# Influence of Caprock Morphology on Solubility Trapping during CO2 Geological Sequestration

Authors: Pradeep Reddy Punnam; Balaji Krishnamurthy; Vikranth Kumar Surasani
Journal: Geofluids
 (2022)

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## Abstract

Carbon capture and sequestration (CCS) technology is one of the indispensable alternatives to reduce carbon dioxide (CO2) emissions. In this technology, carbon capture and transport grid will send CO2 to the storage facilities that are using various storage techniques. Geologic carbon sequestration (GCS) is one such storage technique where CO2 is injected into a deep geological subsurface formation. The injected CO2 is permanently stored in the formation due to structural, residual, solubility, and mineral trapping phenomena. Among different trapping mechanisms, solubility trapping plays a significant role in the safe operation of GCS. In this work, the study is conducted to elucidate the influence of top surface caprock morphology on the solubility trapping mechanism. The simulation results show that the naturally available heterogeneous formations with anticline and without anticline structure influence the solubility fingering phenomena and solubility entrapment percentage over a geological time scale. The lateral migration and sweeping efficiency results of both the synthetic domains for the injected CO2 have shown the importance of caprock morphology on solubility trapping and selection of injection rate. Quantification of solubility trapping in two morphological structures revealed that the synthetic domain without anticline morphology had shown higher solubility trapping. In the future, the simulation data using Artificial Neural Networks can be applied to predict the structural and solubility trapping of geological formations. This analysis further helps incorporating the interaction of CO2 with porous media leading to a mineral trapping mechanism.


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## Body

## 1. Introduction

Carbon capture, utilization, and sequestration (CCUS) technology is an emerging field to mitigate the CO2 emissions into the earth’s atmosphere. Precombustion, oxy-fuel combustion, postcombustion, and chemical loop combustion are four widely used carbon capture technologies [1, 2]. Post capture, in carbon utilization technologies, CO2 is chemically transformed into other value-added products, mostly fuels like hydrogen, methanol, and synthetic natural gas [2, 3]. However, the carbon utilization technologies are in an emerging stage that needs new novel catalyst developments and scale-up procedures to meet the current emission rate. Alternatively, in carbon sequestration technology, CO2 can be stored in deep sea beds and geological formations and used in Enhanced-Oil-Recovery (EOR), methane recovery from coal seams, etc. [2]. Among carbon sequestration technologies, the geologic CO2 sequestration (GCS) is the most viable option to permanently dispose CO2 in deep geological formations [4, 5]. Upon implementation of carbon capture and sequestration (CCS) technology, it can effectively decrease the social cost of carbon value. Despite having the potential to be a mainstream technology for reducing CO2 emissions, the CCS also has barriers and hurdles in implementation in most countries. The transportation and setup cost of the injection grid is financially expensive [6]. During postinjection period, a dedicated monitoring and disaster unit has to be established to monitor the migration and control the leakage of CO2 from the subsurface [6]. The acceptance rate from the public communities for the technology is slim because of the unawareness and low confidence in the technology [6, 7].The in situ thermodynamic conditions of geological formations, such as temperatures greater than 31.1°C and pressures greater than 7.39 MPa, must keep the injected CO2 in the supercritical state [8, 9]. Such supercritical conditions preferably exist in the geological subsurface where CO2 is highly dense and occupies less volume than the gaseous state. When CO2 is injected below caprock, it moves upwards in the subsurface and is obstructed at the caprock stratum [10]. The CO2 that spreads along the caprock and becomes immobile under the caprock is classified as structural trapping. After the injection, the CO2 trapped in porous structures leaves residuals during its movement. This part of injected CO2 co-exists with water, classified as the residual trapping mechanism [11–13]. During upward migration of injected CO2 from the injection point, some quantity of CO2 will get trapped in the migration pathway due to the higher entry capillary pressure of the pore. The high entry capillary pressure will act as the barrier to injected CO2. This trapped CO2 can be classified as local capillary trapping [14–16]. The CO2 trapped in the migration pathway and under caprock will dissolve in water to form weak carbonic acids. This phenomenon is classified as solubility trapping [17]. The dissolved CO2 chemically interacts with minerals present in the formation layer and undergoes mineral reactions to form secondary carbonate minerals. This geochemical transformation of CO2 is called mineral trapping [18, 19]. Among all the trapping mechanisms, solubility trapping plays a significant intermediate role in permanently disposing CO2 over geological time. Therefore, this study focuses on how the heterogeneity of the geological domain will determine the fate of CO2 in the form of solubility trapping efficiency [18, 20].In the geologic CO2 sequestration process, the solubility trapping mechanism is critical to the safe eradication of injected CO2. Figure 1 represents CO2 migration phenomena leading to solubility trapping in geological formations with and without anticline dome (see Figures 1(a) and 1(b)). During injection, CO2 forms a stable plume due to injection pressure and moves upward to spread laterally under impermeable caprock. A thin interface layer starts forming slowly between this CO2 plume and reservoir water due to the dissolution of CO2 into the water. Once this interface layer becomes thick enough, the fluid channelling takes place. These channelling effects generally form due to the density differences between CO2 dissolved water and reservoir water, which ultimately leads to the diffusive convection in the pore space of the domain [20, 21]. Furthermore, this leads to the generation of a geological anastomosing pattern called the solubility fingering phenomenon. In this process, the dissolved CO2 fluid moves downwards due to gravitational forces acting on the higher density fluid, resulting in CO2 plume contact with freshwater, ultimately resulting in more dissolution of CO2 in the subsurface domain. This convective movement continues to enhance solubility trapping of the formation domain. The dissolved CO2 easily interacts with the surrounding rock (CO2-water-rock interactions) formation, triggering geochemical reactions resulting in CO2 trapping in the subsurface through a mineral trapping mechanism. In mineral trapping, the formation rock interacts with neighbouring CO2 and reservoir water and undergoes various geochemical reactions [20, 21]. The percentage of solubility trapping influences the efficiency of the mineral trapping, which decides the fate of carbon sequestration technology. In this way, solubility trapping phenomena play a significant role in the enhancement of CO2 geological storage.Figure 1
