes reactions in porous media. On the other hand, CO₂-brine-rock interactions facilitate the CO₂ dissolution reversely.

The brine density will increase because of dissolved CO₂ and ions entering the solution resulting from minerals dissolution. The range of brine density variation is consistent with CO₂ gas saturation, as shown in Figure 3.

The density of the aqueous phase with dissolved CO₂ is calculated assuming the additivity of the volumes of brine and dissolved CO₂ as follows [20]:

$$\frac{1}{{\rho }_{\mathrm{a}\mathrm{q}}}=\frac{1-X_3}{{\rho }_{\mathrm{b}}}+\frac{X_3}{{\rho }_{{\mathrm{C}\mathrm{O}}_2}}$$

where $X_3$ is the mass fraction of CO₂ in the aqueous phase; ${\rho }_{\mathrm{a}\mathrm{q}}$, ${\rho }_{\mathrm{b}}$, and ${\rho }_{{\mathrm{C}\mathrm{O}}_2}$ are densities of aqueous, brine, and CO₂, respectively. The density of dissolved CO₂, ${\rho }_{{\mathrm{C}\mathrm{O}}_2}$, is a function of temperature and calculated by

$${\rho }_{{\mathrm{C}\mathrm{O}}_2}=\frac{M_{{\mathrm{C}\mathrm{O}}_2}}{V_{\varphi }}\times {10}^3$$

where $M_{{\mathrm{C}\mathrm{O}}_2}$ is the molecular weight of CO₂, and $V_{\varphi }$ is the molar volume of dissolved CO₂:

$$V_{\varphi }=a+bT+c{T}^2+d{T}^3$$

in units of cm³ per gram-mole, $T$ is the temperature in °C, and $a$ through $d$ are fitting parameters: $a=37.51$, $b=-9.585\times {10}^{-2}$, $c=8.74\times {10}^{-4}$, and $d=-5.044\times {10}^{-7}$. Dissolved CO₂ is always dilute regardless of total fluid pressure, because it amounts at most to a few percent of total aqueous density. Accordingly, it is permissible to neglect the pressure dependence of the partial density of dissolved CO₂.

3.2. pH Value of Reservoir

The pH value decreases because of CO₂ dissolution, and the corresponding geochemical processes (Equations (1)–(3)) are listed as follows:

$${\mathrm{C}\mathrm{O}}_{2\left(\mathrm{g}\right)}+{\mathrm{H}}_2\mathrm{O}\leftrightarrow {\mathrm{H}}_2{\mathrm{C}\mathrm{O}}_3$$

(1)

$${\mathrm{H}}_2{\mathrm{C}\mathrm{O}}_3\leftrightarrow {\mathrm{H}}^{+}+{\mathrm{H}\mathrm{C}\mathrm{O}}_3^{-}$$

(2)

$${\mathrm{H}\mathrm{C}\mathrm{O}}_3^{-}\leftrightarrow {\mathrm{H}}^{+}+{\mathrm{C}\mathrm{O}}_3^{2-}$$

(3)

Figure 4 shows pH value distributions in the reservoir. CO₂ moves upward and diffuses around the injection well, where the pH value demonstrates this process due to CO₂ solution in reservoir. During the CO₂ injection period, CO₂ moves upward and spreads along the bottom of the caprock, where the pH value decreases. The CO₂ migration range in the reservoir top is almost the same as in the reservoir base since stopping injection. This is because of the lower permeability and higher residual gas saturation. In the reservoir base, the radius of the lateral migration region is about 600 m, while, in the top, it reaches 700 m. According to Figure 4b–d, pH values will increase over time. The main reason is geochemical interactions among CO₂, brine, and minerals in rock. These reactions will consume a large amount of CO₂, which will buffer the pH value of brine.

CO₂ dissolution will promote multiple complex physical and chemical processes, where there are super-critical CO₂ flow diffusion and convection, and many geochemical interactions with CO₂. In the reservoir, the geochemical process involves minerals dissolution and precipitation. On the one hand, the acidized brine will result in some minerals dissolving, such as calcite dissolution, whose geochemical processes equations are listed in (4)–(5):

$$\mathrm{C}\mathrm{a}{\mathrm{C}\mathrm{O}}_3+{\mathrm{C}\mathrm{O}}_2+{\mathrm{H}}_2\mathrm{O}\rightleftarrows {\mathrm{C}\mathrm{a}\mathrm{H}\mathrm{C}\mathrm{O}}_3^{+}+{\mathrm{H}\mathrm{C}\mathrm{O}}_3^{-}$$

(4)

$${\mathrm{C}\mathrm{a}\mathrm{H}\mathrm{C}\mathrm{O}}_3^{+}\to {\mathrm{C}\mathrm{a}}^{2+}+{\mathrm{H}\mathrm{C}\mathrm{O}}_3^{-}$$

