Geochemical Modeling of Changes in Storage Rock Environments at CO₂ Injection Sites

Abstract

Geochemical modeling in TOUGHREACT code was used to simulate chemical processes in CO₂–rock–brackish water systems in a pilot research environment of CO₂ storage in the Brodske area (Czech Republic). Models studied mineralogical changes in rock samples resulting from acidification of the aqueous phase caused by the dissolution of pressurized supercritical CO₂. Rock samples of the reservoir horizon and cement from the grouting of an injection borehole were considered, and the water phase represented the mineralized groundwater. The aim of the study was to characterize the influence of CO₂ in the geological structure on mineralogical rock changes and to predict gas distribution through the rocks bearing brackish water. The most important chemical processes are dissolution of carbonates and clay minerals during the injection of CO₂ into the structure, as the increase in porosity in the structure affects the sequestration capacity of the reservoir rock. In the CO₂–cement–brackish water system, the models confirm the rapid dissolution of portlandite and its replacement with calcite. The CSH gel is also dissolved, and silica gel appears. The porosity of the cement decreases. Further studies on such a cement slurry are needed to prevent the possibility of mechanical damage to the integrity of the borehole.

1. Introduction

Several publications on carbon capture and storage (CCS) mention and detail specific experiments that precede the implementation of CCS in various geological structures [1,2,3,4,5,6]. Experiments with mixed fluids between supercritical CO₂ and saline NaCl have been described [7,8,9]. Experiments have shown that the injection of CO₂ into the rock system leads to complex and significant changes in the nature of such a system. One of many accompanying phenomena is, for example, the nucleation and growth of new carbonate and silicate minerals [9,10,11]. The accompanying phenomenon is a change in the permeability of the storage reservoir structure, which may have a negative impact on the entire storage system.

The same has been demonstrated in experiments simulating P-T conditions of real potential storage. It turns out that the interaction between the CO₂–H₂O system of sedimentary rock with carbonate cement leads to the dissolution and re-formation of carbonate minerals [12,13]. The study of Brandl et al. [14] also mentions the reduction of porosity near injection boreholes. Clogging involves reactions between carbonates, clay and related minerals, oxides, hydroxides, and iron sulfides. A significant, and in some cases essential, source component for the formation of clogging minerals is the borehole’s own material, the grouting [15,16]. Crystallization processes are controlled mainly by the partial pressure of CO₂, pH, and groundwater flow [17,18]. Oxidation–reduction reactions of iron are also of major importance.

Processes occurring in the environment of the reservoir after CO₂ injections have been clearly and conclusively described in many articles [3,4,5,6], particularly those relating to geochemical changes in both the reservoir and the overlying confining layer [1,2,4]. Changes in minerals and pore space can affect storage capacity and injectivity in the short term; in the long run, they affect the distribution of individual phases (fluids, rocks) [3,13]. Therefore, it is necessary to model the various aspects of these processes, both at the microscale (e.g., changes in minerals and pore space) and at the macroscale (e.g., the development of new preferential migration pathways due to the dissolution of minerals, fluid quality changes, etc.). Geochemical modeling of rock alterations is therefore a key supportive method for assessing the safe operation of future storage [6]. This study is focused on simulating chemical processes in CO₂–rock–brackish water systems in a pilot research environment of CO₂ storage in the Brodske area (South Moravia, Czech Republic). This location is an extracted oil deposit and is potentially suitable for CO₂ injection.

2. Materials and Methods

Models involving kinetic transport through porous media and thermodynamic issues of multiphase systems are very useful in forecasting the impact of CO₂ injections on the changes to the rock environment at the site. These models are based on information regarding petrophysical, mineralogical, and hydrogeological characteristics of porous media, hydrochemical analysis of fluid composition, pressure and temperature values of the deposit, and kinetic parameters.

2.1. Input Parameters for the Model

A model of reservoir rocks of the Labsky horizon (labeled Br-52) from the locality of Brodske was considered. A description of the rock is given in

Table 1. The samples of reservoir rocks.