Schematic diagram explaining and illustrating the significance and influence of geological features like anticline dome on sweeping efficiency and solubility fingering phenomena during geologic CO2 sequestration.A review on geological CO2 sequestration by Kumar et al. [22] highlighted the existing gaps in the present research regarding trapping mechanisms and site characterization. Over the past decade, the research on structural trapping has mainly focused on elucidating storage capacity and integrity [22–24]. In residual trapping research, studies on pore size, heterogeneity, injection strategies, and resident brine density have been conducted predominantly to analyze and increase the residual trapping efficiency [16, 22, 25]. In recent times, research on solubility trapping has been carried out to study the influences of parameters like brine salinity, pH, microbial activity, and reservoir conditions on the solubility trapping efficiency. Abba et al. [26] conducted experiments on the solubility trapping mechanism to examine its influences on the salinity in the gas reservoir. In the gas reservoir, even at higher salinity of 10% weight percentage of NaCl, the trapped efficiency of solubility trapping was observed 63% [26]. In Kumar et al.’s [27] simulation analysis carried out in carbonate formation, an increase in salinity has no impact on the pH variation and has a meagre influence on mineral trapping [27]. In a study conducted by Zhao et al. [28], the microbial-mediated process improved solubility trapping. The author observed that the CO2 dissolution and solubility trapping increased by increasing the microbe activity [28]. In Shen et al.’s [29] simulation analysis, the microbial activity has shown positive results. During the injection period, the microbes promote mineral dissolution, and during the postinjection period, it favours mineral precipitation, which has increased overall trapping efficiency [29].During the CO2 injection and migration period, various geological and sequestration parameters influence the efficiency of trapping mechanisms. Major parameters are petrophysical heterogeneity, well injection configuration, wettability, salinity, top subsurface perturbation, etc. In the research conducted by Al-Khdheeawi et al. [30–33], the influence of wettability was studied in the heterogeneous (variation in petrophysical properties) domain. This numerical study observed that in the strongly CO2 wet domain, the vertical migration of injected CO2 was rapid compared to the strongly water wet. But, the lateral spreading was lower in the strongly CO2 wet compared to the strongly water wet. Due to this, the residual CO2 entrapment was lower; and the solubility trapping and free mobile CO2 quantity were higher in the strong CO2 wetted domain than in all other considered domains. The author recommends that the strongly water wet domain is preferable for implementing geological CO2 sequestration (GCS) because a more significant time is consumed by CO2 plume to reach the caprock in a strongly water wet domain that can increase overall trapping efficiency [30–33].In the naturally available subsurface reservoir, the wettability can vary from strongly water wet to strongly CO2 wet within the domain space. But the magnitude of these influences might be unpredictable because wettability mostly depends on the rock surface chemistry, connate reservoir water composition, and reservoir temperature [30–34]. Wettability, influences of microbial, salinity, pore network analysis, and other mesoscopic analysis, is very computationally intense [21]; therefore, these analyses were excluded in the current study. Al-Khdheeawi et al. [35–37] have also conducted simulation analysis on the injection well configuration analysis [35] and salinity [36, 37]. It is observed that during horizontal well injection, the lateral spreading of the CO2 leads to an increase in the contact area between injected CO2–reservoir water. Due to this reason, the residual and solubility entrapment in the domain was increased [35]. It was also determined that the salinity of reservoir water influences the mobility and vertical migration distances of the CO2 plume. It is observed that lower salinity is desirable for geological CO2 sequestration [36, 37].In Khudaida et al. [38], the numerical simulation was conducted to study the influence of heterogeneity on the CO2 geological sequestration. A significant share of the injected CO2 is registered under solubility trapping in the homogenous domain. The CO2 plume flow is fluent in spreading laterally, increasing the contact area with reservoir water, further increasing the solubility trapping. In contrast to the homogenous domain, in the heterogeneous domain, the residual trapping percentage increases due to the restriction on the flow of CO2 plume in the migration pathway [38]. Lee et al.’s [39] research described the influence of anticline structure on the selection of injection rate for the CO2 sequestration. With a higher injection rate, the CO2 plume is directed towards the anticline structure; during this process, some CO2 gets immobilized in the migration pathway towards the anticline at a lower injection rate [12]. The flow dynamics of CO2 plume in the migration pathway and contact area of CO2 plume with water are highly dependent on the domain heterogeneity, which further influences the residual and solubility trapping percentage [39]. A similar conclusion was made by Raza et al. [40], where the aquifer heterogeneity directs the selection of injection rate [40]. The degree of suitable heterogeneity for implementing safe CO2 sequestration was studied with the help of the petroleum Lorenz coefficient in Rasheed et al. [41].The previous study on the influences of geological folds has shown their impacts on the primary trapping mechanisms and sweeping efficiency of CO2 plume for different ranges of perturbed subsurface morphology [42]. The existence of geological structures like anticline and syncline can certainly control the CO2 migration, lateral spreading, and safe storage of CO2 in the domain [12]. Figure 1 gives a glimpse and schematic explanation of the simulation analysis carried out in the current research study. In this study, the influence on the CO2 sweeping efficiency and lateral migration by the presence of geological features like anticline dome is analyzed. The impacts on lateral migration and sweeping efficiency directly influence the solubility trapping; it was clearly illustrated and explained in Sec. 4 and in Figures 1(a) and 1(b). As explained earlier, once the injected CO2 plume reaches the caprock, it will start to migrate in the lateral direction. During lateral migration, the CO2 plume might get trapped in any geological features like anticline and stagnate under it, as illustrated in Figure 1(a). In the absence of geological features, a significant quantity of CO2 plume might migrate in the lateral direction and increase sweeping efficiency. A considerable amount of CO2 might move away from the observable or monitoring region at a higher injection rate, as illustrated in Figure 1(b), while in lateral spreading, the movement of the CO2 plume will get reduced, and the interaction between water and CO2 will lead to solubility fingering. The solubility fingering phenomena give glimpses of solubility trapping and vertical separating of CO2. Studying the occurrences of solubility fingering for different caprock domains, mainly under the presence of geological features, and its influences on the solubility trapping is one of the key aspects of novelty for the current research study. The illustration of CO2 plume migration for two caprock morphologies with their respective influences on solubility trapping analysis is the crucial outcome of the research. This study also presented the significance of selecting an injection point near the high elevation region like the anticline dome. However, as the geology of porous media is neglected, i.e., no dissolved CO2 and mineral interactions, this work is limited to structural and solubility trapping mechanisms. The geological faults, folds, and subsurface structures can influence the CO2 migration and CCS integrity. The presence of faults in the domain might lead to CO2 leakage and be prone to disrupt the structural integrity of the subsurface domain [43–45]. The research has to be carried out on the geological structures with faults, and different folds, which are still nascent with regard to primary (structural and residual) and secondary (solubility) trapping mechanisms. Therefore, this study is also limited to establishing the fundamental transport mechanism during CO2 sequestration, which is useful for establishing the mineral interactions and ANN studies on physical trapping phenomena.In this study, the CO2 migration, lateral spreading, and solubility trapping for both synthetic domains (without and with anticline dome) are analyzed by observing the CO2 mole fraction, total CO2 aqueous presence, and pH distribution in the domain. Additionally, average reservoir pressure and the average temperature are also analyzed to study the impacts of CO2 injection in the domain over a geological time scale. The heterogeneity term is used to describe the irregularities in petrophysical properties and the subsurface geological structure forming on caprock morphology, such as anticline and syncline formations.In Sec.2 of this research article, the methodology used in the simulation analysis is explained. Then, the modelling of synthetic subsurface domains with and without anticline domain is illustrated, and other simulation setups are described in Sec. 3. Sec. 4 illustrates and explains the parametric simulation outcomes focusing mainly on caprock morphology. Finally, in Sec.5, summary of the conclusions is presented based on the current research study.