(5)

On the other hand, bicarbonate, and cations, such as Ca²⁺, Mg²⁺, Fe²⁺, will produce carbonate eventually. These chemical processes are the main ways of CO₂ mineralization, and the corresponding geochemical processes equations are (6)–(8):

$${\mathrm{C}\mathrm{a}}^{2+}+{\mathrm{H}\mathrm{C}\mathrm{O}}_3^{-}\to \mathrm{C}\mathrm{a}{\mathrm{C}\mathrm{O}}_{3\left(\mathrm{s}\right)}+{\mathrm{H}}^{+}$$

(6)

$${\mathrm{M}\mathrm{g}}^{2+}+{\mathrm{H}\mathrm{C}\mathrm{O}}_3^{-}\to \mathrm{M}\mathrm{g}{\mathrm{C}\mathrm{O}}_{3\left(\mathrm{s}\right)}+{\mathrm{H}}^{+}$$

(7)

$${\mathrm{F}\mathrm{e}}^{2+}+{\mathrm{H}\mathrm{C}\mathrm{O}}_3^{-}\to \mathrm{F}\mathrm{e}{\mathrm{C}\mathrm{O}}_{3\left(\mathrm{s}\right)}+{\mathrm{H}}^{+}$$

(8)

3.3. Main Geochemical Interactions

At the first stage of injection, CO₂ will be stored in the free state in the reservoir. Hydrogen ions, induced by carbonic acid due to CO₂ dissolution, will reduce the pH value of brine, which will increase the reactivity of minerals and provide initial conditions for the CO₂-brine-rock reaction. Minerals dissolution and precipitation occur simultaneously. Dissolution is often observed first, and then precipitation. If minerals dissolution predominates, reservoir porosity will increase as well as its permeability. Otherwise, if the minerals precipitation plays a dominant role in reactions, the reservoir porosity will be weakened as well as its permeability. CO₂-brine-rock interaction can alter the mineral composition dramatically in the reservoir, and particularly have a significant influence on the reservoir pore structure, which will change the CO₂ storage capacity. In this numerical simulation, mineral dissolution and precipitation will be distinguished by negative and positive values, respectively, listed on the right side of the figures.

3.3.1. K-Feldspar

K-feldspar is the principal component of alkaline feldspar. In the laboratory, K-feldspar underwent only a weak dissolution and retained its crystalline form even in 100 °C [11]. However, K-feldspar dissolution can be observed on a large time scale in the numerical simulation. This means that in an acidic environment, it will be dissolved, as well as in CO₂ geological storage. The corresponding reaction equation is

$$\underset{\mathrm{K}-\mathrm{feldspar}}{\underbrace{\mathrm{KAlS}{\mathrm{i}}_3{\mathrm{O}}_8}}+4{\mathrm{H}}^{+}+4{\mathrm{H}}_2\mathrm{O}\to {\mathrm{K}}^{+}+{\mathrm{A}\mathrm{l}}^{3+}+3{\mathrm{H}}_4\mathrm{Si}{\mathrm{O}}_4$$

(9)

$${\mathrm{H}}_4\mathrm{Si}{\mathrm{O}}_4\to \mathrm{Si}{\mathrm{O}}_2+2{\mathrm{H}}_2\mathrm{O}$$

(10)

Quartz will precipitate while K-feldspar dissolves, according to Equations (9) and (10), which is consistent with the SiO₂ content increase in Section 3.3.3. In Equation (9), ${\mathrm{H}}_4\mathrm{Si}{\mathrm{O}}_4$ is in the form of hydrate and can be usually expressed as Equation (10).

K-feldspar dissolution can be modeled by numerical simulation, as shown in Figure 5. During the CO₂ injection period, there is only a little amount of dissolution, as shown in Figure 5a. The degree of K-feldspar dissolution increases gradually, as shown in Figure 5b–d. This means that a lot of CO₂ will be consumed by K-feldspar dissolution.

3.3.2. Albite

Albite showed no noticeable dissolution at lower temperature and weak dissolution at higher temperature [11]. In the numerical simulation, there is no change in albite volume content. Otherwise, albite precipitation is observed after 500 years, as well as 1000 years, as shown in Figure 6. This is because a large amount of ${\mathrm{A}\mathrm{l}}^{3+}$ is released by K-feldspar dissolution, which will combine ${\mathrm{N}\mathrm{a}}^{+}$ in brine-forming albite precipitation. The amount of albite precipitation in the acidized environment is much less than in the neutral environment from the comparison between Figure 6a,b. Moreover, precipitated albite will transform another secondary mineral, dawsonite, which can be found in the simulation after 2000 years, and the corresponding chemical equation is

$$\underset{\mathrm{albite}}{\underbrace{\mathrm{NaAlS}{\mathrm{i}}_3{\mathrm{O}}_8}}+\mathrm{C}{\mathrm{O}}_2+{\mathrm{H}}_2\mathrm{O}\rightleftarrows \underset{\mathrm{dawsonite}}{\underbrace{\mathrm{NaAlC}{\mathrm{O}}_3(\mathrm{OH}{)}_2}}+3\mathrm{Si}{\mathrm{O}}_2$$

(11)

Dawsonite does not always exist during the simulation period, which will dissolve after precipitation. The stability of dawsonite will be weakened with the increase in temperature.

