Mechanism, Modeling and Challenges of Geological Storage of Supercritical Carbon Dioxide

Abstract

CO₂ geological storage (CGS) is critical for mitigating emissions in hard-to-abate industries under carbon neutrality. However, its implementation faces significant challenges. This paper examines CO₂-trapping mechanisms and proposes key safety measures: the continuous monitoring of in situ CO₂ migration and formation pressure dynamics to prevent remobilization, and pre-injection lithological analysis to assess mineral trapping potential. CO₂ injection alters reservoir stresses, inducing surface deformation; understanding long-term rock mechanics (creep, damage) is paramount. Thermomechanical effects from supercritical CO₂ injection pose risks to caprock integrity and fault reactivation, necessitating comprehensive, multi-scale, real-time monitoring for leakage detection. Geostatistical analysis of well log and seismic data enables realistic subsurface characterization, improving numerical model accuracy for risk assessment. This review synthesizes current CGS knowledge, analyzes technical challenges, and aims to inform future site selection, operations, and monitoring strategies.

1. Introduction

1.1. Background

Since the Industrial Revolution, atmospheric concentrations of CO₂ and other greenhouse gases (e.g., CH₄, N₂O) have risen significantly [1]. Figure 1 illustrates the sectoral distribution of greenhouse gas emissions. The primary drivers include fossil fuel combustion in power-generation and industrial processes [2], reduced CO₂ absorption capacity due to deforestation, substantial CO₂ emissions from building construction and operation life cycles [3]. From before industrialization to the present, the concentration of CO₂ in the atmosphere has increased from 280 ppm to 420 ppm, an increase of nearly 50%. If this phenomenon is not controlled, it will have serious impacts. The emitted CO₂ may dissolve in seawater, causing the acidification of seawater, adversely affecting the marine ecosystem [4], and elevating the incidence of respiratory diseases [5]. As early as the 21st United Nations Climate Change Conference in 2015, 178 countries jointly signed the Paris Agreement, suggesting that the increase in the global average temperature be limited to within 2 °C of the pre-industrial level. Relevant studies show that the implementation of CCUS (Carbon Capture, Utilization and Storage) technology could reduce global CO₂ emissions by 14%. CO₂ geological storage is an important supporting technology for the sustainable development of difficult-to-reduce industries under the background of achieving carbon neutrality [6], aiming to eliminate CO₂ emissions related to fossil fuel consumption [7]. It has been implemented in multiple sectors, including the energy and fuel sector, the petroleum industry, and chemical production, etc.

CO₂ utilization enables Carbon Capture, Utilization, and Storage (CCUS), which is the primary carbon-emission option for power plants and industrial plants [8]. Carbon capture is achieved from the atmosphere through methods such as physical and chemical adsorption. Then, captured CO₂ is converted into value-added products, enabling carbon utilization. Carbon storage refers to the permanent sequestration of CO₂ within geological formations. The main method of CCUS application is to store CO₂ in geological structures—primarily deep saline aquifers, gas reservoirs, and unmineable coal seams (

Table 1. CCUS geological structures.

Formation Type	Advantage	Disadvantages
Deep Saline Aquifers	Deep saline aquifers exhibit extensive global occurrence, possess the largest theoretical storage capacity, are typically sealed by shale caprocks, and provide effective CO2 containment.	Deep saline aquifers are often poorly characterized geologically, exhibiting significant uncertainties in porosity, permeability, and caprock integrity. Consequently, injectivity may be constrained, while accurately mapping CO2 plume migration and verifying long-term containment states poses substantial technical complexity and cost.
Gas Reservoirs	Geological structure, reservoir properties, caprock sealing capacity, and trapping mechanisms are well characterized. The existing infrastructure can be repurposed, significantly lowering development costs. Offers enhanced economic viability potential, particularly when combined with enhanced oil recovery.	With limited storage capacity, Wellbore integrity requires rigorous assessment, as existing wells may serve as potential leakage pathways. Long-term production activities may compromise reservoir integrity, affecting injectivity and containment security.
Deep Unmineable Coal Seams	CO2 exhibits stronger adsorption affinity to coal surfaces than methane, enabling displacement of coalbed methane (CBM). This mechanism achieves concurrent CO2 sequestration and enhanced CBM recovery (ECBM), offering significant economic benefits.	Low permeability poses injectivity challenges, while complex fracture networks and strong reservoir heterogeneity further complicate operations. Critically, CO2 adsorption induces significant coal-matrix swelling, thereby reducing permeability and constraining long-term injectivity.

) [9]. The concept of CO₂ geological storage can be traced back to the oil and gas industry at the earliest, when CO₂ was injected into oil and gas reservoirs to achieve the purpose of enhanced oil recovery [10]. CO₂ geological storage, often referred to as carbon capture and storage (CCS), is a process of capturing CO₂ emissions from various sources, such as industrial plants, power plants, and other CO₂ production facilities, and safely storing them to prevent their release into the atmosphere [11]. Pursuant to the 2015 Paris Agreement goals, nations including China, Japan, and Australia have launched CO₂ storage projects to reduce emissions during energy transitions [12]. The United States and Northern Europe lead in implementing geological storage projects.

Table 2. Example of CO₂ storage.