## 2. Mathematical Modelling

Multiphase flow and reactive transport modelling (RTM) is used to perform this numerical analysis. RTM has the ability to predict the spatial and temporal evolutions of geochemical species during CO2 geological sequestration [46]. The RTM code utilizes the multiphase, multicomponent mass, momentum, and energy balance equations which are incorporated with geochemistry to understand the interaction between the CO2 plume and water [47, 48].


### 2.1. Multiphase Flow Equations

Geological sequestration of CO2 occurs in a subsurface porous structure that involves several processes, including flow and transport of CO2. In this section, multiphase flow equations are explained. And it is assumed that the immiscible displacements of CO2 and water are occurring in a complex porous geological formation. Each phase can involve more than one chemical species and can be considered a mass transfer occurring between phases to accommodate the dissolution of CO2 in water [48, 49]. The general mass and energy conservation equations governing the multiphase flow are illustrated in Table 1 Eq. (1)–(3). The subscript l, g denotes phases in the conservation equations, where g is for gas and l is for liquid. The first term in the equation affiliates to an accumulation in the control volume V, and the second term affiliates to the net flux into the control volume. The third term refers to the source/sink term (Qw, Qc, and Qe) [47, 48].Table 1
Multiphase flow and reactive transport model for CO2 geological sequestration.
Multiphase flow and reactive transport modelling equationsMultiphase flow equationsWater phase, mass balance equation∂/∂tϕSlρlXwl+SgρgXwg+∇⋅qlρlXwl+qgρgXwg−ϕSlDlρl∇Xwl+SgDgρg∇Xwg=QwEq. (1)Darcy velocity of the water phaseql=−kkrl/μl∇pl−ρlgzEq. (1a)ScCO2 phase, mass balance equation∂∂tϕSlρlXcl+SgρgXcg+∇⋅qlρlXcl+qgρgXcg−ϕSlDlρl∇Xcl+SgDgρg∇Xcg=QcEq. (2)Darcy velocity of gas phaseqg=−kkrg/μg∇pg−ρggzEq. (2a)Energy balances equation∂/∂tϕSlρlUl+SgρgUg+1−ϕρrCrT+∇⋅qlρlHl+qgρgHg−κ∇T=QeEq. (3)Reactive transport equationsMulticomponent reactive transport equation∂/∂tϕ∑lslΨjl+∇.∑αΩjl=−∑mvjmImwhere −∑mvjmIm is the rate of reaction equation and j refers to the primary speciesEq. (4)Total concentrationΨjl=Cjl+∑ivjiCilEq. (5)Total fluxΩjl=−τϕslDl∇+kkl/μl∇Wlηl−ρlgzΨjlEq. (6)Axillary equationsSaturation relation for all phases for a singular component∑Sα=1Eq. (7)Brooks–Corey-Mualem relationship between relative permeability and effective saturationkr,l=Se,ln1+n2n3kr,g=1−Se,ln11−Sln2n3Eq. (8)Brooks-Corey relationship between the effective saturation and capillary pressureSe,gPc/Pe−nb.,ifPc>Pe1,ifPc≤PeEq. (9)Capillary pressurePc=ρl−ρggh=∆ρghEq. (10)Trapping estimationStructurally trapped CO2structural−trapping=∑n=1nf∅Vsρco2×minSco2,Srco2Eq. (11)Residually trapped CO2Residual−trapping=∑n=1nf∅Vrρco2×minSco2,Srco2Eq. (12)From Table1 Eqs. (1)-(3), the term Ø represents the porosity of the domain, ql and qg stand for Darcy velocity of phase l and g, and Slorg stands for phase saturation in a domain. Dlorg represents phase diffusivity coefficient, H represents the enthalpy, U represents the internal energy, and ρr represents the rock density.


### 2.2. Reactive Transport Modelling

The multicomponent reactive transport equation [46] is illustrated in Table 1 Eq. (4). The total concentration of the components is calculated with the equation mentioned in Table 1 Eq. (5). The subscript α represents the phase l or g. The total flux is calculated with the equation mentioned in Table 1 Eq. (6). The Darcy velocity is already substituted in the total flux equation. The term k stands for saturated permeability of the porous media, krα is the relative permeability of phase α,μα is the viscosity of phase, α,Pα is the pressure of phase, α, g is the acceleration due to gravity, and z is the vertical coordinate, η represents the molar density, Wα represents the formula weight [47, 48]. The reactive transport modelling technique is used to perform the numerical analysis; it can predict the geochemical reactions in both spatial and temporal directions along with the fluid flow [46]. The reactive transport code utilizes the multiphase, multicomponent mass, and energy balance equations incorporated with reaction chemistry to understand the interaction between the CO2 plume and nearby reservoir water [47, 48].


### 2.3. Brooks–Corey Relation

In Table1, Eq. (7) illustrates the saturation relation for all phases. The Brooks–Corey relation is used to relate the capillary pressure Pc to effective invading fluid saturation Se,α. In this current simulation study, CO2 is the invading fluid in the reservoir. The Brooks–Corey relation is illustrated in Table 1 Eq. (9). The term Pe in the Brooks–Corey relationship represents the entry pressure; Pc denotes the capillary pressure. The formulation of reservoir capillary pressure is illustrated in Table 1 Eq. (10). The terms ρl and ρg represented densities of water and injected CO2; Se,g is the effective CO2 saturation. The term nb is the parameter related to the pore-size distribution, its value is considered 2.5, and its range is between 0.2 and 5 [49]. Brooks–Corey-Mualem model gives the relationship equation between relative permeability and effective saturation (illustrated in Table 1 Eq. (8)). The terms n1, n2, and n3 in the Brooks–Corey-Mualem equation are constants. The value of n1 is 1, n2 is 1+1/nb, and n3 is 2, which are obtained by the experimental fitting. The term Se,l is effective water saturation. The effective saturation fluid should be considered normal saturation of fluid in this simulation analysis because it is considered that there are no presences of isolation pore space [49]. The fluid movement is primarily defined by the action of buoyancy and capillary forces, which will govern the movement of injected CO2 in the geological structure domain [49].


## 2.1. Multiphase Flow Equations

Geological sequestration of CO2 occurs in a subsurface porous structure that involves several processes, including flow and transport of CO2. In this section, multiphase flow equations are explained. And it is assumed that the immiscible displacements of CO2 and water are occurring in a complex porous geological formation. Each phase can involve more than one chemical species and can be considered a mass transfer occurring between phases to accommodate the dissolution of CO2 in water [48, 49]. The general mass and energy conservation equations governing the multiphase flow are illustrated in Table 1 Eq. (1)–(3). The subscript l, g denotes phases in the conservation equations, where g is for gas and l is for liquid. The first term in the equation affiliates to an accumulation in the control volume V, and the second term affiliates to the net flux into the control volume. The third term refers to the source/sink term (Qw, Qc, and Qe) [47, 48].Table 1
Multiphase flow and reactive transport model for CO2 geological sequestration.
Multiphase flow and reactive transport modelling equationsMultiphase flow equationsWater phase, mass balance equation∂/∂tϕSlρlXwl+SgρgXwg+∇⋅qlρlXwl+qgρgXwg−ϕSlDlρl∇Xwl+SgDgρg∇Xwg=QwEq. (1)Darcy velocity of the water phaseql=−kkrl/μl∇pl−ρlgzEq. (1a)ScCO2 phase, mass balance equation∂∂tϕSlρlXcl+SgρgXcg+∇⋅qlρlXcl+qgρgXcg−ϕSlDlρl∇Xcl+SgDgρg∇Xcg=QcEq. (2)Darcy velocity of gas phaseqg=−kkrg/μg∇pg−ρggzEq. (2a)Energy balances equation∂/∂tϕSlρlUl+SgρgUg+1−ϕρrCrT+∇⋅qlρlHl+qgρgHg−κ∇T=QeEq. (3)Reactive transport equationsMulticomponent reactive transport equation∂/∂tϕ∑lslΨjl+∇.∑αΩjl=−∑mvjmImwhere −∑mvjmIm is the rate of reaction equation and j refers to the primary speciesEq. (4)Total concentrationΨjl=Cjl+∑ivjiCilEq. (5)Total fluxΩjl=−τϕslDl∇+kkl/μl∇Wlηl−ρlgzΨjlEq. (6)Axillary equationsSaturation relation for all phases for a singular component∑Sα=1Eq. (7)Brooks–Corey-Mualem relationship between relative permeability and effective saturationkr,l=Se,ln1+n2n3kr,g=1−Se,ln11−Sln2n3Eq. (8)Brooks-Corey relationship between the effective saturation and capillary pressureSe,gPc/Pe−nb.,ifPc>Pe1,ifPc≤PeEq. (9)Capillary pressurePc=ρl−ρggh=∆ρghEq. (10)Trapping estimationStructurally trapped CO2structural−trapping=∑n=1nf∅Vsρco2×minSco2,Srco2Eq. (11)Residually trapped CO2Residual−trapping=∑n=1nf∅Vrρco2×minSco2,Srco2Eq. (12)From Table1 Eqs. (1)-(3), the term Ø represents the porosity of the domain, ql and qg stand for Darcy velocity of phase l and g, and Slorg stands for phase saturation in a domain. Dlorg represents phase diffusivity coefficient, H represents the enthalpy, U represents the internal energy, and ρr represents the rock density.


## 2.2. Reactive Transport Modelling

The multicomponent reactive transport equation [46] is illustrated in Table 1 Eq. (4). The total concentration of the components is calculated with the equation mentioned in Table 1 Eq. (5). The subscript α represents the phase l or g. The total flux is calculated with the equation mentioned in Table 1 Eq. (6). The Darcy velocity is already substituted in the total flux equation. The term k stands for saturated permeability of the porous media, krα is the relative permeability of phase α,μα is the viscosity of phase, α,Pα is the pressure of phase, α, g is the acceleration due to gravity, and z is the vertical coordinate, η represents the molar density, Wα represents the formula weight [47, 48]. The reactive transport modelling technique is used to perform the numerical analysis; it can predict the geochemical reactions in both spatial and temporal directions along with the fluid flow [46]. The reactive transport code utilizes the multiphase, multicomponent mass, and energy balance equations incorporated with reaction chemistry to understand the interaction between the CO2 plume and nearby reservoir water [47, 48].