Borehole	True Vertical Depth (m)	Stratigraphy	Lithology
Br-52	1150–1155	STBA* Reservoir	Medium-grained calcareous sandstone

* STBA—Middle Badenian.

. The Labsky horizon lies at a depth of about 1000 m and is formed by a Miocene sandstone about 15.5 million years old (stratigraphically belonging to the Middle Badenian). A Br-52 sample is considered a representative sample of the rock of the storage reservoir. It is a mid-Badenian medium-grained sandstone located at a depth of 1150 m, from what is called the Labsky horizon.

As a sample of the water phase, which forms the filling of the pore space of the reservoir formation in the so-called Labsky horizon, the water solution from the Br-45 borehole was used. The water sample from the aquifer was taken by the project partner (MND Energie a.s.) from a depth of 1105 m and the chemical analysis of the water was carried out in the laboratories of the ÚJV Řež, a.s. near Prague. Thereafter, synthetic water was produced in the same laboratory, and its chemistry corresponded to the water composition in the aquifer. The chemical composition of this solution is shown in

Table 2. Physico-chemical parameters of synthetic brackish water Br-45.

Synthetic Water Br-45
Ca2+	(mg/L)	142.9
Mg2+	(mg/L)	55.2
Na+	(mg/L)	3777.0
K+	(mg/L)	84.6
Cl−	(mg/L)	4826.2
HCO3−	(mg/L)	1410.9
SO42−	(mg/L)	785.9
TDS *	(mg/L)	10,998.1
Other parameters
T *	(°C)	43
pH	-	8.1
Ι *	mol/L	0.21
depth	meter	1105

* TDS—total dissolved substances; T—temperature; I—ionic strength.

.

For modeling changes in the rock environment, it was also necessary to consider the entry of a gaseous CO₂ phase which, under the bearing horizon conditions (temperature: 43 °C, pressure: 116 bar), achieves a supercritical state with a resulting equilibrium partial pressure (P_CO2) of approximately 115.5 bar. These values were determined by the project partner (MND Energie a.s., Hodonin, Czech Republic) and were based on values monitored directly on site.

The mineralogical and petrophysical properties of the studied rock sample, the characteristics of the cement in the boreholes, and the hydrogeological parameters of the reservoir at the location in question are described in

Table 3. Mineralogical composition of the studied rock sample (wt%) and conversion to percentages by volume (vol.%).

Borehole	Q	Mu	Mic	Chl	Calc	Dol	Alb	Gyp	Porosity	Specific Surface
Br-52	(wt%)	(wt%)	(wt%)	(wt%)	(wt%)	(wt%)	(wt%)	(wt%)	(%)	(m2/g)
	60.22	9.83	3.85	6.42	6.97	3.12	7.66	1.92	24.51	0.88
	(vol.%)	(vol.%)	(vol.%)	(vol.%)	(vol.%)	(vol.%)	(vol.%)	(vol.%)	(%)
	46.52	7.10	3.08	3.97	5.26	2.23	6.00	1.33	24.51

Q—quartz, Mu—muscovite, Mi—microcline, Ka—kaolinite, Chl—chlorite, Calc—calcite, Sid—siderite, Dol—dolomite, Alb—albite, Gyp—gypsum.

,

Table 4. Mineralogical composition of the cement sample (wt%) and conversion to percentages by volume (vol.%).

Mineral	Formula	wt%	vol.%
CSH1.6	Ca1.6SiO3.6:2.58H2O	42.3	27.43
Portlandite	Ca(OH)2	25.2	18.79
Ettringite	Ca6Al2(SO4)3(OH)12:26H2O	18.2	9.94
Hydrotalcite	Mg4Al2O7:10H2O	5.9	3.89
Katoite-Si	Ca3Al2SiO4(OH)8	5.7	7.56
C3FH6	Ca3Fe2(OH)12	1.9	3.96
Calcite	CaCO3	0.8	0.43

and

Table 5. Hydrogeological parameters of reservoir rock with medium-grained calcareous sandstone.