Name	Location	Storage Capacity	Main Information
In Salah	Algeria	1700 Mt [14]	This fully operational, world-pioneering onshore gas field receives CO2 from the In Salah oil field, a depleted reservoir. Injection was suspended in June 2011 due to caprock integrity concerns [15,16,17].
Ketzin	Ketzin, Germany	67,271 t	Europe’s first onshore CO2 storage project injected the gas into a saline sandstone aquifer at ~630 m depth [18,19].
Sleipner	The mid-central North Sea	15.5 Mt	The world’s first commercial-scale CO2 injection project stored the gas in a Norwegian North Sea saline aquifer, 800–1000 m below the seabed [20,21].
Weyburn-Midale	South central Saskatchewan (Canada)	20 Mt [22]	The Weyburn project aimed to boost oil production via CO2-EOR, targeting two Midale carbonate reservoir aquifers: porous vuggy beds and dolostone marly beds [23,24].
Ordos	Inner Mongolia (China)	15 Mt	A comprehensive monitoring system (ground, surface, and subsurface) tracked CO2 migration using vertical seismic profiles (VSP). Results showed oil/gas reservoirs outperform saline aquifers for storage [25,26].

shows some examples of actual CO₂ geological storage projects. According to the relevant geological assessments, the global CO₂ storage capacity is approximately 800 to 550 billion tons, distributed across various regions [13]; for details, please refer to Figure 2. Given this vast capacity, understanding subsurface trapping mechanisms and deploying appropriate monitoring technologies is critically important.

Underground reservoirs have demonstrated the ability to store fluids such as oil, natural gas, and water for millions of years. Therefore, it is feasible to achieve geological CO₂ storage on a timescale [27]. Successful geological CO₂ storage requires low-porosity caprocks to prevent leakage and reservoir rocks with sufficient capacity for large-volume storage. When CO₂ exceeds its critical point (31.1 °C, 7.38 MPa), it enters the supercritical state and has diffusability similar to that of a gas and a density similar to that of a liquid. Under reservoir conditions, its density is usually 600–800 kg/m³. Consequently, injection depths exceeding 700–800 m are recommended to maintain supercritical conditions [12].

1.2. Research Methods

This article reviews the literature related to CO₂ geological sequestration, discusses the various storage mechanisms of CO₂ geological sequestration, the interaction between CO₂ and rocks under different conditions, including rock pores and crack development and gas-migration rules inside the rocks, and evaluates the safety of CO₂ geological sequestration through numerical simulation literature; in addition, monitoring methods suitable for CO₂ geological storage were also analyzed, and the two were discussed in combination with the current development of AI technology. The work is mainly carried out from the following four aspects, as shown in Figure 3 in detail.

1.3. Review Purpose

This review is based on the research content and results of the CO₂ geological sealing field, aiming to understand the CO₂ capture mechanism and deeply analyze the physical and chemical effects of CO₂ and the surrounding rocks in the geological sealing state, so as to discuss the deterioration mechanism of surrounding rocks. The safety of geological sealing is analyzed through numerical simulation; numerical simulations reveal the migration patterns of CO₂ within the reservoir. Through multiphysics coupling, these simulations analyze mineral dissolution and fracture development under various conditions, allowing for the assessment of geological storage safety. There are corresponding descriptions for monitoring technology. This knowledge can provide reference for the practice of researchers and field staff to ensure the safety and efficiency of CO₂ geological storage projects.

Baskaran [28] analyzed CO₂ capture technology (pre-combustion, post-combustion, oxy-fuel combustion, and chemical looping combustion), alongside CO₂ utilization pathways including chemical conversion (e.g., urea, methanol, carbonate synthesis), food carbonation, and building materials, but there are still certain defects in environmental and long-term monitoring, and there is a lack of discussion on the CO₂ trap mechanism. Davoodi [29] discussed the CO₂ storage mechanism, including the effect of fluid mechanical trapping and the influence of capillary force, and analyzed the impact of the reaction mechanism between CO₂ and different minerals in different rock layers on CO₂ injection, including the saline layer, unmined coal seam, oil, natural gas reservoir, basalt base layer, and organic matter-rich shale. While highlighting machine learning applications in CCUS, the work lacked an analysis of geomechanical degradation and long-term leakage monitoring. Aminu [30] reviewed global CO₂ geological sequestration projects, establishing site-selection criteria based on geological stability, geothermal gradients, and geohazard risks. This synthesis provides benchmark references for future project development. Bashir [31] discusses the advantages and risks of different geological structures on CO₂ geological storage, and emphasizes the importance of chemical reactions to long-term safe storage of CO₂. Zhao [32] demonstrated marine CO₂ sequestration potential through global engineering cases but noted insufficient research on coupled mechanisms (e.g., dissolution–mineralization synergies). Zhou [33] covers a comprehensive summary of CO₂-EOR, including the storage screening criteria for sandstone and carbonate reservoirs, CO₂–brine–rock interactions, introduces the numerical simulation methodologies. The analysis provides a reference for the analysis of CO₂ storage in other reservoirs.

The primary focus of this work is to analyze the efficiency and safety of different capture mechanisms, examine alterations in porosity and permeability across various lithologies under CO₂ geological storage conditions, and reveal the relationship between surrounding rock deterioration mechanisms and factors including temperature, pressure, and immersion duration. Furthermore, the application of the mainstream simulation method, COMSOL Multiphysics, in geological storage is analyzed, and discussions are presented addressing the limitations identified within the current research scope.