## 2.3. Brooks–Corey Relation

In Table1, Eq. (7) illustrates the saturation relation for all phases. The Brooks–Corey relation is used to relate the capillary pressure Pc to effective invading fluid saturation Se,α. In this current simulation study, CO2 is the invading fluid in the reservoir. The Brooks–Corey relation is illustrated in Table 1 Eq. (9). The term Pe in the Brooks–Corey relationship represents the entry pressure; Pc denotes the capillary pressure. The formulation of reservoir capillary pressure is illustrated in Table 1 Eq. (10). The terms ρl and ρg represented densities of water and injected CO2; Se,g is the effective CO2 saturation. The term nb is the parameter related to the pore-size distribution, its value is considered 2.5, and its range is between 0.2 and 5 [49]. Brooks–Corey-Mualem model gives the relationship equation between relative permeability and effective saturation (illustrated in Table 1 Eq. (8)). The terms n1, n2, and n3 in the Brooks–Corey-Mualem equation are constants. The value of n1 is 1, n2 is 1+1/nb, and n3 is 2, which are obtained by the experimental fitting. The term Se,l is effective water saturation. The effective saturation fluid should be considered normal saturation of fluid in this simulation analysis because it is considered that there are no presences of isolation pore space [49]. The fluid movement is primarily defined by the action of buoyancy and capillary forces, which will govern the movement of injected CO2 in the geological structure domain [49].


## 3. Simulation Setup

### 3.1. Synthetic Domain

Two geological domains are modelled to conduct the numerical analysis to elucidate the influence of caprock morphology on the solubility trapping mechanism. A MATLAB software’s default membrane function and trigonometric function are used to model the synthetic domains. By combining the membrane and trigonometric functions, auxiliary equations are developed. Utilizing themeshgrid MATLAB function, two-dimensional grid coordinates are developed with two vector variables. These vectors are further substituted in the auxiliary equations to form top surface layers for two models. The membrane function is used to model the geological anticline structure. And the trigonometric function is used to model the perturbation and irregularity, which will demonstrate as geological ridges. After creating two-dimensional top surface layers, the grid cells are assigned in the third direction to construct three-dimensional grid structures. The membrane function is suppressed for the second synthetic domain to model the domain without anticline structure. Figure 2 illustrates the modelled three-dimensional domains and petrophysical properties distributions considered for the simulations. The physical dimensions of the synthetic domains are about 10 km ×10 km ×0.15 km, and it is discretized into 50 × 50 ×10 grid cells (25,000 grid cells). For the petrophysical properties distribution, the porosity ranges from 20 to 40%, and the value for permeability varies from 10 to 1500 mD [50, 51]. The distribution of porosity and permeability for both synthetic domains is illustrated in Figure 2 [49]. The two synthetic geological domains considered in this simulation analysis have one disguised feature: one domain contains a caprock anticline structure, and another does not include any structure. These synthetic domains contain the same number of perturbations and similar petrophysical property distribution of porosity and permeability. This analysis will be helpful in forecasting injected CO2 storage and entrapment potential of the domains through structural and solubility trapping. The injection point coordinate considered in these simulations is (4000, 4000, 950), which is also illustrated in dark red colour with the alphabet word I in Figure 2.Figure 2
Illustration of a schematic diagram of the three-dimensional grid structure of both the domains and petrophysical properties distribution.


### 3.2. Reactive Transport Mechanism

The multiphase flow forms a liquid-gas interface where ScCO2 is in contact with water. Due to the chemical potential gradient of CO2, to maintain local thermodynamic equilibrium at the interface, CO2 will solubilize in water to form CO2(aq). Aqueous CO2 interactions with H+ and OH- ions lead to a series of equilibrium reactions, as listed in Table 2 [20, 52–54]. In the current numerical study, only the solubility reactions are considered to estimate the potential of solubility trapping alone. The initial concentration of CO2 and H2O for the whole domain before starting the injection of the ScCO2 is 4.6 ×10-12 M and 55.508 M, respectively. In addition, the initial pH of the entire domain is maintained at 5.6.Table 2
Solubility trapping reactions with respective Log(K) values at standard temperature (25°C).
ReactionsLog(K) (at standard temperature)CO2aq↔CO2g1.4689H2O↔H++OH−-13.9951CO2g+H2O↔H++HCO3−-7.8136H++HCO3−↔H2CO36.3447CO32−+H+↔HCO3−10.3288CO32−+2H+↔CO2aq+H2O16.6735The injection of CO2 at point I is facilitated in Eq. (2) with the source term Qc. During injection and postinjection, solution of multiphase flow and energy balance Eqs. (1)-(3) gives the phase distributions of water and CO2. Darcy’s velocities of individual phases are given by Eqs. (1a) and (2a). Eqs. (7) to (10) give the axillary/closure equations, which include Brooks–Corey’s relationships between saturation, capillary pressures, and relative permeability. The local equilibrium between ScCO2-water interfaces gives aqueous CO2 by Henry’s relations. The fate of CO2 and H+ in the water phase due to convection and diffusion, i.e., the total concentration of CO2(ΨCO2l) and H+(ΨH+l), is solved using reactive transport model Eq. (4).


### 3.3. Estimation of Structural Residual and Solubility Trapping Percentage

The structural and residual trapping is estimated based on the cells’ porosity, pore volume, and CO2 saturation. The structural and residual trapping is calculated using the equation illustrated in Table 1 Eq. (11)-(12). The movable plume is the remaining quantity of CO2 after the structural and residual trapping. The term nf in Table 1 Eq. (11)-(12) is the total number of cells in the grid structure. The Ø term represents porosity. Vsand Vr are the cell volumes of structural traps and residual traps, respectively. The structural traps are identified by analyzing the top surface. The top surface is modelled by using the meshgrid. Then, the MATLAB Gaussian noise function is used to integrate the perturbation into the mesh surface. Now the numerical distance differences between each cell of the mesh surface are identified. The structural traps are then identified, and the consecutive cells are saved under structural trapping cells and analyzed during simulations. The remaining cells other than the structural trapping cells of a domain are the active cells for residual trapping calculation. Only the immobile CO2 saturation cells are considered for the entrapment calculation. The remaining cell saturations are considered for the movable-plume calculations. The SCO2 and SrCO2 are the saturation of CO2 and residual CO2 saturation. The CO2 entrapment percentage of solubility is analyzed by observing the CO2 present in the aqueous and gaseous forms in the geological simulation domain.This study used a massively parallel reactive transport code PFLOTRAN for this simulation analysis. The detailed mathematical implementation of PFLOTRAN is discussed in Mills et al. [48]. The parallelization is achieved through domain decomposition using the PETSc (Portable Extensible Toolkit for Scientific Computation) libraries. PETSc is a data structure and routine suit for the scalable solution of scientific applications [55]. The Newton–Krylov iterative solver is used in this simulation analysis. The PFLOTRAN has the ability to solve coupled thermal-hydrologic-chemical three-dimension problems in variably saturated, nonisothermal porous media. [55].