3.3.3. Quartz

Quartz is commonly found in sand reservoirs, whose main chemical composition is SiO₂. It is difficult to observe quartz corrosion even at higher temperature. Some intense corrosion can be found at 250 °C [23]. In our simulation, there is little volume change during the first 30 years, as shown in Figure 7a. Quartz precipitation results in a volume content increase 300 years after injection, and the content continues to increase, as depicted in Figure 7b–d. The main reason of quartz precipitation is related to the dissolution of K-feldspar and albite, as illustrated in Equations (10) and (11).

3.3.4. Calcite

Calcite is one of the most common carbonate minerals, which distributes widely in various geological environments. During the simulation, calcite dissolves in the range of CO₂ sequestration area and precipitates in the other areas, as shown in Figure 8. On the one hand, calcite dissolution in acidized brine can be described by chemical equations (Equations (4) and (5)). On the other hand, in a neutral environment, ${\mathrm{Ca}}^{2+}$ will combine with ${\mathrm{H}\mathrm{C}\mathrm{O}}_3^{-}$ or ${\mathrm{C}\mathrm{O}}_3^{2-}$, leading to calcite precipitation. This can be observed in Figure 8b-d, where some dark red areas are regions with the highest density of calcite precipitation.

3.3.5. Other Minerals

Some other minerals precipitations can be found in the simulation, such as siderite and ankerite, as shown in Figure 9 and Figure 10. It is the important way of CO₂ mineralization after CO₂ injection into the reservoir.

Siderite is formed in the region between the CO₂ acidized area and neutral area. In this region, CO₂ dissolution into the brine will provide ${\mathrm{C}\mathrm{O}}_3^{2-}$, which will combine with Fe²⁺ to form siderite precipitation. In the CO₂ acidized area, siderite will dissolve because of the lower pH value. In the neutral area, there is not enough ${\mathrm{C}\mathrm{O}}_3^{2-}$ to form precipitation. This is the main reason for siderite precipitation along the junction area. Ankerite precipitation can be found 500 years after injection. After that, a large amount of ${\mathrm{C}\mathrm{a}}^{2+}$ will be provided by calcite dissolution, and there is more ankerite precipitated in the higher-pH area than in the lower-pH area.

3.4. Porosity and Permeability

There are many methods to deal with the permeability variation of the reservoir. Here, the Kozeny-Carman equation is used to calculate the permeability value of the reservoir as the porosity changes [16]. There are some assumptions when dealing with this problem, such as the reservoir rock with uniform voids, ignoring the influence of rock particle size, bending degree, and reaction surface area, whose changes have no effect on permeability. The Kozeny-Carman equation is listed as follows:

$$k=k_i\frac{{\left(1-{\varphi }_i\right)}^2}{{\left(1-\varphi \right)}^2}{\left(\frac{\varphi }{{\varphi }_i}\right)}^3$$

(12)

where $k_i$ and ${\varphi }_i$ are the initial permeability and porosity, respectively. Variations in both porosity and permeability are illustrated in Figure 11 and Figure 12, respectively, and the simulation time is 1000 years. The porosity will first increase and then decrease. The increase is due to primary minerals dissolution and the decrease is due to secondary minerals precipitation. According to Figure 11 and Figure 12, their trends are almost the same, because the relationship between porosity and permeability is chosen as positively correlated.

3.5. Long-Term CO₂ Geological Storage

After 2000 years of CO₂ injection into the target area, the corresponding volume content changes of main minerals are shown in Figure 13, Figure 14, Figure 15, Figure 16, Figure 17, Figure 18 and Figure 19.

For K-feldspar dissolution reaction, the higher the content, the greater the dissolution, as shown in Figure 13. Because of both K-feldspar and albite generating ${\mathrm{A}\mathrm{l}\mathrm{O}}_2^{-}$, there will be a common ion effect. Therefore, the degree of K-feldspar dissolution in Case 2 is greater than in Case 1, as shown in Figure 13a,b. The reason is that the albite content in the latter case is almost twice the value of the first case. There is much more K-feldspar dissolution in Cases 3 and 4 than in Cases 1 and 2, because of the greater content than in Cases 3 and 4, as depicted in Figure 13c,d.