2. Capture Mechanism in CO₂ Geological Storage

To ensure the secure geological storage of CO₂ and mitigate CO₂ leakage, comprehensive understanding of subsurface trapping mechanisms—including structural, residual, solubility, and mineral trapping—is essential [34], as illustrated in Figure 4.

These trapping mechanisms collectively enable long-term CO₂ sequestration in subsurface reservoirs [36]. Structural and residual trapping can be attributed to physical trapping, where structural trapping primarily restricts the migration of CO₂ within the formation [37]. Residual trapping immobilizes CO₂ through capillary forces within rock pore networks [31]. Solubility and mineral trapping can be attributed to chemical trapping, where solubility trapping primarily involves dissolving CO₂ into formation fluids [38], such as water. Mineral trapping precipitates carbonate minerals through CO₂–rock reactions [39]. Understanding and optimizing these trapping mechanisms can help better implement CO₂ geological sequestration projects to achieve the goal of reducing greenhouse gases [38].

2.1. Structural Trapping

Structural trapping of CO₂, illustrated in Figure 5, occurs when injected CO₂ migrates upward due to buoyancy and becomes confined beneath low-permeability caprocks. This immobilizes the CO₂ plume within subsurface formations—analogous to conventional hydrocarbon reservoirs—constituting the predominant mechanism in geological sequestration. Caprock integrity governs this process, where low-permeability lithologies (e.g., shales) provide optimal containment. However, CO₂ can react with the caprock, and as the reaction time accumulates, it can induce the formation of new fractures and pores in the caprock or accelerate the development of existing pore structures, thereby compromising the caprock’s sealing effect on CO₂. Therefore, it needs to be combined with other trapping methods to prevent CO₂ from leaking into the atmosphere.

Optimal caprock selection is therefore critical for secure CO₂ containment. Low-permeability lithologies (e.g., shale, mudstone) constitute preferred caprocks in geological storage systems [41]. Factors including the caprock-to-reservoir thickness ratio, caprock thickness, and lithology influence caprock permeability [42]. The capillary entry pressure threshold serves as the primary integrity metric. Long-term CO₂ exposure risks fault-mediated leakage through geochemical alteration [43]. Concurrently, the maximum pressure sustained by the caprock governs the maximum feasible injection depth; exceeding this pressure limit can cause caprock fracturing and subsequent CO₂ leakage [44]. Changes in subsurface conditions may induce groundwater leakage, necessitating the installation of monitoring wells within CO₂ storage sites or the monitoring of existing CO₂ injection wells [45]. Furthermore, caprock wettability evolution further impacts containment efficacy: prolonged CO₂–shale interaction can shift wettability from water-wet to CO₂-wet states, degrading sealing capacity [46]. To ensure optimal CO₂ storage, achieving a supercritical carbon dioxide (SC-CO₂) state is essential. This requires careful consideration of injection depth to avoid shallow injection and facilitate the attainment of the supercritical state [47]. Through data analysis and iterative comparative validation, the optimal subsurface storage depth for CO₂ is determined to be approximately 1300 m [48].

2.2. Residual Trapping

Residual trapping denotes the immobilization of CO₂ by capillary forces within the pore structure of rocks [49]. As illustrated in Figure 6, the intricate pore–throat structure of porous media fragments the injected CO₂ into isolated bubbles or droplets, thereby inhibiting further migration. Compared to structural trapping, residual trapping is considered a more secure mechanism [50]. The trapping efficiency is governed by residual CO₂ saturation, which depends on the petrophysical, chemical, and hydrodynamic characteristics of the CO₂–fluid–rock system [51]. Additionally, rock heterogeneity affects residual trapping capacity [52]. Studies have demonstrated that even small-scale (millimeter-level) heterogeneity with high randomness and no distinct pattern can significantly influence large-scale CO₂ migration in geological storage formations.

Investigating the effects of capillary and viscous forces on CO₂ residual trapping in complex porous media under various wettability conditions reveals that the interplay between these forces plays a pivotal role in governing CO₂ migration patterns, residual trapping efficiency, and overall storage capacity [54]. In saline aquifers, heterogeneity enhances CO₂ entrapment: increased capillary-pressure heterogeneity decelerates vertical migration while intensifying localized capillary trapping. Utilizing thicker saline aquifers as caprock can further mitigate CO₂ leakage risks [55]. Experimental studies employing rocks with varying permeabilities demonstrate that low-permeability rocks exhibit the poorest injection performance, while trapping efficiency inversely proportional to permeability [56]. Residual trapping capacity correlates positively with permeability, porosity, and brine density [57]. Organic content enhances CO₂ adsorption, while mineral composition variations alter CO₂–mineral surface interactions, thereby modifying residual trapping [58]. To identify optimal petrophysical parameters for predicting CO₂ residual trapping in sandstones, core flooding experiments under reservoir conditions (nine heterogeneous sandstone samples) indicate that CO₂ residual trapping capacity decreases with increasing porosity but increases with greater heterogeneity [59].