## 3.1. Synthetic Domain

Two geological domains are modelled to conduct the numerical analysis to elucidate the influence of caprock morphology on the solubility trapping mechanism. A MATLAB software’s default membrane function and trigonometric function are used to model the synthetic domains. By combining the membrane and trigonometric functions, auxiliary equations are developed. Utilizing themeshgrid MATLAB function, two-dimensional grid coordinates are developed with two vector variables. These vectors are further substituted in the auxiliary equations to form top surface layers for two models. The membrane function is used to model the geological anticline structure. And the trigonometric function is used to model the perturbation and irregularity, which will demonstrate as geological ridges. After creating two-dimensional top surface layers, the grid cells are assigned in the third direction to construct three-dimensional grid structures. The membrane function is suppressed for the second synthetic domain to model the domain without anticline structure. Figure 2 illustrates the modelled three-dimensional domains and petrophysical properties distributions considered for the simulations. The physical dimensions of the synthetic domains are about 10 km ×10 km ×0.15 km, and it is discretized into 50 × 50 ×10 grid cells (25,000 grid cells). For the petrophysical properties distribution, the porosity ranges from 20 to 40%, and the value for permeability varies from 10 to 1500 mD [50, 51]. The distribution of porosity and permeability for both synthetic domains is illustrated in Figure 2 [49]. The two synthetic geological domains considered in this simulation analysis have one disguised feature: one domain contains a caprock anticline structure, and another does not include any structure. These synthetic domains contain the same number of perturbations and similar petrophysical property distribution of porosity and permeability. This analysis will be helpful in forecasting injected CO2 storage and entrapment potential of the domains through structural and solubility trapping. The injection point coordinate considered in these simulations is (4000, 4000, 950), which is also illustrated in dark red colour with the alphabet word I in Figure 2.Figure 2
Illustration of a schematic diagram of the three-dimensional grid structure of both the domains and petrophysical properties distribution.


## 3.2. Reactive Transport Mechanism

The multiphase flow forms a liquid-gas interface where ScCO2 is in contact with water. Due to the chemical potential gradient of CO2, to maintain local thermodynamic equilibrium at the interface, CO2 will solubilize in water to form CO2(aq). Aqueous CO2 interactions with H+ and OH- ions lead to a series of equilibrium reactions, as listed in Table 2 [20, 52–54]. In the current numerical study, only the solubility reactions are considered to estimate the potential of solubility trapping alone. The initial concentration of CO2 and H2O for the whole domain before starting the injection of the ScCO2 is 4.6 ×10-12 M and 55.508 M, respectively. In addition, the initial pH of the entire domain is maintained at 5.6.Table 2
Solubility trapping reactions with respective Log(K) values at standard temperature (25°C).
ReactionsLog(K) (at standard temperature)CO2aq↔CO2g1.4689H2O↔H++OH−-13.9951CO2g+H2O↔H++HCO3−-7.8136H++HCO3−↔H2CO36.3447CO32−+H+↔HCO3−10.3288CO32−+2H+↔CO2aq+H2O16.6735The injection of CO2 at point I is facilitated in Eq. (2) with the source term Qc. During injection and postinjection, solution of multiphase flow and energy balance Eqs. (1)-(3) gives the phase distributions of water and CO2. Darcy’s velocities of individual phases are given by Eqs. (1a) and (2a). Eqs. (7) to (10) give the axillary/closure equations, which include Brooks–Corey’s relationships between saturation, capillary pressures, and relative permeability. The local equilibrium between ScCO2-water interfaces gives aqueous CO2 by Henry’s relations. The fate of CO2 and H+ in the water phase due to convection and diffusion, i.e., the total concentration of CO2(ΨCO2l) and H+(ΨH+l), is solved using reactive transport model Eq. (4).


## 3.3. Estimation of Structural Residual and Solubility Trapping Percentage

The structural and residual trapping is estimated based on the cells’ porosity, pore volume, and CO2 saturation. The structural and residual trapping is calculated using the equation illustrated in Table 1 Eq. (11)-(12). The movable plume is the remaining quantity of CO2 after the structural and residual trapping. The term nf in Table 1 Eq. (11)-(12) is the total number of cells in the grid structure. The Ø term represents porosity. Vsand Vr are the cell volumes of structural traps and residual traps, respectively. The structural traps are identified by analyzing the top surface. The top surface is modelled by using the meshgrid. Then, the MATLAB Gaussian noise function is used to integrate the perturbation into the mesh surface. Now the numerical distance differences between each cell of the mesh surface are identified. The structural traps are then identified, and the consecutive cells are saved under structural trapping cells and analyzed during simulations. The remaining cells other than the structural trapping cells of a domain are the active cells for residual trapping calculation. Only the immobile CO2 saturation cells are considered for the entrapment calculation. The remaining cell saturations are considered for the movable-plume calculations. The SCO2 and SrCO2 are the saturation of CO2 and residual CO2 saturation. The CO2 entrapment percentage of solubility is analyzed by observing the CO2 present in the aqueous and gaseous forms in the geological simulation domain.This study used a massively parallel reactive transport code PFLOTRAN for this simulation analysis. The detailed mathematical implementation of PFLOTRAN is discussed in Mills et al. [48]. The parallelization is achieved through domain decomposition using the PETSc (Portable Extensible Toolkit for Scientific Computation) libraries. PETSc is a data structure and routine suit for the scalable solution of scientific applications [55]. The Newton–Krylov iterative solver is used in this simulation analysis. The PFLOTRAN has the ability to solve coupled thermal-hydrologic-chemical three-dimension problems in variably saturated, nonisothermal porous media. [55].


## 4. Results and Discussion

The CO2 mole fraction and pH variations are two significant factors that enable the visualization of CO2 entrapment in the formation zone. Here, CO2 mole fraction values for the whole domain provided an overall picture of CO2 migration. Simultaneously, the domain’s pH variation helped visualize the solubility fingering phenomena and solubility trapping occurrence within the domain. Additionally, the average reservoir pressure, average reservoir temperature, and CO2 trapped in the different phases have given an adequate understanding on the influence of caprock morphology. This simulation analysis is carried out to analyze and visualize the effects of caprock morphology on the quantity of CO2 that undergoes the solubility trapping mechanism in the domain. The CO2 injection is carried out continuously for the first 30 years at the mass flow rate of 0.315 Mt/year. The density and viscosity of water considered in the simulations are 975.86 kg/m3 and 0.3086 ×10-3 Pa.s, and that of CO2 are 686.54 kg/m3 and 0.0566 ×10-3 Pa.s, respectively [49]. The initial temperature of the reservoir is maintained at 75°C. The reservoir depth starts from 800 m, as illustrated in Figure 2, which indicates that the sequestration of CO2 in the simulation domain is carried out 800 m below the earth’s surface. The synthetic domain considered in this research analysis is a sloping landscape. So, the depth value “h” for each grid cell changes. The initial reservoir pressure in the reservoir is calculated by ρwgh. As the density of water (ρw) considered in the geological domain is constant, the pressure depends only on the depth (h). The initial reservoir pressure varies from 77 to 84.6 bars in the geological domain. The rock formation’s tortuosity values are assumed to be 1, and the rock density is considered 2900 kg/m3 [56]. For the solubility trapping simulation analysis, the initial pH of the domain is maintained at 5.6. The porosity and permeability distribution of the domain is illustrated in Figure 2.