The contents of calcite in four cases are almost the same, as well as chlorite. There is little difference in the amount of dissolution of both calcite and chlorite, which can be found in both Figure 14 and Figure 15. Chlorite dissolution will produce large amounts of ${\mathrm{M}\mathrm{g}}^{2+}$, ${\mathrm{A}\mathrm{l}}^{3+}$, and ${\mathrm{A}\mathrm{l}\mathrm{O}}_2^{-}$. ${\mathrm{M}\mathrm{g}}^{2+}$ is the main source of magnesite, smectite-Na, and smectite-Ca precipitation, as shown in Figure 16, Figure 17 and Figure 18, respectively. ${\mathrm{A}\mathrm{l}}^{3+}$ is the main source for smectite-Na and smectite-Ca precipitation.

The amount of smectite-Na precipitation is proportional to the content of albite. The largest amount of smectite-Na precipitation appears in Figure 17a, and the least amount appears in Figure 17c. For smectite-Ca precipitation, the largest amount appears in Case 1, as shown in Figure 18, which corresponds to the least amount of illite precipitation. The reason for the smallest illite precipitation in Case 1, to some extent, is that smectite-Ca takes up more ${\mathrm{M}\mathrm{g}}^{2+}$ and ${\mathrm{A}\mathrm{l}}^{3+}$.

Illite precipitate is also an important secondary mineral in CO₂-brine-rock interactions. From Figure 19, we can see that Case 3 has the largest amount of illite precipitation, and the next is Case 4, both of which are proportional to the contents of K-feldspar, as listed in Table 2.

For different compositions of the reservoir, the degree of minerals dissolution may vary as well as minerals precipitation, which may lead to a different variation tendency. On the one hand, the porosity will increase first due to minerals dissolution after CO₂ injection into the reservoir, which results from the lower pH value of brine because of the acidity of CO₂. On the other hand, the porosity will then decrease due to the formation of secondary minerals in the CO₂-brine-rock reaction, resulting in precipitation. Therefore, the change in reservoir porosity results from two reactions: primary mineral dissolution and secondary mineral precipitation. As shown in Figure 20 and Figure 21, the porosity and permeability change in different cases. The overall trends are similar. The decrements of Case 2 and Case 3 are larger than those of the other two cases. Case 1 and Case 4 are almost the same. These differences may be associated with anorthite and K-feldspar dissolution. The sum of the two feldspar determines the decrease in porosity and the permeability. For CO₂ geological sequestration, mineralization will consume vast quantities of CO₂ regardless of the matter dissolution or precipitation. The process is of positive significance to safe CO₂ sequestration, which is regarded as the safest storage mechanism.

4. Conclusions

The process of CO₂ sequestration will have significant impacts on the geochemical properties and physical parameters of the reservoir. During CO₂ injection, the largest factor affecting the security of storage is the rapidly increasing pressure brought by gas injection. The gas saturation in the reservoir reaches the maximum around the injection well at the end of the injection period, which is the time node with the highest probability of reservoir risk. After that, CO₂ will migrate horizontally. The spreading width may be several kilometers; however, the risk of leakage may be reduced. During the long storage life after injection, the CO₂-brine-rock reaction driven by a large amount of CO₂ exerts the greatest influence on the reservoir physical properties.

Carbonation is the most important one among all interactions according to the numerical simulation. The acidized brine will promote CO₂-brine-rock interactions because of CO₂ dissolution. The lower pH will increase the reaction rate, and the reaction will buffer the pH value of acidized brine. Feldspar, calcite, and chlorite will dissolve once CO₂ is injected into the reservoir. Magnesite, illite, smectite, siderite, and ankerite will precipitate after the beginning of the dissolution. Minerals dissolution will provide cations for secondary minerals precipitation. To analyze the sensitivity of numerical simulation, we also set four cases to investigate the mineral contents effect on the reaction. The results show that there is competition among ions. One mineral may precipitate first, which may result in another mineral precipitation decrease.

Moreover, the CO₂-brine-rock interaction occurring after CO₂ injection can alter the physical property distribution of the reservoir. From the simulation results, the porosity of the reservoir increases first and then decreases on long-term CO₂ sequestration, which is closely related to the geochemical reaction of the main minerals. On the contrary, mineral components of the reservoir are of great significance to the mineralization of CO₂. Regardless of the mineral dissolution or precipitation, they all play important roles in the long-term safe storage of CO₂. On the one hand, these interactions will promote CO₂ dissolution and reduce leakage risk; on the other hand, secondary minerals in the CO₂-brine-rock reaction can permanently sequester CO₂ in the reservoir. Although the reaction rate is very slow, it is the most ideal storage mechanism from the perspective of storage safety.