Parameters	Value	Unit
thickness	20	m
porosity	24.5	%
horizontal permeability kR	450	mD
vertical permeability kz	4.5	mD
pressure P	116	bar
temperature T	43	°C
max. salinity S	72	g/L
CO2 density	195	kg/m3
CO2 viscosity	1.5 × 10−4	Pa·s

, respectively.

The mineralogical composition of Br-52 samples was determined by XRD analysis. XRD powder data were measured at room temperature on a Bruker AXS D8 θ-θ powder diffractometer (Karlsruhe, Germany) in Bragg–Brentano parafocusing geometry using CoK_α wavelength (λ = 1.7903 Å, U = 34 kV, I = 30 mA). Porosity was determined using Hg-porosimetry, and the specific surface area was found by the N₂-BET method by adsorption–desorption isotherms. The samples from borehole Br-52 were part of the drill core and came from depths corresponding to the reservoir rock.

The use of classic Portland cement CEM II/B-M (S-V) 32.5R is assumed for the equipped of boreholes through which CO₂ will be injected into the structure. The main component of the cement is Ca–Si hydrate (CSH1.6) [11,19]. The composition of the cement, reported in the literature [11,19,20], corresponds to the analysis of the real sample (sample of Portland cement from borehole Br-52 equipment) used in the model. The mineralogical composition of the cement sample in wt% and vol.% is shown in Table 4.

The hydrogeological parameters of the Labsky horizon are important for understanding and predicting changes in the storage area. These parameters are summarized in Table 5. It is assumed that there is higher horizontal permeability k_R than vertical permeability k_z due to the geological processes undergone during sedimentation. These data were taken from the project partners, and they published their results in a scientific journal [13]. In agreement with Wertz et al. [13], we assumed that due to geological processes undergone during sedimentation, the horizontal perm is 100 higher than the vertical perm. The density and viscosity of CO₂ are dynamically determined in the TOUGHREACT program by the ECO2N module as a function of pressure P, temperature T, and salinity S [21,22].

During the modeling of the spread of injected CO₂ using hydrogeological parameters, an z–x coordinate cylinder was considered, where the x-axis is the distance from the borehole in kilometers, and the z-axis is the thickness of the reservoir. The x-axis is 6 km long and the z-axis is 20 m thick. The network is made up of 193 cells with an exponentially increasing radius. Models were developed in TOUGHREACT (with ECO2N) [22]. The porosity was assumed to be homogeneous throughout the reservoir. The calculations were performed based on the Darcian flow in a porous environment. In the calculations, the amount of CO₂ injected into the reservoir was 8750 tCO₂/year. This parameter was determined by the project partner (MND Energie a.s.).

The fluid dynamic model and the geochemical simulations of mineralogical rock changes were implemented separately.

2.2. Geochemical Modeling

The applied models specified below were designed to describe processes with (a) a short injection time (i.e., dynamic 1-year simulations of instantaneous chemical change in the reservoir affected by the start of CO₂ injection), (b) a longer-term reactivity of CO₂ with the rock environment (6 or 8 years of injection of CO₂ into the storage site), and (c) a long-term period of storage relaxation after the injection (500 years).

The results presented in the following chapter are the outputs of equilibrium, kinetic, and multiphase modeling of the geochemical reactivity of the CO₂–water–rock system, determining the influence of CO₂ on the porosity in the near field of the injection borehole.

Equilibrium models were designed to evaluate changes in porous water chemistry after CO₂ injection into the reservoir to express balances in the rock–CO₂–brackish water system, and to express the solubility of CO₂ in brackish water Br-45. Kinetic and multiphase modeling was conducted to evaluate hydrogeochemical changes in the studied formation in relation to the injection and storage of CO₂ in the structure. This allowed for the assessment of volumes and quantities of precipitated or dissolved mineral phases and of their impact on reservoir rock permeability in relation to the prediction of possible CO₂-related risks.