### 4.1. Base Case Scenario

A synthetic anticline domain (Figure2) is considered a base case scenario to understand solubility trapping phenomena. The petrophysical properties, injection rate, and fluid properties are considered as mentioned in Sec. 3 for this simulation analysis. Two sets of simulation analyses were carried out with and without considering the CO2 dissolution. The simulation set without CO2 dissolution mechanism consideration will calculate only structural and residual trapping; this simulation set will be referred to as simulation 1 in subsequent text, whereas in the simulation setup where the dissolution reactions are considered, the solubility trapping is calculated in addition to structural and residual trapping; this will be referred to as simulation 2. These simulations are carried out at the same injection point at the constant injection rate. The CO2 saturation profiles on the top surface of the anticline domain are illustrated in Figure 3(a).Figure 3
(a) Saturation of CO2 in anticline dome representing the migration at discrete times 1, 30, and 3000 years. Simulation 1, structural, and residual trapping only represent ScCO2 migration without CO2 solubility. Simulation 2 for solubility trapping clearly shows lower CO2 saturation describes the injected CO2 in the aqueous phase. The dynamic profile of the amount of CO2 in various forms of trapping mechanisms, (b) during structural and residual trapping (without CO2 dissolution) and (c) solubility trapping (with CO2 dissolution).
(a)(b)(c)In simulation 1, due to the absence of CO2 in the aqueous phase, the injected CO2 percolates and undergoes structural and residual trapping [7]. From Figure 3(a), it is noticed that in simulations 1 and 2, the CO2 plume is migrating towards the top surface of the anticline domain. Once the injected CO2 plume completely reaches the anticline dome, it gets stagnates in the anticline dome. This restricts the CO2 plume from migrating in the lateral direction. This restriction of CO2 plume in the domain will limit the residual trapping. In simulation 1, the saturation of CO2 on the top surface of the domain is more compared to simulation 2. This implies that the CO2 migration in simulation 2 is less because ScCO2 dissolves into the resident reservoir water and undergoes solubility trapping. To understand more on CO2 migration in the formation domain, the mass of CO2 in various forms is quantified in Figures 3(b) and 3(c). For the initial 30 years of injection, 9.7 Mega tonnes of CO2 was injected into the formation. Figure 3(b) illustrates the dynamic variation of the mass of CO2 in the form of structural and residual trapping and free mobile CO2, where the dissolution mechanism is not considered (simulation 1). Figure 3(c) illustrates the efficiency of solubility trapping by quantifying the mass of CO2 in both aqueous and gas phases. In Figure 3(c), CO2 aqueous represents the dissolved mass of CO2 in water, and the CO2 gas represents the free mobile, structural and residual trapped CO2 over a geological time scale. It can be observed that the structural and residual trapping was dominant during the injection period (30 years) (see Figure 3). However, during the migration, the solubility of CO2 in water is prevalent from Figure 3(c). During the postinjection period, the CO2 plume stagnates under the anticline dome, and the constant dissolution of CO2 into resident water will take place. And about 90% of injected CO2 is dissolved in water at 3000 years (see Figure 3(c)).


### 4.2. Solubility Fingering Phenomena

After injecting the ScCO2 into the domain, it will form a CO2 plume, start migrating upwards, and spread laterally under impermeable caprock. After the injection is ceased, the velocity of the CO2 plume will decrease gradually over time, which increases the contact time between the CO2 plume and the connate reservoir water. The obtained results of plume migration in the domain are illustrated in Figure 4. The interface layer will be formed between the CO2 plume and connate reservoir water. At the interface, the CO2 dissolves into connate reservoir water. Molecular diffusion and mass transfer occur from CO2 plume to resident reservoir water. As the CO2 dissolved into the water, it became denser and led to convection mixing in the downward direction [18, 57].Figure 4
Solubility fingering phenomenon during CO2 geological sequestration and their evolution over geological time scale.The fingering phenomenon occurs during the solubility trapping mechanism due to the dissolution-diffusion-convection process. The solubility fingers form in the domain help increase the efficiency of solubility trapping. Due to this fingering phenomenon, more CO2 will come in contact with the fresh formation water. The illustrative results of the fingering phenomenon can be seen in Figure 4. The CO2 concentration is higher near the injection well during the injection period, and the dominance of dissolution is not seen in the domain (see Figure 4 for 30 years). During postinjection, the plume spreading over a geological time scale creates more CO2-water interface to facilitate the CO2 dissolution phenomena. It is observed that the fingering phenomena gradually shift beneath the anticline dome where the maximum amount of CO2 plume has migrated. The number of fingers increases with geological time scale (see Figure 4 for 200 and 3000 years). This phenomenon of solubility trapping effect is evident in Figure 4 for comparison of CO2 saturation in residual trapping-only trapping and residual-and-solubility trapping.The simulation results in Figure5 depict the fate of CO2 at discrete geological times in the form of a CO2 mole fraction across the domain. After reaching the caprock, the plume laterally spreads under the impermeable caprock. During this time, one can notice a constant decrease in the CO2 mole fraction. This can be attributed to residual and solubility trapping, which works in tandem to increase the entrapment of the injected CO2. The plume reaches the caprock within one year, and at the end of the injection period, it slowly starts to migrate towards the anticline dome. It assumed that the upper layer of the domain is impermeable. Therefore, it will restrict the CO2 from passing through it and allow it to migrate towards the anticline. During this migration, due to the absence of injection force and the presence of perturbation on caprock, the momentum of the CO2 plume decreases, which increases the contact time between CO2 and water, which further leads to an increase in the percentage of entrapment in the domain. A steady reduction in CO2 mole fraction and increase in total aqueous phase CO2 quantity after the injection phase suggest that the entrapment of CO2 occurs through the solubility trapping mechanism.Figure 5
Illustration of CO2 mole fraction and pH variation over geological time scale during CO2 geological sequestration.The CO2 mole fraction and pH variation results are presented in Figure 5. Initially, a pH of 5.6 is attributed to the whole domain. As the CO2 moves upwards and percolates through the formation layer, the CO2 starts getting dissolved into connate reservoir water, which further leads to a decrease in pH value in the domain. From the results, it is observed that the large volume of the synthetic domain can be seen to be covered with a low pH. This happens due to lateral spreading and solubility fingering phenomenon of CO2 plume in the domain; the results are illustrated in Figure 5. The pH drops to 3.5, suggesting solubility trapping occurrences with safe entrapment of injected CO2 in the domain. For mineral trapping to occur, certain conditions are required, of which pH is an essential factor. For example, to have a dissolution of silicate minerals, a low pH range is preferred to have a higher concentration of H+ ions on the reactant side. For a precipitation reaction to occur, a slightly higher pH is preferred. In order to have reliable sequestration trapping, it is preferred to have an optimal pH range. The aforementioned pH range of 3.5-5 is considered optimal enough to promote both dissolution reaction and precipitation reaction and thereby enhance the storage of CO2 in the domain [58].


