Evaluation of Caprock Sealing Performance for CO₂ Saline Aquifer Storage: A Numerical Study

Abstract

The integrity of caprock sealing is a crucial factor in guaranteeing the safety and long-term feasibility of CO₂ saline aquifer storage. In this study, we identified three principal mechanisms that give rise to topseal failure: (1) gradual CO₂ seepage through the upper cap, (2) capillary seal failure resulting from the pressure increment due to CO₂ injection, and (3) localized overpressure causing cap rupture. Through the integration of numerical simulation and geomechanics, this study offers a sealing assessment for the caprock. The thorough analysis of the sealing performance of the Guantao formation reveals that after 2000 years of CO₂ injection, the caprock would undergo intrusion by 35 m without any leakage risk. Moreover, investigations into CO₂–water–rock interactions suggest that precipitation reactions outweigh dissolution reactions, leading to a decreased permeability and an enhanced sealing performance. The most likely fracture mode identified is shear fracture with a critical caprock fracture pressure of 36.48 MPa. In addition to these discoveries, it is significant to consider ongoing research aimed at enhancing our ability to predict and manage potential risks associated with carbon capture and storage technologies.

1. Introduction

The increasing threat posed by greenhouse gas emissions has made global warming a critical challenge of the 21st century. Despite our reliance on fossil fuels such as oil, natural gas, and coal, saline aquifer storage has emerged as an effective approach for reducing atmospheric CO₂ levels [1,2,3]. Efficient, safe, and economically feasible carbon dioxide sequestration is a highly valuable and complex research goal. In recent years, there has been growing interest in exploring alternative methods for reducing greenhouse gas emissions beyond traditional carbon capture and storage techniques. Researchers have been investigating innovative approaches such as direct air capture technology, bioenergy with carbon capture and storage (BECCS), and enhanced weathering to complement existing strategies [4,5,6]. Furthermore, international collaboration and investment in large-scale demonstration projects are crucial for advancing the deployment of carbon sequestration technologies [7,8]. In our urgent efforts to mitigate the impacts of climate change, it is crucial to prioritize sustainable solutions that can effectively reduce CO₂ emissions without compromising energy security or economic development [9,10].

The integrity and effectiveness of CO₂ sequestration are significantly influenced by geological discontinuity, CO₂–water–rock reactions, and extreme conditions of temperature, pressure, and stress within deep saline aquifers [11]. Current research primarily focuses on caprock properties such as thickness, permeability, porosity, and capillary pressure [12,13,14,15]. According to Fu et al., greater caprock thickness, broader horizontal distribution, and enhanced airtightness are associated with improved containment efficacy [16]. Jiang et al. stress that the primary sealing mechanisms of the cap layer are capillary sealing and permeation sealing. Capillary sealing occurs at the CO₂–brine interface, preventing any upward flow of CO₂. Permeation sealing takes place when the breakthrough pressure is exceeded with the cap layer serving as a barrier to permeation. While both mechanisms exhibit limited leakage, they persist over an extended period [17].

Studies have also investigated the movement of CO₂ under various reservoir conditions. Li et al.’s research on sandstone reservoirs in Ordos demonstrates that both the permeability of the reservoir and the pressure–temperature conditions influence the migration of CO₂ [18]. Cui examined how reservoir permeability distribution and temperature impact the stable burial efficiency of CO₂ saline aquifers by establishing a comprehensive characterization index for burial efficiency, using numerical simulation and Pearson correlation coefficient statistics [19].

While these studies provide a theoretical basis, their practical application is still constrained. Diao et al. established a geological safety evaluation system and determined that the impermeability and mechanical stability of the caprock are of significant importance, indicating that a stable regional caprock is crucial for ensuring successful CO₂ geological storage [20]. However, there is still a lack of comprehensive studies that integrate both physical properties and CO₂–water–rock reactions.