TOUGHREACT, The Geochemist’s Workbench, and PHREEQC modeling programs were used to meet the above objectives. Modeling systems for the TOUGHREACT multiphase modeling included the ECO2N Thermodynamic Module. Supporting kinetic and thermodynamic models were applied using The Geochemist’s Workbench (GWB) Release 6.0 [23] and additional equilibrium calculations were performed in the PHREEQC program (version 3).

The thermodynamic databases “thermo.dat” (built in the GWB package), the PHREEQC database [24], and the THERMODEM database [25,26] were used.

3. Results and Discussion

3.1. Changes in Br-45 Brackish Water Chemistry after CO₂ Injection

The reaction of CO₂ with groundwater and its effects on potential storage are of utmost importance for the process of mineral sequestration because only a dissolved form of CO₂ can react with the rock. CO₂ solubility is a function of the temperature, pressure, and salinity of the solution, with CO₂ solubility decreasing with increases in the temperature and molarity of the solution, while CO₂ solubility increases with increasing pressure. The dissolution was carried out until the thermodynamic equilibrium was reached and the solution was saturated with CO₂. Based on the input parameters used in the PHREEQC model (Br-45 brackish water chemistry, P_CO2 = 116 bar, and temperature = 43 °C), we report the theoretical acidification of Br-45 brackish water as a result of CO₂ injection and calculated chemistry changes in

Table 6. Original and model-calculated acidification of Br-45 brackish water.

		Original Br-45	Acidified Br-45
Ca2+	(mg/L)	142.9	142.48
Mg2+	(mg/L)	55.2	55.03
Na+	(mg/L)	3777.0	3765.76
K+	(mg/L)	84.6	83.8
Cl−	(mg/L)	4826.2	4867.7
HCO3−/CO2(aq)	(mg/L)	1410.9	113,021.26
SO42−	(mg/L)	785.9	783.56
TDS	(g/L)	10,998.1	10,998.1
Other parameters
T	(°C)	43	43
pH	-	8.1	4.1
Ι	mol/L	0.21	0.18

log P_CO2 = 2.065.

. The HCO₃⁻ ion is the dominant carbonate component in the solution at alkaline pH. When the pH drops to the acidic values, the bicarbonate ions decrease in solution and carbonic acid, respectively, and CO₂ (aq) [18,27] becomes the dominant carbonate component.

The change in the character of the input water after CO₂ injection calculated in the PHREEQC program corresponds to the chemical changes of the original water as modified by the TOUGHREACT program in its first-time step. The differentiated chemistry of Br-45 brackish water is then used in simulations in this program as its next steps.

The calculations in PHREEQC were carried out to confirm the changes in the chemistry of the input water.

The process of dissolving CO₂ in a brackish water solution results in the dissolution of certain minerals of the geological environment in which the CO₂ is injected and then is followed by the precipitation of new minerals. This can ultimately lead to changes in the permeability of the rock environment and to a reduction in the capacity of the injected CO₂.

3.2. Modelled Spreading of the Injected CO₂ in Potential Storage

The modeled spread of injected CO₂ in the potential storage is presented in this chapter during the ongoing CO₂ injection period (for the first year and 6 years). The saturation of the environment with the injected gas after the end of the injection is shown here after 100 and 500 years.

Figure 1 is a model showing the evolution of CO₂ pressure in the reservoir and the saturation of the environment with the injected gas after the first year of injection. The initial value was 11.5 MPa.

In the first year of CO₂ injection, the pressure had a steady value of 9.96 MPa in the immediate surroundings of the injection. Despite the pressure decrease against the original value, the CO₂ pressure in the reservoir increases within the entire length of the model profile after one year of the injection. The highest value of 9.96 MPa was reached within the first 200 to 500 m from the injection borehole (Figure 1a). Furthermore, within the length of the model profile, the pressure has the value of 8.4 MPa with increasing distance from the injection borehole.