### 4.3. Caprock Structure Influence on Solubility Trapping

In this section, the simulation study is carried out to analyze the influence of caprock structure on CO2 geological sequestration. The first set of simulations is carried on the synthetic domain incorporated with the anticline domain, and it will be referred to as synthetic domain-1 in the subsequent text. In the second set of simulations, a synthetic domain without caprock morphological structure is considered, and it is referred to as synthetic domain-2. Figure 6(a) illustrates the CO2 mole fraction distribution for both synthetic domains. From Figure 6(a), it is observed that by the end of the simulation time, the CO2 mole fraction distribution is lesser in synthetic domain-2 as compared to synthetic domain-1. It may be due to high lateral spreading and displacement efficiency in synthetic domain-2. Due to high lateral spreading, a large quantity of CO2 came in contact with connate water, which triggered a dissolution reaction and further initiated the fingering phenomenon. So, for this reason, the total aqueous phase CO2 quantity observed was higher, and the free mobile CO2 quantity was lower in the synthetic domain-2 compared to synthetic domain-1 (see Figure 7(c)).Figure 6
Influence of caprock morphology on (a) CO2 mole fraction and (b) pH variation over a geological time scale.
(a)(b)Figure 7
Influence of caprock morphology on (a) average reservoir pressure, (b) average reservoir temperature, and (c) aqueous and gaseous phase CO2 quantity variation over geological time scale.
(a)(b)(c)Figures6(a) and 6(b) give an illustrative explanation about the higher solubility of injected CO2 in synthetic domain-2 compared to synthetic domain-1. In the pH variation simulation results, see Figure 6(b); it is observed that a large volume of the domain in synthetic domain-2 is covered with low pH compared to synthetic domain-1. The volume covered and displacement efficiency of injected CO2 plume is less in synthetic domain-1 than in synthetic domain-2. It is due to the migration pathway of CO2 plume is congested to narrow pathway towards anticline centre. In synthetic domain-2, due to the absence of an anticline dome, the injected CO2 plume leads to more spreading in the lateral direction, which leads to higher CO2 dissolution. Furthermore, it contributes to the fingering phenomenon, which increases the dissolution in the depth axis and increases the vertical spreading. In this way, the pH in the domain changes over geological time. The low pH region created during the solubility trapping phase might trigger a mineral reaction for the mineral trapping mechanism as the domain’s pH range is within the acceptable limits [59].The average reservoir pressure and temperature results of synthetic domain-2 are in the commendable range (see Figures7(a) and 7(b)). As predicted, in Figure 7(a), the pressure in synthetic domain-1, i.e., with anticline structure, is high at the end of the simulation time compared to synthetic domain-2, i.e., without anticline structure. Due to the narrow pathway and stagnated CO2 in the dome centre, it will uphold the normal reservoir pressure in synthetic domain-1. It is observed that the average reservoir temperature has not shown any significant variations during simulations. Its effects were recorded over the geological time scale were nominal (see Figure 7(b)). From solubility trapping, as depicted in Figure 7(c), it is observed that the mass of CO2 dissolved in water at any time is higher in synthetic domain-2 compared to synthetic domain-1. As mentioned earlier, high lateral spreading in the synthetic domain-2 leads to more entrapment in the migration pathway. In synthetic domain-1, due to the presence of an anticline structure, the lateral spreading of the CO2 plume was restricted and remained low, which ultimately reduced the residual and solubility entrapment. Overall, the free mobile CO2 quantity is low in synthetic domain-2 compared to synthetic domain-1; from Figure 7(c), it is evident that at 3000 years, most of the injected CO2 was dissolved in the water phase.In comparison, 99% of the injected mass is dissolved without anticline structure, whereas it is 90% in the anticline structure case. But at a higher injection rate, synthetic domain-2 has shown a large quantity of CO2 migrating out of the observable domain. In certain situations, the injected CO2 must be confined within the limits of the geological domain by which CO2 can be restricted from exploring the geological cracks and fault structures, which might further lead to leakage [45]. In such a scenario, the presence of geological structures like anticline dome in synthetic domain-1 is a viable option. As illustrated in synthetic domain-1 results, see Figure 6, the anticline dome restricts the CO2 within the observable domain limits.The low availability of storage volume and low injection rate can increase the risk factor and financial aspects of the CCS operation in synthetic domain-2. The synthetic domain-1 can be cost-effective (see Figures6(a) and 6(b)); it can be observed that injected CO2 is migrating under a small volume of anticline dome, which will reduce the monitoring cost as it will require to screen a small area. But if the anticline dome contains faults, it can create severe problems for the safe operations of CCS.


## 4.1. Base Case Scenario

A synthetic anticline domain (Figure2) is considered a base case scenario to understand solubility trapping phenomena. The petrophysical properties, injection rate, and fluid properties are considered as mentioned in Sec. 3 for this simulation analysis. Two sets of simulation analyses were carried out with and without considering the CO2 dissolution. The simulation set without CO2 dissolution mechanism consideration will calculate only structural and residual trapping; this simulation set will be referred to as simulation 1 in subsequent text, whereas in the simulation setup where the dissolution reactions are considered, the solubility trapping is calculated in addition to structural and residual trapping; this will be referred to as simulation 2. These simulations are carried out at the same injection point at the constant injection rate. The CO2 saturation profiles on the top surface of the anticline domain are illustrated in Figure 3(a).Figure 3
(a) Saturation of CO2 in anticline dome representing the migration at discrete times 1, 30, and 3000 years. Simulation 1, structural, and residual trapping only represent ScCO2 migration without CO2 solubility. Simulation 2 for solubility trapping clearly shows lower CO2 saturation describes the injected CO2 in the aqueous phase. The dynamic profile of the amount of CO2 in various forms of trapping mechanisms, (b) during structural and residual trapping (without CO2 dissolution) and (c) solubility trapping (with CO2 dissolution).
(a)(b)(c)In simulation 1, due to the absence of CO2 in the aqueous phase, the injected CO2 percolates and undergoes structural and residual trapping [7]. From Figure 3(a), it is noticed that in simulations 1 and 2, the CO2 plume is migrating towards the top surface of the anticline domain. Once the injected CO2 plume completely reaches the anticline dome, it gets stagnates in the anticline dome. This restricts the CO2 plume from migrating in the lateral direction. This restriction of CO2 plume in the domain will limit the residual trapping. In simulation 1, the saturation of CO2 on the top surface of the domain is more compared to simulation 2. This implies that the CO2 migration in simulation 2 is less because ScCO2 dissolves into the resident reservoir water and undergoes solubility trapping. To understand more on CO2 migration in the formation domain, the mass of CO2 in various forms is quantified in Figures 3(b) and 3(c). For the initial 30 years of injection, 9.7 Mega tonnes of CO2 was injected into the formation. Figure 3(b) illustrates the dynamic variation of the mass of CO2 in the form of structural and residual trapping and free mobile CO2, where the dissolution mechanism is not considered (simulation 1). Figure 3(c) illustrates the efficiency of solubility trapping by quantifying the mass of CO2 in both aqueous and gas phases. In Figure 3(c), CO2 aqueous represents the dissolved mass of CO2 in water, and the CO2 gas represents the free mobile, structural and residual trapped CO2 over a geological time scale. It can be observed that the structural and residual trapping was dominant during the injection period (30 years) (see Figure 3). However, during the migration, the solubility of CO2 in water is prevalent from Figure 3(c). During the postinjection period, the CO2 plume stagnates under the anticline dome, and the constant dissolution of CO2 into resident water will take place. And about 90% of injected CO2 is dissolved in water at 3000 years (see Figure 3(c)).


## 4.2. Solubility Fingering Phenomena

After injecting the ScCO2 into the domain, it will form a CO2 plume, start migrating upwards, and spread laterally under impermeable caprock. After the injection is ceased, the velocity of the CO2 plume will decrease gradually over time, which increases the contact time between the CO2 plume and the connate reservoir water. The obtained results of plume migration in the domain are illustrated in Figure 4. The interface layer will be formed between the CO2 plume and connate reservoir water. At the interface, the CO2 dissolves into connate reservoir water. Molecular diffusion and mass transfer occur from CO2 plume to resident reservoir water. As the CO2 dissolved into the water, it became denser and led to convection mixing in the downward direction [18, 57].Figure 4
Solubility fingering phenomenon during CO2 geological sequestration and their evolution over geological time scale.The fingering phenomenon occurs during the solubility trapping mechanism due to the dissolution-diffusion-convection process. The solubility fingers form in the domain help increase the efficiency of solubility trapping. Due to this fingering phenomenon, more CO2 will come in contact with the fresh formation water. The illustrative results of the fingering phenomenon can be seen in Figure 4. The CO2 concentration is higher near the injection well during the injection period, and the dominance of dissolution is not seen in the domain (see Figure 4 for 30 years). During postinjection, the plume spreading over a geological time scale creates more CO2-water interface to facilitate the CO2 dissolution phenomena. It is observed that the fingering phenomena gradually shift beneath the anticline dome where the maximum amount of CO2 plume has migrated. The number of fingers increases with geological time scale (see Figure 4 for 200 and 3000 years). This phenomenon of solubility trapping effect is evident in Figure 4 for comparison of CO2 saturation in residual trapping-only trapping and residual-and-solubility trapping.The simulation results in Figure5 depict the fate of CO2 at discrete geological times in the form of a CO2 mole fraction across the domain. After reaching the caprock, the plume laterally spreads under the impermeable caprock. During this time, one can notice a constant decrease in the CO2 mole fraction. This can be attributed to residual and solubility trapping, which works in tandem to increase the entrapment of the injected CO2. The plume reaches the caprock within one year, and at the end of the injection period, it slowly starts to migrate towards the anticline dome. It assumed that the upper layer of the domain is impermeable. Therefore, it will restrict the CO2 from passing through it and allow it to migrate towards the anticline. During this migration, due to the absence of injection force and the presence of perturbation on caprock, the momentum of the CO2 plume decreases, which increases the contact time between CO2 and water, which further leads to an increase in the percentage of entrapment in the domain. A steady reduction in CO2 mole fraction and increase in total aqueous phase CO2 quantity after the injection phase suggest that the entrapment of CO2 occurs through the solubility trapping mechanism.Figure 5
Illustration of CO2 mole fraction and pH variation over geological time scale during CO2 geological sequestration.The CO2 mole fraction and pH variation results are presented in Figure 5. Initially, a pH of 5.6 is attributed to the whole domain. As the CO2 moves upwards and percolates through the formation layer, the CO2 starts getting dissolved into connate reservoir water, which further leads to a decrease in pH value in the domain. From the results, it is observed that the large volume of the synthetic domain can be seen to be covered with a low pH. This happens due to lateral spreading and solubility fingering phenomenon of CO2 plume in the domain; the results are illustrated in Figure 5. The pH drops to 3.5, suggesting solubility trapping occurrences with safe entrapment of injected CO2 in the domain. For mineral trapping to occur, certain conditions are required, of which pH is an essential factor. For example, to have a dissolution of silicate minerals, a low pH range is preferred to have a higher concentration of H+ ions on the reactant side. For a precipitation reaction to occur, a slightly higher pH is preferred. In order to have reliable sequestration trapping, it is preferred to have an optimal pH range. The aforementioned pH range of 3.5-5 is considered optimal enough to promote both dissolution reaction and precipitation reaction and thereby enhance the storage of CO2 in the domain [58].