2.3. Dissolution Trapping

Dissolution trapping refers to the process in CO₂ geological storage where CO₂ dissolves into formation water to form carbonic acid, thereby reducing CO₂ mobility. As illustrated in Figure 7, dissolved CO₂ increases brine density, generating density-driven convection that transports CO₂-saturated brine downward. This mechanism effectively restricts vertical CO₂ migration and enhances storage security. When combined with localized capillary trapping, dissolution may reduce potential leakage by >19% However, high-permeability connected streaks can compromise these trapping mechanisms’ leakage mitigation efficacy [60]. The dissolution process triggers a series of chemical reactions, as shown below [61,62]:

$$\begin{array}{c}\mathrm{C}{\mathrm{O}}_2\left(\mathrm{g}\right)+{\mathrm{H}}_2\mathrm{O}={\mathrm{H}}_2\mathrm{C}{\mathrm{O}}_3\end{array}$$

(1)

$$\begin{array}{c}{\mathrm{H}}_2\mathrm{C}{\mathrm{O}}_3={\mathrm{H}}^{+}+\mathrm{H}\mathrm{C}{\mathrm{O}}_3^{-}\end{array}$$

(2)

$$\begin{array}{c}\mathrm{C}{\mathrm{a}}^{\left(2+\right)}+\mathrm{H}\mathrm{C}{\mathrm{O}}_3^{-}=\mathrm{C}\mathrm{a}\mathrm{H}\mathrm{C}{\mathrm{O}}_3^{+}\end{array}$$

(3)

$$\begin{array}{c}\mathrm{H}\mathrm{C}{\mathrm{O}}_3^{-}+\mathrm{C}{\mathrm{a}}^{\left(2+\right)}=\mathrm{C}\mathrm{a}\mathrm{C}{\mathrm{O}}_3\left(\mathrm{s}\right)+{\mathrm{H}}^{+}\end{array}$$

(4)

$$\begin{array}{c}\mathrm{H}\mathrm{C}{\mathrm{O}}_3^{-}+\mathrm{M}{\mathrm{g}}^{\left(2+\right)}=\mathrm{M}\mathrm{g}\mathrm{C}{\mathrm{O}}_3\left(\mathrm{s}\right)+{\mathrm{H}}^{+}\end{array}$$

(5)

$$\begin{array}{c}\mathrm{H}\mathrm{C}{\mathrm{O}}_3^{-}+\mathrm{F}{\mathrm{e}}^{\left(2+\right)}=\mathrm{F}\mathrm{e}\mathrm{C}{\mathrm{O}}_3\left(\mathrm{s}\right)+{\mathrm{H}}^{+}\end{array}$$

(6)

Reservoir heterogeneity and connectivity significantly influence dissolved CO₂ advection–diffusion transport. The dynamic simulation method can be found that the homogeneous and heterogeneous porous media mechanisms are similar in terms of long-term evolution mechanisms [64]. In the layered heterogeneous formation containing low permeability layers, density-driven convection rarely enhances convective mixing, dissolved CO₂ becomes immobilized at low diffusion rates, and leakage risk through faults/fractures is reduced [65]. The maximum dissolution fraction of CO₂ depends on the volume ratio of water to CO₂ in the low-permeability layer in the low-permeability layer. For finer stratigraphic reservoirs, the CO₂ injected within one year is dissolved [66]. CO₂ thermodynamic properties critically govern bubble persistence. Under the experimental scale, CO₂ bubbles disappear for 5.87 h. This longer time prompts the redistribution of CO₂ in porous media, reducing dissolution efficiency and elevating long-term leakage risks [67]. Pressure, formation temperature, and salinity all have an impact on storage efficiency. High pressure has a high carbon fixation efficiency. Temperature has negative and positive effects on CO₂ dissolution capture. Increased temperature will lead to a decrease in CO₂ dissolution efficiency [68]. The salt-containing layer needs to be evaluated before operation. High ionic strength will reduce the dissolution capture efficiency to a certain extent [69]. In addition, wetting properties also have a certain effect on CO₂ dissolution. Under intermediate-wet conditions, small SC-CO₂ clusters localize at pore termini. On the contrary, under strong water- and mixed-wet conditions, the clusters are larger and interconnected, distributed in the center of the pores, resulting in a larger SC-CO₂–water interface area and improving dissolution efficiency [70].

2.4. Mineral Trapping

Injected CO₂ undergoes geochemical reactions with formation brines, through mineral trapping converting into stable carbonate minerals (e.g., calcite [CaCO₃], dolomite [CaMg(CO₃)₂]) [71]. As shown in Figure 8, this process is called mineral capture and is also the basic purpose of CO₂ geological storage [72]. Mineral trapping is widely regarded as the most secure sequestration mechanism. Although mineralization occurs over millennial timescales, its contribution during short injection periods is negligible [50]. By injecting CO₂ into waste oil and gas reservoirs, saltwater layers or coal seams, under the action of temperature, pressure and fluid, CO₂ undergoes geochemical reaction with minerals or ions to form stable carbonate minerals. Compared to structural, residual, and solubility trapping mechanisms, mineral trapping provides irreversible CO₂ sequestration [73].