The pore environment of the reservoir was saturated with gas after the first year of CO₂ injection within a distance of 600 m. Maximum values of 50% of the value of the modelled supercritical pressure SG (P_CO2 = 116 bar) were achieved in the immediate vicinity of the injection borehole (Figure 1b).

Figure 2 shows the evolution of CO₂ pressure in the reservoir and the saturation of the environment injected with gas after 6 years of injection. Figure 1 and Figure 2 show an increasing radius with respect to the injection well.

After 6 years, an injection pressure of 9.9 MPa was found within a distance of 1 km from the injection borehole (Figure 2a). Within a distance of 2.2 km, the structural pressure was equal to 9.4 MPa. In the remaining length of the model profile, the pressure value with increasing distance from the injection site drops to 9.0 MPa (Figure 2a). The saturation of the pore environment of the reservoir extends to about 2.7 km from the injection borehole after 6 years of injection. Maximum values of 100% of the modelled supercritical pressure SG (P_CO2 = 116 bar) were reached within the first tens of meters from the borehole (Figure 2b).

Figure 3 shows the saturation of the environment with the injected gas 100 and 500 years after the injection. After 100 years, the saturation of the pore environment by the gas at the top of the reservoir increases to almost 6 km (Figure 3a). On the contrary, at the base of the reservoir, the gas saturation is minimal (Figure 3a). After 500 years of structure relaxation, the loss of saturation in the pore environment due to dissipation of the gas (Figure 3b) is evident throughout the model profile.

Figure 4 presents a model representing the amount of dissolved CO₂ in a reservoir with a growing radius from the injection borehole and a relaxation time of 100 years (Figure 4a) and 500 years (Figure 4b) from injection. The solubility of CO₂ is almost constant, so CO₂ (aq) is in thermodynamic equilibrium with the surrounding brackish water at a concentration of 60.26 g_CO2/kg_brine throughout the structure that the cloud of injected CO₂ passed through. It can also be concluded that the amount of CO₂ (aq) in the pore environment of the storage structure decreases with increasing relaxation time (Figure 4).

The differences in permeability strongly affected the kinetics of saturation at depth, as shown by the coarser pressure and saturation changes in z-axis compared to x-axis after CO₂ injection ceased (Figure 1, Figure 2, Figure 3 and Figure 4).

3.3. Modelled Mineralogical Changes in the Rock Mass Storage after the Injection of CO₂

Geochemical simulations of mineralogical rock changes in a potential CO₂ storage site were carried out using a batch simulation method. Batch simulation allows the performance of numerous successive simulation runs. They were used to explore the parameter space of a model or to optimize a set of model parameters. Thermodynamic data for individual rock-forming minerals and Portland cement (borehole grouting) were determined using the THERMODDEM database [25]. These data consist of thermodynamic equilibria and saturation indices. Not all mineral phases forming the rock of the reservoir rock of the potential storage are listed in the used chemical database. Furthermore, the model does not distinguish between microcline and orthoclase, so if microcline is transformed into orthoclase after a reaction with acidified brackish water, this change will not be reflected in the model. However, a decrease or increase in the concentration of a given mineral due to ongoing reactions can be observed. However, this process is not expected. It is impossible to transform microcline into orthoclase in the testing conditions. These processes can only occur in metamorphic and igneous systems. Acidification of microcline is hydrolyzing microcline into clays. Kaolinite, siderite, and magnesite were not identified in the real rock sample Br-52, yet they are accounted for in the model. Clay minerals are a typical product of weathering, and kaolinite was chosen as their most common representative. Siderite was selected as a possible secondary phase, binding iron ions from solution. Precipitation of magnesite was assumed in the case of enrichment of the solution with magnesium. However, the formation of these secondary phases can only be expected if the pH of the brackish water solution increases again.