This study thoroughly examines the intricate dynamics of the saline aquifer within the Guantao formation, which is located within an oilfield of the Bohai Sea. Through a detailed assessment of CO₂–water–rock interaction, this research aims to elucidate the interplay between these elements and their impact on subsurface geological formations. Using numerical simulation methods, it seeks to evaluate the sealing effectiveness of the Ming-Huazhen formation cap layer. Furthermore, by integrating geomechanics techniques with numerical simulations, this study aims to examine potential risks associated with hydraulic fracturing and CO₂ injection-induced leakage in the caprock. The analysis encompasses both dynamic and static perspectives, providing a robust foundation for optimizing the location and deepening our insights into more effective strategies for utilizing and strengthening the sealing layer in this geological setting.

2. Geological Setting

The Guantao Formation in the Bohai Sea region exhibits a stable geological structure characterized by significant sand body thickness (510–650 m) and high porosity and permeability. The overlying Minghuazhen Formation’s mudstone cap layer, approximately 40 m thick, serves as a reliable seal. Faults are rarely observed within both the cap layer and storage unit. The formation pressure is calculated to be 23.92 MPa, with a temperature of 97 °C, which maintains the CO₂ in a supercritical state.

The basic physical properties of the reservoir are shown in

Table 1. Basic parameters of reservoir model.

Type	Value
Bottom hole pressure	32 MPa
Temperature	97 °C
Salinity	0.99 NaCl (CaCl2 of Water type)
CO2 injection rate	6.5 kg/s, 4.0 kg/s, 1.5 kg/s (562 t/d, 350 t/d, 130 t/d)

and

Table 2. Geological parameters of cap rock and reservoir.

Type	Target Stratum
	Mudstone Caprock	Sandstone Formation
Permeability (m2)	1.00 × 10−18	5.80 × 10−13
Porosity (%)	5	17
CO2 injection rate (wt.%)	0.99	0.99
Residual water saturation	0.3	0.15
Residual gas saturation	0.05	0.1
Maximum water saturation	0.99	0.99
Maximum gas saturation	0.99	0.99
Capillary pressure (MPa)	0.0621	0.0196

. The water quality indicators and rock mineral composition of formation water are shown in

Table 3. Ionic composition and concentration of saline water.

Concentration (mol/kg)
K+	Na+	Mg2+	Ca2+	Cl−	SO42−	HCO3−
1.15 × 10−3	0.17	4.167 × 10−4	5.65 × 10−3	0.1745	1.146 × 10−4	5.403 × 10−3
Mineralizaion (mg/L)			Water Type	pH
10,769			CaCl2	7.48

and

Table 4. Rock mineral composition.

Type	Target Stratum
	Formation	Caprock
Calcite	3	7
Quartz	43	40
Kaolinite	0	4
Illite	0	7
Low-albite	17	10
Smectite-Na	15	24
K-feldspar	17	3
Chlorite	5	5

. These reservoir parameters will be input into the model. The parameter values in the model come from the data of a single well, and the reservoir has heterogeneity. It is possible that the data of this well cannot fully represent the reservoir parameters, which will affect the accuracy of the model results. We recommend using data from multiple wells for a more practical scenario.

3. Methodology

Two key factors primarily influence the caprock sealing performance: capillary sealing and hydraulic sealing. The capillary pressure threshold is affected by pore throat size, wettability, and CO₂–water surface tension. Numerical simulation can be used to study capillary breakthrough, taking into account pressure, temperature, chemical changes, and the mechanical response of the rock. Hydraulic sealing can be evaluated through the construction of a stress field model to identify failure conditions and guide field applications.

3.1. Numerical Simulation of Thermo-Hydro-Mechanical–Chemical (THMC)

Physical experiments related to the geomechanics response and CO₂ migration and transformation laws are typically limited to small spatial scales (<1 m) and short time spans (<30 day). This limitation poses a challenge in elucidating the CO₂ sequestration mechanisms at the stratigraphic scale. However, numerical experiments can comprehensively consider the physical and chemical interactions of CO₂–water–rock over extensive spatiotemporal ranges, offering a more comprehensive understanding.