Mineral trapping predominantly occurs in H₂O-rich aqueous phases through three reaction pathways: (1) CO₂ dissolution: CO₂ partitions into an aqueous phase, forming carbonic acid (pH reduction); (2) mineral dissolution: acidic conditions dissolve silicate minerals, releasing metal cations; (3) carbonate precipitation: as the PH rises, metal ions bind to carbonate ions to form stable carbonate minerals. Key reactions include [37]:

$$\begin{array}{c}{\mathrm{M}}^{\left(2+\right)}\mathrm{C}{\mathrm{O}}_3\left(\mathrm{s}\right)+{\mathrm{H}}^{+}\left(\mathrm{aq}\right)\to {\mathrm{M}}^{\left(2+\right)}\left(\mathrm{aq}\right)+\mathrm{H}\mathrm{C}{\mathrm{O}}_3^{-}\end{array}$$

(7)

$$\begin{array}{c}\mathrm{C}{\mathrm{O}}_2\left(\mathrm{aq}\right)+{\mathrm{M}}^{\left(2+\right)}+{\mathrm{H}}_2\mathrm{O}\to {\mathrm{M}}^{\left(2+\right)}\mathrm{C}{\mathrm{O}}_3\left(\mathrm{s}\right)+2{\mathrm{H}}^{+}\left(\mathrm{aq}\right)\end{array}$$

(8)

Mineral trapping kinetics follow reaction–transport competition theory. Research based on coherent leading-edge propagation theory shows that the mineral capture rate in the front stage of the complete reaction (such as lamina precipitation) is always controlled by transmission (λ < 1), which is proportional to the Darcy flow rate, dissolved carbon concentration gradient, and hydrodynamic diffusion correction coefficient; while in the incomplete leading edge stage, it may be converted to reaction control (λ > 1) at low reaction rates, dependent on propagation distance and precipitation rate [74]. This reveals the significant effect of hydrodynamic diffusion on the propagation velocity of leading edges, overlooked in traditional models. Bello [75] analyzed the mineral capture dynamics within 1000 years after injection of more than 48 million tons of CO₂ in the brackish water layer of siliceous clastic rock. The simulation showed that the initialization stage was controlled by the reservoir temperature and pressure conditions, and the initial reaction between minerals and fluids started; the mineral reaction was active in the peak stage; and the capture efficiency decreased during the decline period due to mineral consumption or insufficient CO₂.

Mineral trapping constitutes the most secure long-term CO₂ sequestration mechanism by permanently converting CO₂ into stable carbonate minerals. Through research, it was found that its efficiency is predominantly controlled by reservoir mineral composition: the abundance of Ca/Mg/Fe-rich silicate and carbonate minerals determines trapping capacity. Pyroclastic reservoirs exhibit significantly higher mineralization potential than siliceous clastic systems. The inorganic carbon and residual CO₂ dissolved under CO₂ saturation conditions can be almost completely converted into mineral carbon within 20 years, with mineral trapping volumes surpassing residual and dissolution mechanisms. Nevertheless, mineral reactions also indirectly affect other capture mechanisms [76]. After CO₂-saturated water is injected into Berea sandstone, fine-particle migration generated by the dissolution of cements such as CaCO₃ and CaMg(CO₃)₂ will block pores, increasing the residual CO₂ saturation by 6–7% and demonstrating how mineral reactions enhance residual trapping via pore-structure modification. Crucially, there is an essential difference between mineral capture (permanent carbon sequestration) and pore effects (short-term retention) caused by mineral reactions [77].

Based on the analysis of the four trapping mechanisms, we conduct a comparative discussion of these mechanisms in terms of storage timescale, storage stability, and primary advantages and disadvantages, as detailed in

Table 3. Different trapping mechanism comparison.

Trapping Mechanisms	Timescale	Stability	Topography	Advantage	Disadvantages
Structural Trapping	Minimum	Minimum	Well-suited for sedimentary basins but remains inapplicable to mountainous terrains or fault-developed zones.	Structural trapping provides a predictable storage capacity and serves as the primary barrier against upward CO2 migration	This mechanism is entirely contingent upon the long-term integrity of the caprock and structural stability, presenting elevated long-term risks. Its viability demands stringent geological conditions and necessitates continuous pressure monitoring to mitigate induced seismicity.
Residual Trapping	Medium	Medium	High-porosity channel sands enhance capillary trapping effectiveness, thus improving storage efficiency, whereas steep mountainous terrains remain inapplicable for this mechanism.	Capillary trapping immobilizes the mobile CO2 phase and markedly reduces its leakage potential, thereby providing a critical contribution to long-term containment in saline aquifers.	The magnitude of capillary trapping is strongly conditioned by the pore structure, wettability, and spatial heterogeneity of the host rock, leading to substantial variability across formations.
Dissolution Trapping	Medium and long term	Higher	Deep-water basins (>800 m) are optimal for CO2 storage, geothermal zones pose elevated vertical migration risks due to thermal convection.	Aqueous-phase dissolution of CO2 eliminates discrete pore-volume occupancy, thereby enhancing effective reservoir storage capacity. Concurrently, it reduces potential leakage volume and pressure, substantially mitigating long-term containment risks.	The dissolution process is kinetically constrained, with rates and extent governed by formation water salinity, temperature, pressure, pH, and reservoir heterogeneity.
Mineral Trapping	Maximum	Maximum	Mineral trapping exhibits high efficiency in divalent cation-rich lithologies such as basalt, whereas quartz-dominated sandstones demonstrate limited effectiveness.	Dissolved CO2 reacts with reservoir minerals to precipitate stable carbonate phases, achieving permanent sequestration; these neo-formed carbonates simultaneously enhance mechanical integrity by reinforcing the pore framework and increasing bulk rock strength.	Mineral-trapping kinetics operate on geological timescales (103–106 yr), rate-limited by silicate reactivity and divalent cation availability. Although carbonate precipitation permanently immobilizes CO2, excessive mineralization may occlude pore throats, degrading porosity and impairing long-term injectivity and storage capacity.