## 4.3. Caprock Structure Influence on Solubility Trapping

In this section, the simulation study is carried out to analyze the influence of caprock structure on CO2 geological sequestration. The first set of simulations is carried on the synthetic domain incorporated with the anticline domain, and it will be referred to as synthetic domain-1 in the subsequent text. In the second set of simulations, a synthetic domain without caprock morphological structure is considered, and it is referred to as synthetic domain-2. Figure 6(a) illustrates the CO2 mole fraction distribution for both synthetic domains. From Figure 6(a), it is observed that by the end of the simulation time, the CO2 mole fraction distribution is lesser in synthetic domain-2 as compared to synthetic domain-1. It may be due to high lateral spreading and displacement efficiency in synthetic domain-2. Due to high lateral spreading, a large quantity of CO2 came in contact with connate water, which triggered a dissolution reaction and further initiated the fingering phenomenon. So, for this reason, the total aqueous phase CO2 quantity observed was higher, and the free mobile CO2 quantity was lower in the synthetic domain-2 compared to synthetic domain-1 (see Figure 7(c)).Figure 6
Influence of caprock morphology on (a) CO2 mole fraction and (b) pH variation over a geological time scale.
(a)(b)Figure 7
Influence of caprock morphology on (a) average reservoir pressure, (b) average reservoir temperature, and (c) aqueous and gaseous phase CO2 quantity variation over geological time scale.
(a)(b)(c)Figures6(a) and 6(b) give an illustrative explanation about the higher solubility of injected CO2 in synthetic domain-2 compared to synthetic domain-1. In the pH variation simulation results, see Figure 6(b); it is observed that a large volume of the domain in synthetic domain-2 is covered with low pH compared to synthetic domain-1. The volume covered and displacement efficiency of injected CO2 plume is less in synthetic domain-1 than in synthetic domain-2. It is due to the migration pathway of CO2 plume is congested to narrow pathway towards anticline centre. In synthetic domain-2, due to the absence of an anticline dome, the injected CO2 plume leads to more spreading in the lateral direction, which leads to higher CO2 dissolution. Furthermore, it contributes to the fingering phenomenon, which increases the dissolution in the depth axis and increases the vertical spreading. In this way, the pH in the domain changes over geological time. The low pH region created during the solubility trapping phase might trigger a mineral reaction for the mineral trapping mechanism as the domain’s pH range is within the acceptable limits [59].The average reservoir pressure and temperature results of synthetic domain-2 are in the commendable range (see Figures7(a) and 7(b)). As predicted, in Figure 7(a), the pressure in synthetic domain-1, i.e., with anticline structure, is high at the end of the simulation time compared to synthetic domain-2, i.e., without anticline structure. Due to the narrow pathway and stagnated CO2 in the dome centre, it will uphold the normal reservoir pressure in synthetic domain-1. It is observed that the average reservoir temperature has not shown any significant variations during simulations. Its effects were recorded over the geological time scale were nominal (see Figure 7(b)). From solubility trapping, as depicted in Figure 7(c), it is observed that the mass of CO2 dissolved in water at any time is higher in synthetic domain-2 compared to synthetic domain-1. As mentioned earlier, high lateral spreading in the synthetic domain-2 leads to more entrapment in the migration pathway. In synthetic domain-1, due to the presence of an anticline structure, the lateral spreading of the CO2 plume was restricted and remained low, which ultimately reduced the residual and solubility entrapment. Overall, the free mobile CO2 quantity is low in synthetic domain-2 compared to synthetic domain-1; from Figure 7(c), it is evident that at 3000 years, most of the injected CO2 was dissolved in the water phase.In comparison, 99% of the injected mass is dissolved without anticline structure, whereas it is 90% in the anticline structure case. But at a higher injection rate, synthetic domain-2 has shown a large quantity of CO2 migrating out of the observable domain. In certain situations, the injected CO2 must be confined within the limits of the geological domain by which CO2 can be restricted from exploring the geological cracks and fault structures, which might further lead to leakage [45]. In such a scenario, the presence of geological structures like anticline dome in synthetic domain-1 is a viable option. As illustrated in synthetic domain-1 results, see Figure 6, the anticline dome restricts the CO2 within the observable domain limits.The low availability of storage volume and low injection rate can increase the risk factor and financial aspects of the CCS operation in synthetic domain-2. The synthetic domain-1 can be cost-effective (see Figures6(a) and 6(b)); it can be observed that injected CO2 is migrating under a small volume of anticline dome, which will reduce the monitoring cost as it will require to screen a small area. But if the anticline dome contains faults, it can create severe problems for the safe operations of CCS.


## 5. Summary and Conclusions

In carbon capture and sequestration (CCS), CO2 storage in geological formations is proven to be a viable solution [4]. During geological sequestration, the fate of CO2 is governed by multiphase flow and geochemical interactions between water, CO2, and minerals in the form of structural, solubility, and mineral trapping mechanisms. Solubility trapping is a significant phenomenon to facilitate the mineralization of CO2. The structure of the caprock plays a major role in interaction of CO2 with water to maximize solubility trapping during geological sequestration. In this work, the reactive transport modelling technique was used to simulate and understand the influence of caprock morphology on the solubility trapping mechanism. The outcome of the work is summarized as
(i)
The mole fraction of CO2 and pH distribution across the synthetic domain are two major features to analyze and visualize the influence of caprock morphology on solubility trapping(ii)
The variation of the CO2 mole fraction over a geological time scale helped to visualize the entrapment of CO2 within the formation zone. At the same time, the change in pH values helped in imagining solubility trapping that took place within the formation in the depth axis(iii)
A comparative simulation study between two simulation domains (with and without anticline dome) was conducted to study the influence of caprock morphology. It was noticed that the presence of the anticline dome reduces the solubility trapping efficiency, but increases the range of the injection rate(iv)
The influence of the solubility fingering phenomenon in increasing the CO2 entrapment was observed from CO2 solubility trapping plots. These factors helped understand that the naturally available domain is better in storing the injected CO2(v)
The average reservoir pressure plots have given a distinguished explanation for two comparative sets of simulation models, which helped analyze the effective storage of injected CO2 in the formation domain(vi)
Future works include the development of a comprehensive reactive transport model by incorporating the geochemistry of minerals, which elucidate the fate of CO2 in the form of structural, residual, solubility, and mineral trapping mechanisms(vii)
The future comprehensive model shall accommodate the heterogeneity effects of formation domains such as mineralogy, wettability conductions, pH, and salinity of connate water



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*Source: 8016575-2022-06-25.xml*