The phase state of CO₂ is determined by temperature and pressure, while the physical and chemical interactions between CO₂, water, and rock are influenced by temperature. The behavior of multiphase flow involving water and CO₂, as well as the coupling of flow pressure/velocity distribution with chemical fields, stress fields, and temperature fields, have a significant impact on CO₂ storage efficiency and long-term safety. The chemical field primarily considers the physical and chemical reactions among CO₂, water, and rock. While salt precipitation may reduce pore permeability, rock dissolution by H₂CO₃ may increase pore permeability along with changes in the mechanical properties of the rock. Under the combined effects of fluid pressure and original geostress, geological formations may deform and fail, leading to potential CO₂ leakage through activated joints, fractures, or faults which may compromise the integrity of CO₂ storage.

A fully coupled mathematical model has been developed based on the principles of THMC to simulate rock deformation, CO₂ migration, and temperature distribution during CO₂ injection. This model considers thermal conduction, flow, and deformation dynamics while incorporating the CO₂–water–rock interactions through a solute transport equation that includes chemical reactions for salt precipitation and dissolution.

3.1.1. Thermal Conduction

The phase behavior of CO₂ is influenced by temperature and pressure, while the physical and chemical interactions between CO₂, water, and rock are dependent on temperature. As a result, an overall energy conservation equation that accounts for thermal convection and conduction is formulated.

$${\displaystyle \frac{d}{dt}}\underset{V_n}{\int }{M}^{\kappa }d{V}_n=\underset{{\Gamma }_n}{\int }{E}^{\kappa }\cdot {nd\Gamma }_n+\underset{V_n}{\int }{q}^{\kappa }d{V}_n$$

(1)

where $M^{\kappa }$ represents the total energy of solids and fluids

$$M^{NK+1}=(1-\varphi ){\rho }_R{C}_{R}T+\varphi \sum _{\beta }{S}_{\beta }{\rho }_{\beta }{u}_{\beta }$$

(2)

where $E^{\kappa }$ represents the add-up of the heat conduction term and the heat convection term, which can be expressed as

$$E^{NK+1}=-\mathsf{\lambda }\nabla \mathrm{T}+\sum _{\beta }{h}_{\beta }{F}_{\beta }$$

(3)

3.1.2. Flow Model

In accordance with the principles of CO₂ and brine migration and transformation, while taking into account convection and diffusion effects, the continuity equations for each component fluid can be formulated.

$${\displaystyle \frac{d}{dt}}\underset{V_n}{\int }{P}^{\kappa }d{V}_n=\underset{{\Gamma }_n}{\int }{F}^{\kappa }\cdot {nd\Gamma }_n+\underset{V_n}{\int }{q}^{\kappa }d{V}_n$$

(4)

where $P^{\kappa }$ is the cumulative term of volumetric mass.

$$P^{\kappa }=\varphi \sum _{\beta }{S}_{\beta }{\rho }_{\beta }{X}_{\beta }^{\kappa }$$

(5)

$F^{\kappa }$ represents the convection and diffusion terms

$${\left.F^{\kappa }\right|}_{adv}=\sum _{\beta }{X}_{\beta }^{\kappa }{F}_{\beta }$$

(6)

$${\left.F^{\kappa }\right|}_{dis}=-\sum _{\beta }{{\rho }_{\beta }\overline{D_{\beta }^{\kappa }}\nabla X}_{\beta }^{\kappa }$$

(7)

3.1.3. Deformation Model

The mechanical response of rock deformation and discontinuous geological structures can be effectively described by the following stress expression.

$${\sigma }_{ij}={\sigma }_{ij}^{\prime }+mp{\delta }_{ij}$$

(8)

Equilibrium equation of rock mass continuous medium

$${\sigma }_{ij,j}^{\prime }+f_i=0$$

(9)

Deformation equation

$${\epsilon }_{ij}={\displaystyle \frac{1}{2}}\left(u_{i,j}+u_{j.i}\right)$$

(10)

Elastic–plastic constitutive equation

$${d\sigma }_{ij}^{\prime }=D_{ijkl}^{ep}{d\epsilon }_{kl}$$

(11)

3.1.4. CO₂–Water–Rock Reaction

A solute transport equation incorporating chemical reactions to account for salt precipitation and dissolution effects between CO₂–water–rock can be formulated based on Equation (1).