.

3. Mechanism of Surrounding Rock Deterioration Under CO₂

3.1. Strength and Deformation of Surrounding Rock

CO₂ injection alters the physicochemical properties of rocks through stress effects and other processes. Gou Bo [78] experimentally investigated the evolution of in tight carbonate rocks under SC-CO₂ exposure. After immersed in SC-CO₂ for durations exceeding 1 day, the tight carbonates exhibited strength reductions greater than 33% and Young’s modulus degradation exceeding 17%, demonstrating characteristic brittle failure patterns. Furthermore, dissolution reactions between CO₂ and soluble minerals in the rock matrix contribute to mechanical strength reduction. Following 60 days of immersion in CO₂-saturated brine, limestone specimens showed significant deterioration, as shown in Figure 9, with uniaxial compressive strength and elastic modulus decreasing by 79.3% and 72.03%, respectively [79].

The elastic modulus (E = σ/ε), a key parameter in rock mechanics quantifying a rock’s resistance to elastic deformation, exhibits direct correlations with both compressive and tensile strength [80]. Moisture content significantly influences the mechanical properties of rocks. The tri-phase interactions among SC-CO₂, water, and coal rock exhibit maximum reactivity at moisture contents of 65–80%, corresponding to peak damage levels. However, under in situ stress conditions in deep formations, bituminous coal demonstrates an average strength reduction rate of 4.03% [81]. Liang Jie [82] studied the impact of soaking temperature on shale mechanical properties. The results indicate that these properties are inversely related to soaking temperature. When the soaking time reaches 120 h, the weakening effect becomes significant, though its rate decreases. Shale mechanical properties initially decline and then increase with rising confining pressure, reaching a minimum near 12 MPa. SC-CO₂ induces more pronounced alterations than gaseous CO₂. After gaseous CO₂ treatment, the uniaxial compressive strength and elastic modulus of shale decrease by 11.4% and 3.3%, respectively. In contrast, following SC-CO₂ treatment, they drop by 32.9% and 16.8% [83]. During initial SC-CO₂ immersion, strain undergoes rapid nonlinear escalation until stabilizing at equilibrium, with longitudinal strain persistently exceeding transverse strain. Notably, dramatic mechanical changes occur within the critical pressure range [84].

Carbon-storage operations elevate pore pressure within reservoirs, inducing subsurface expansion that propagates pore-pressure diffusion. This process perturbs the in situ stress equilibrium, while permeability predominantly governs displacement distribution. Surface deformation exhibits a positive correlation with fault dip angle but a negative correlation with fault offset distance [85]. Xing [86] emphasized the significant role of creep deformation in long-term rock deformation through creep tests. They also indicated that chemical activity from water-bearing fluids can accelerate creep deformation. Khan [87] investigated the impact of reservoir size and boundary conditions on surface uplift, finding that small-scale reservoirs and closed boundary systems exhibit higher fluid pressure buildup and surface uplift than large-scale reservoirs. This indicates that CO₂ sequestration by injection is safer in large-scale reservoirs. Rahman [88] modeled the Smeaheia potential storage site (Norway), predicting a maximum uplift of 7 cm in central/southern sectors after 50 years of injection, with the caprock uplift reaching 8 cm.

3.2. Porosity and Permeability Evolution of Surrounding Rock

Sandstone is predominantly composed of quartz, feldspar, and carbonate minerals. Carbonate minerals rich in CaCO₃ and CaMg(CO₃)₂ undergo dissolution when exposed to CO₂-charged fluids, However, in the long term, there will be a recrystallization effect, forming stable CaCO₃.

$$\begin{array}{c}\mathrm{C}\mathrm{a}\mathrm{C}{\mathrm{O}}_3+\mathrm{C}{\mathrm{O}}_2+{\mathrm{H}}_2\mathrm{O}\to \mathrm{C}{\mathrm{a}}^{2+}+2\mathrm{H}\mathrm{C}{\mathrm{O}}_3^{-}\end{array}$$

(9)

$$\begin{array}{c}\mathrm{C}\mathrm{a}\mathrm{M}\mathrm{g}{\left({\mathrm{CO}}_3\right)}_2+2\mathrm{C}{\mathrm{O}}_2+2{\mathrm{H}}_2\to \mathrm{C}{\mathrm{a}}^{2+}+\mathrm{M}{\mathrm{g}}^{2+}+4\mathrm{H}\mathrm{C}{\mathrm{O}}_3^{-}\end{array}$$

(10)

$$\begin{array}{c}\mathrm{C}{\mathrm{a}}^{2+}+\mathrm{C}{\mathrm{O}}_3^{2-}\to \mathrm{C}\mathrm{a}\mathrm{C}{\mathrm{O}}_3\downarrow \end{array}$$

(11)