The kinetic parameters (the kinetic constant for 25 °C; the activation energy of the reaction; the degree of the reaction mechanism; the reactive surface of the mineral) of primary and secondary minerals used in model simulations have been taken from the literature data [20,28,29,30].

Table 7. Mineral phases used in the model.

Mineral	Formula
Quartz	SiO2
Muscovite	KAl2(AlSI3)O10(OH)2
Microcline	KAlSi3O8
Chlorite	Fe5Al(AlSi3)O10(OH)8
Calcite	CaCO3
Siderite	FeCO3
Dolomite	CaMg(CO3)2
Albite	NaAlSi3O8
Kaolinite	Al2Si2O5(OH)4
Gypsum	CaSO4∙2H2O
Magnesite	MgCO3
CSH1.6	Ca1.6SiO3.6:2.58H2O
Portlandite	Ca(OH)2
Ettringite	Ca6Al2(SO4)3(OH)12:26H2O
Hydrotalcite	Mg4Al2O7:10H2O
Katoite-Si	Ca3Al2SiO4(OH)8
C3FH6	Ca3Fe2(OH)12

shows all the mineral phases that were calculated in the model.

The input parameters for modeling mineralogical changes in fluid-bearing rock and borehole grouting are as follows: the chemical composition of brackish water Br-45 (Table 6), the mineralogical composition (in vol.%) and porosity (in%) of real studied rock samples (Table 3), and of Portland cement (see Table 4). Porosity changes were quantified from mass balance. The injected amount of CO₂ was assumed to be 8750 t_CO2/year, corresponding to an injection rate of 0.28 kg_CO2/s.

pH is the key to phase stability. At a distance of 20 m from the injection well, a sharp drop in pH will occur in the storage structure in the first year of injection. In the first months, the pH of the brackish water used in the modeling is relatively stable at its original value of 8.1. In the third and fourth months, the pH will drop for the first time to a value of around 6.4. This may be due to the dissolution of gypsum and calcite. The buffering capacity of the reservoir rock decreases. After 6 months, when the system was buffered with carbonate substances contained in the solution and the pH value dropped from 6.4 to only 6.2, there will be a further drop in pH to 4.5. The pH then decreases slightly until the end of the first year of injection, when it reaches a value of 4.2 at a distance of 20 m from the injection well.

After the end of CO₂ injection into the reservoir rock of the potential storage at a distance of 20 m from the injection well, the pH will rise very quickly to the value of 7. The maximum value of pH 7.3 will be reached after about 100 years. Subsequently, it slowly decreases again. The reasons for this decrease may be the same reactions that led to the decrease in pH near the injection well. Thus, it may be related to the release of residual CO₂ trapped in the structural pastes, to the dissolution of magnesite, or to both processes simultaneously. After about 350 years, the pH value drops to a final value of 6.4 and does not develop further.

Mineralogical changes in the reservoir rock at 20 m from the injection borehole over 8 years of storage operation are shown in Figure 5a. The model shows that, about 4 years after injection, the dolomite and the microcline are slightly decreasing. Microcline decreased right away, but it began to stagnate from the fourth year. The brackish water is enriched with magnesium, which leads to the precipitation of magnesite. After 6 years, calcite and gypsum dissolve slightly, releasing calcium, carbonate, and sulfate ions. Quartz, albite, chlorite, and muscovite remained stable throughout the storage operation.

Five years after injection was completed, dolomite was completely dissolved (Figure 5b) and replaced with magnesite. After 60 years, the gypsum was dissolved completely, and the calcite was slightly dissolved. Calcite enters the model with a higher volume% value than dolomite. Calcite generally has faster kinetics than dolomite, but it also depends on the mass balance of both minerals and environmental conditions. The brackish water is saturated with Ca²⁺ and HCO₃⁻ ions during the dissolution of both minerals. As a result of the dissolution of other phases, the brackish water may become oversaturated with calcium and bicarbonates. Secondary calcite will form, as in this case.