A multi-component multiphase CO₂ migration THMC numerical model can thus be developed utilizing the finite element method and finite volume method. The specific calculation process is shown in Figure 1.

3.2. Hydraulic Sealing Mechanics

The mechanical stability was evaluated using a stress field model to determine the activation pressure and fracture mechanics of the caprock with shear fracture identified as the primary failure mode.

3.2.1. Construction of Stress Field

Based on the stress analysis at the discontinuity level of the Mohr circle and its correlation with the rupture envelope, the additional fluid pressure can be formulated as

$$∆P={\sigma }_n-\left(\tau -C\right)/\mu$$

(12)

The activation pressure can be expressed as

$$P_R=∆P+P_p$$

(13)

The activation pressure coefficient can be described as the ratio of activation pressure to static water pressure

$$P_{RC}=P_R/\left({\rho }_{w}gh\right)$$

(14)

According to the leakage test from three wells, the relationship between three-dimensional stress and depth is obtained as follows: vertical principal stress S_v = 0.0203 h, maximum horizontal principal stress SH_max = 0.0208 h − 0.93, and minimum horizontal principal stress Sh_min = 0.0176 h − 2.34

3.2.2. Rupture Mechanics

Due to the lack of tensile strength data in the study area, that of the same layer in the nearby block is referenced (

Table 5. Failure mechanics of cover layer (Mildren et al., 2005) [21].

Fracture Mode	Rock Fracture Criterion	Stress Condition
Tensional rupture (hydraulic rupture)	P = σ3 + T	(σ1 − σ3) < 4T
Mixed rupture of tension and shear	P = σn + (4T2 − τ2)/4T	4T < (σ1 − σ3) < 6T
Shear fracture	P = σn + (C − τ)/μ	(σ1 − σ3) > 6T

), which is 1.0 MPa. Applying the top depth of the cover, σ₁ − σ₃ = 14.09 MPa, which meets the condition of (σ₁ − σ₃) > 6T stress according to the rock rupture criterion. Therefore, the cap rupture in the study area is shear rupture.

4. Result and Discussion

4.1. CO₂ Migration and Caprock Intrusion

Base on the typical reservoir profile in the Field A area, a two-dimensional model was established with a cap layer thickness of 40 m (Figure 2). The injection point was designed to be 60 m below the top surface of the reservoir, as shown in Figure 3. Subsequently, it was initialized based on the actual hydrogeological parameters, mineral components of the formation, and chemical components of the aqueous solution. Injection boundary conditions, outflow boundary conditions, and initial conditions were defined for conducting numerical simulation of CO₂–water–rock chemical reaction heat–chemistry–flow–solidity over an injection period of 30 years.

During the initial 30 years, CO₂ injection continued, resulting in a lateral migration distance of approximately 600 m at the bottom and an increasing migration distance at the top over time. By the 300-year mark, the distribution pattern of CO₂ had stabilized with no significant changes in migration distance observed from then until the 2000-year mark. Throughout the injection period, CO₂ consistently infiltrated the caprock, reaching approximately 5 m after 30 years and nearly reaching the top of the caprock by the 2000-year mark. By that year, the maximum intrusion distance of dissolved CO₂ into the caprock had reached about 35 m at an extremely low intrusion rate.