Dissolution and precipitation significantly alter porosity and permeability. CO₂ injection modifies the porosity and permeability of reservoir rocks [89]. Figure 10 demonstrates that permeability and porosity changes at different conditions. Panels (a, b) (tight sandstone): we can see that when injection pressure increased from 15 MPa to 25 MPa, porosity and permeability rose by 3.2% and 9.9%, respectively. Conversely, at constant pressure (15 MPa), raising the temperature from 44 °C to 64 °C reduced the porosity increment from 3.0% to 1.7%,while permeability exhibited an initial decrease followed by an increase, resulting in an overall increase ranging from 20.3% to 35% [90]. Panel (c) (tight carbonate): indicated with increasing exposure duration, both the porosity and permeability of tight carbonate rocks exhibit increasing trends after CO₂ soaking. In contrast, according to (d), the permeability of shale is inversely related to soaking pressure [91]. Under reservoir conditions, CO₂–water–rock interactions generate secondary minerals and inorganic precipitates that occlude pore throats, impairing formation permeability. During initial CO₂–water flooding, core permeability increased by 90.54% alongside a 2.13% porosity gain due to mineral dissolution. However, inorganic precipitation ultimately dominated during later reaction stages. Consequently, both the core’s permeability and porosity exhibit linear relationships with reaction time [92]. Permeability exhibits an inverse correlation with confining pressure. When confining pressure increased from 20 MPa to 40 MPa during SC-CO₂ injection, permeability underwent nonlinear degradation. After 240 h of exposure, anthracite coal permeability decreased by 72–85% [93].

Clay content in rock samples significantly impacts permeability, when clay content exceeds 7.5%, permeability decreases with increasing reaction time, with higher clay content inducing more substantial permeability reduction—enhancing CO₂ geological storage integrity [94]. Yu Zhichao [95] quantified permeability and porosity evolution under reservoir conditions using core-flooding experiments. Post-experimental analysis revealed 4% permeability reduction and 2.5% porosity decline, attributed to pore-throat occlusion by neoformed kaolinite and mobilized clay particles derived from carbonate dissolution. Compared to conventional reservoirs, shales and mudstones exhibit intrinsically low porosity and permeability. Calcite reprecipitation and iron dolomite precipitation further reduce pore space and flow capacity, whereas clay mineral dissolution enhances both parameters. Dai Xuguang [96] investigated dissolution–precipitation effects on shale pore structure (Longmaxi Formation, Sichuan Basin). Mineral dissolution and secondary precipitation alternately affect shale pore structure. Dissolution enlarges pores and increase adsorption, while precipitation primarily occurs in the reaction’s late stage or long term, causing minimal pore-volume alteration. Both processes increase pore-structure complexity. The dissolution effect of SC-CO₂ leads to the dissolution of clay minerals in shale, creating a significant number of micro-pores on the surface, improving permeability. However, concurrent adsorption capacity enhancement reduces original pore volume, exerting counteracting effects [97]. Jia [98] studied the impact of CO₂ on shale through experiments. After soaking in CO₂-saturated water for 7 days, the shale’s permeability rose by about 65%, resulted from carbonate mineral dissolution enlarging existing pores or creating new flow pathways.

3.3. Caprock Integrity

Caprock integrity is a critical metric for CO₂ geological storage safety. Micropores within caprocks generate high capillary pressures that resist upward CO₂ migration. However, once the breakthrough pressure is exceeded, CO₂ can rapidly escape through pre-existing or newly formed fractures. Notably, such leakage volumes are typically small and do not compromise the storage capacity at the injection point [99]. CO₂ injection poses risks to caprock integrity through multiple mechanisms: capillary leakage, hydraulic fracturing, and reduction in effective stress [100]. Capillary pressure exhibits a positive correlation with injection pressure. To ensure caprock integrity, the maximum injection pressure must be constrained below the minimum principal stress [101]. When the water pressure in the caprock exceeds the minimum principal stress, hydraulic fracturing occurs. In low-permeability rock layers, fluid diffusion is slow, so it takes longer to reach the caprock breakdown pressure. Consequently, preventing vertical hydraulic fracturing and ensuring caprock integrity are crucial for practical CO₂ sequestration projects [102]. During the hydraulic fracturing process, increased formation pressure can induce seismicity and compromise caprock stability. The inherent anisotropy of shale caprocks and complex natural fracture networks further complicate the prediction of fracture propagation pathways, resulting in challenges in controlling caprock integrity [103].

CO₂ injection can cause fault reactivation, and the fault failure criterion can be assessed using the Mohr–Coulomb equation [104]:

$$\begin{array}{c}{\mathsf{\sigma }}_{\mathrm{n}}={\displaystyle \frac{\left({\mathsf{\sigma }}_1^{\prime }+{\mathsf{\sigma }}_3^{\prime }\right)}{2}}+{\displaystyle \frac{\left({\mathsf{\sigma }}_1-{\mathsf{\sigma }}_3\right)}{2}}\mathrm{c}\mathrm{o}\mathrm{s}2\mathrm{\Phi }\end{array}$$

(12)

$$\begin{array}{c}\tau =-{\displaystyle \frac{\left({\mathsf{\sigma }}_1-{\mathsf{\sigma }}_3\right)}{2}}\sin 2\mathrm{\Phi }\end{array}$$

(13)

where τ is the shear stress on the shear plane, σ denotes the effective normal stress, Φ is the angle of internal friction of the rock, σ₁ is the maximum principal stress, σ₃ is the minimum principal stress, σ₁′ is the maximum effective principal stress, and σ₃′ is the minimum effective principal stress. The Mohr–Coulomb criterion is an indispensable fundamental tool for assessing fault stability in CO₂ geological storage and serves as a core component in numerous simulation software. It enables the quantitative assessment of the critical injection pressure and the factor of safety. However, this criterion simplifies the complex behavior of faults and neglects the weakening effect on faults induced by the chemical reactions between CO₂, water, and rock triggered by CO₂ injection. Furthermore, while the Mohr–Coulomb criterion primarily describes short-term strength, it does not adequately account for strength variations over the long-term containment period.