One hundred years after injection, a decrease in magnesite is evident (Figure 5b). This may be related to the pH variation in the reservoir rock. Dissolving magnesite not only releases magnesium, but also carbonate ions that can bind to protons and increase pH.

At a higher pH, calcite is precipitated again after about 200 years, as can be seen in Figure 5c. After 250 years, the microcline is completely dissolved, and the clay minerals of the chlorite groups are precipitated. The other minerals are stable even 500 years after injection (Figure 5c).

The model shows an increase in porosity during injection (Figure 5a) from the original 24.5% to 27%. The porosity slightly decreases after CO₂ injection (26.5%) and slightly increases over 100 years of relaxation to a value of 29% (Figure 5b). After 200 years, porosity slightly decreases to a value of 28.5%, and for the next 300 years it stagnates at a given value (Figure 5c). The decreasing porosity may be associated with the precipitation of calcite and chlorite group clay minerals. This is volumetrically overcompensating dissolution.

The composition of the cement in vol.% grouting of the injection borehole is described in Table 4. It is typical of Portland cement.

Experiments confirm the rapid dissolution of portlandite and its replacement by calcite. The Ca–Si hydrate (CSH) gel is also dissolved, and silica gel (i.e., silica) appears. Porosity decreases slowly in the first few years of injection, mainly due to the precipitation of calcite.

After the completion of injection, the CSH gel is completely dissolved and is replaced by precipitates of calcite and silica (Figure 6a).

Katoite and hydrotalcite also dissolve. These processes are slower and contribute to the formation of Al gels (i.e., boehmite). The porosity of the cement drops after the end of CO₂ injection, dropping from the original value of 28% to 22% after 100 years of relaxation time (Figure 6b).

4. Conclusions

The TOUGHREACT program was used to simulate the geochemical reactions of injected CO₂, with the aim to predict gas distribution through the rocks bearing the brackish water during the injection (1 and 6 years) and in the 100 and 500 years of relaxation.

It was found that the CO₂ pressure in the reservoir increases within the entire length of the model profile after one year of grouting, reaching 9.96 MPa in the first 200 m from the injection borehole. Furthermore, within the length of the model profile (6 km), the pressure drops with increasing distance from the injection borehole to a value of 8.4 MPa. The pore environment of the reservoir is saturated with gas after the first year of CO₂ injection only. within a distance of 600 m. After 6 years, an injection pressure of 9.9 MPa was found within a distance of 1 km from the injection borehole. Within a distance of 2.2 km, the structure pressure is equal to 9.4 MPa.

For the remaining length of the model profile, the pressure drops with increasing distance from the injection site to a value of 9.0 MPa. The pore saturation of the reservoir rock is extended to about 2.7 km from the injection borehole after 6 years of injection. Maximum values of 100% of the value of the modelled supercritical pressure SG (P_CO2 = 116 bar) were reached within the first tens of meters from the borehole.

One hundred years after injecting, the pore saturation by the gas at the top of the reservoir increased to almost 6 km away. On the contrary, at the base of the reservoir, the saturation of the gas is minimal, and after 500 years of structure relaxation, there is a noticeable loss of pore saturation by the gas within the whole model profile. It is also evident that the amount of CO_{2 (aq)} in the pore environment of the storage site structure decreases with increased relaxation time. Similar conclusions were reached by other authors [9,13] who were involved in modeling the spread of injected CO₂ into the structure of sedimentary rocks.

Interactions were also studied in the CO₂–rock–brackish water system (models were made for reservoir rock). The aim was to characterize the influence of CO₂ in the geological structure on mineralogical rock changes from the potential storage site.