During the initial 30 years, the lateral spread of CO₂ at the depth of injection was approximately 600 m, while the transport distance near the caprock gradually increased over time. After 300 years, the distribution of CO₂ stabilized, and there were no significant changes in migration distances from then until the 2000-year mark. Throughout the injection process, CO₂ seeped into the caprock, reaching around 5 m within 30 years. By 1000 years, the dissolved CO₂ had migrated approximately 35 m, reaching almost to the top of the caprock. This slow seepage continued until the 2000-year mark.

4.2. CO₂–Water–Rock Interaction

The CO₂–water–rock interaction within the caprock was simulated numerically. The pH of the brackish water showed a significant decrease immediately after the start of the injection, followed by an increase after 1000 years, and then showed minimal variation. The concentration of HCO₃⁻ in solution gradually increased, indicating an increasing dissolution of CO₂. Calcite, potassium feldspar, and chlorite all underwent dissolution reactions with calcite and chlorite demonstrating increased dissolution over time. Magnesite underwent a precipitation reaction, leading to greater precipitation with prolonged duration. Owing to the prevalence of precipitation reactions over time, the porosity and permeability of the caprock were notably diminished (Figure 4). Based on these findings, we infer that the CO₂–water–rock interaction in the caprock has a negligible impact on its capillary sealing capacity, resulting in an extremely low risk of caprock leakage.

4.3. Hydraulic Fracturing Risk

Through three-dimensional geological modeling, we have utilized caprock data and stress field information specific to our research site to develop a comprehensive model. This model depicts hydraulic fracturing pressures within T0 reflector layers. Due to minimal depth variations across the various layers of the cover, wide-ranging color codes fail to distinctly highlight weaknesses in their hydraulic seal capabilities. To reveal these vulnerabilities, we employ a single-layer assessment approach. By simulating and computing caprock’s top-to-bottom hydraulic seal capacities for each stratum using stress fields, we derive fracture pressure values within respective ranges—thus enabling a quantitative evaluation of caprock’s overall sealing performance in this region (Figure 5).

The top depth of the cover layer on the surface of the Guantao formation is 2270 m. Based on the hydraulic fracturing pressure plan and stress Mohr circle at this depth, the fracturing pressure is calculated to be 36.48 MPa with a fracturing pressure coefficient of 1.61. The bottom depth of the top cover layer on the Guantao Formation is 2345 m. According to the hydraulic fracturing pressure plan and stress Mohr circle at this depth, the calculated fracturing pressure for the top cover layer on the Guantao formation is 37.61 MPa with a fracturing pressure coefficient of 1.60 (Figure 6).

In conclusion, with increasing burial depth, the hydraulic fracturing pressure of the caprock gradually rises, resulting in the highest risk of fracturing at the top depth of the caprock. The minimum fracturing pressure of the caprock in this area is 36.48 MPa.

5. Conclusions

The integrated numerical simulation of THMC processes comprehensively takes into account temperature distribution, rock deformation, crack/fault activation, and CO₂–water–rock physical and chemical reactions during and after CO₂ saline aquifer storage injection. This approach facilitates the assessment of CO₂ phase change, rock mechanics analysis, fault and cap sealing evaluation, as well as prediction of permeability changes in the cap and reservoir. In addition, it offers guidance for calculating the CO₂ storage capacity and optimizing the design parameters for saline aquifer storage engineering.

The thick overlying mudstone cap layer of the Guantao Formation in the Field A area exhibits excellent sealing properties. The simulation results indicate that following 2000 years of CO₂ injection, the caprock would experience an intrusion of approximately 35 m without any leakage. This demonstrates a stable CO₂ distribution pattern and minimal migration distance beyond 300 years. The interaction between CO₂, water, and rock primarily involves the dissolution of calcite, potassium feldspar, and chlorite with precipitated magnesite contributing to reduced caprock permeability and enhanced sealing capacity. The hydraulic fracturing pressure of the caprock increases with depth. At the top of the caprock, a minimum fracturing pressure of 36.48 MPa was identified. Shear was identified as the primary fracture mode, indicating a low risk of hydraulic failure under current conditions.