For reservoir rocks, the most important chemical processes are the dissolution of carbonates (calcite and dolomite) and microcline due to acidification of the brackish water during the injection of CO₂ into the structure. The dissolution of some mineral phases during the injection and the increase in porosity in the structure affect the sequestration capacity of the reservoir rock of the potential storage site. The dissolution of carbonates and microcline was also confirmed in their study by Wang et al. (2019) [6]. In her study, Gaus et al. (2008) [9] describes the importance of the dissolution of mineral phases for the increased storage capacity of the reservoir rock. The results of the presented work are in agreement with the conclusions of these authors.

Other chemical processes that the models describe include the precipitation of magnesite, which replaces dissolving dolomite completely, and the formation of secondary carbonates as a result of the increasing pH of the brackish water in the structure over a longer period of time after injection is ceased. Carbonate minerals bind CO₂ to their structure and help to stabilize the pH of the brackish water after injecting. The consequence of this process is, however, the reduction in the porosity of the reservoir rock. Klunk et al. (2020) [31] also observed the precipitation of magnesite in his work at elevated pressure-temperature and high salinity.

In the long term, these processes are desirable. The formation of secondary phases is considered useful during the relaxation period of the deposit after CO₂ injection [1,4]. The newly formed phases close the injected CO₂ in the structure and thus contribute to the stability of the environment. They also represent a barrier for possible CO₂ leaks into the caprock [5,6].

The porosity of reservoir rock increases by 4% during the model period, i.e., after 8 years of injecting and then 500 years of structure relaxation.

Experiments in the CO₂–cement–brackish water system were carried out in order to determine and describe the degradation of the cement grouting of the borehole. The models confirm the rapid dissolution of portlandite and its replacement with calcite. Kutchko et al. (2007) [32] conducted laboratory experiments of well cement degradation by CO₂-rich brine under geological (P, T) conditions and proposed a degradation mechanism for Portlandite. Indeed, CO₂-rich acid brine dissolves Portlandite Ca(OH)₂ and precipitates Calcite CaCO₃. The CSH gel is also dissolved, and silica gel (i.e., silica) appears. Porosity decreases quickly in the first few years, mainly due to the precipitation of calcite. After completion of the injection, the CSH gel is completely dissolved, replaced by the precipitation of calcite and silica. Other authors [33,34] have come to the same conclusion. In their papers they also describe the decalcification of the CSH phases, and that CO₂ mainly affects the initial phases of the cement: portlandite, CSH and aluminates. In addition, carbonation is complete and leads to the formation of amorphous silicates. Katoite and hydrotalcite also dissolve. These processes are slower and contribute to the formation of Al gels (i.e., boehmite). The porosity of the cement after the cessation of CO₂ injection continues to decrease, dropping from the original value of 28% to 22% over 100 years of relaxation. Mineral changes are very obvious. The deterioration of the sealing capacity of the borehole grouting and the potential risks of CO₂ leakage through the borehole casing are evident precisely because of the mineral changes and the speed of these processes, especially during the first years of CO₂ injection. Experiments by Jobard (2013) [19] show that the cement structure is nevertheless maintained, and so might not endanger the tightness of the cement. It is therefore necessary to carry out further studies on such a cement slurry and to prevent the possibility of mechanical damage to the integrity of the borehole.

Immediately after its injection, CO₂ spreads in its supercritical form and partially dissolves into the groundwater [1]. This process significantly changes mineralogical, hydrogeological, and geochemical conditions at the storage site [2,3,4]. It acidifies the original groundwater of the brackish water type; it can influence hydrogeological parameters, especially the porosity and permeability of the deposit rock; it changes the mineralogical composition of the deposit rock and can mineralogically affect the confining layers in the overburden; and it causes chemical changes in the cement grouting of the borehole [2,3,4,5,6]. All these reactions can be a potential risk for the CO₂ storage process in the selected structure and can lead to CO₂ leakage from the deposit to the surface [7,8]. It is therefore necessary to understand the mechanism of these reactions and to quantify and evaluate them to ensure the safety and sustainability of storage [1,4,6].