Hydraulic fracturing has a significant impact on the activation of faults. Stress changes and pore-pressure fluctuations during fracturing may trigger fault reactivation and induce seismicity [105]. The injection of CO₂ elevates fluid pressure, resulting in ground uplift, while shear slip along caprock fractures can lead to CO₂ leakage and microseismicity. Nath [106] employed a three-dimensional digital imaging to investigate caprock deformation and failure mechanisms in reservoirs, which offered a broader testing range and enhanced accuracy, when samples present significant heterogeneity, the shale damage varied over time.

CO₂ intrusion compromises caprock compressive strength, weakening sealing integrity. Coupled with numerical simulations, it was found that following the cessation of CO₂ injection, the pressure within the caprock exhibited a decline over a period of 30 to 100 years compared to the injection phase. Due to the high concentration of CO₂ within the reservoir, the pressure cannot immediately stabilize to new levels, resulting in the continuous occurrence of CO₂–water–rock reactions. Consequently, dynamic changes in caprock basal physical properties gradually stabilize compared to the injection phase [107]. Guo Bing [108] investigated caprock sealing evolution during CO₂ storage using Jungar Basin’s (Xinjiang) Ziniquanzi mudstone. Through modeling, it was revealed that under the millennium, the maximum intrusion distance of gaseous and dissolved CO₂ in homogeneous and heterogeneous caprocks differed, measuring 43.5 m and 48 m, and 45 m and 50 m, respectively, and there had significant changes in porosity occurred at distances of 25 m and 46 m from the bottom of the homogeneous and heterogeneous caprocks, respectively. Tian Hailong [109] utilized TOUGHREACT simulations to demonstrate that mineral composition variations alter caprock sealing performance, and reservoir initial gas saturation critically influences seal efficacy—low saturation weakens capillary sealing capacity, while high saturation enhances it.

4. Numerical Simulation and Monitoring

4.1. Numerical Simulation

COMSOL Multiphysics enables multiphysics coupling for analyzing mineral dissolution and fracture development during CO₂ geological sequestration through cross-physical field interactions. Li [110] developed a phase field-based hydro-mechanical coupling model to simulate pore-scale reactive transport. By integrating the phase-field module in COMSOL with the Heaviside function, they discovered distinct regions of mineral dissolution under varying transport conditions. In cases dominated by convection, particle dissolution occurs almost simultaneously in both upstream and downstream regions, and diffusion-dominated conditions localize dissolution within upstream porous media zones. By implementing Java to integrate COMSOL and PhreeqC, geochemical reaction mechanisms at the pore scale can be studied [111], which is applicable to CO₂ geological sequestration, enabling the analysis of changes in mineral components and diagenetic reactions within the caprock system.

Wei [112] developed a fully coupled thermal–hydraulic–mechanical model simulating fault reactivation and CO₂ plume migration post-injection, the findings of which indicated that boundary conditions significantly affect the safety of CO₂ sequestration. As shown in Figure 11, under open-boundary conditions, the lateral migration of CO₂ does not trigger fault activation, whereas closed boundaries induce pressure-driven fault reactivation. This reactivation enables upward CO₂ migration along fault planes, elevating leakage risks. Further investigation into fault-activation mechanisms was conducted by Zhang [113], who developed a hydraulic–mechanical model to explore the reactivation mechanisms during the early stage of CO₂ injection. They indicated that the high-pressure disturbance generated near the injection well has minimal impact on distant faults, suggesting a relatively low seismic risk. However, increasing the injection rate raises the risk of fault activation.

Zheng [114] established a fully coupled thermal–hydraulic–damage model in COMSOL incorporating rock heterogeneity. The results demonstrate that thermal stress–pore-pressure interactions generate tensile stresses while thermally induced quenching reduces reservoir rock tensile strength. The distribution pattern of natural fractures significantly affects the propagation of hydraulic fractures, leading to increased complexity in hydraulic fracturing. Gao [115] developed a 1D + 3D wellbore-coupled 3D reservoir model to study the impact of CO₂ thermophysical properties and phase behavior on geological sequestration. Low-temperature CO₂ injection progressively increases near-wellbore porosity and permeability, generating high-pressure gradients with thermophysical alterations confined within the reservoir. Pavan [116] simulated supercritical SC-CO₂ sequestration in heterogeneous saline aquifers using a 2D numerical model. In high-permeability aquifers, the maximum length of the CO₂ plume can reach 1010 m (as shown in Figure 12, Case ii (b)). In low-permeability scenarios, aquifers with normally distributed porosity can achieve an effective CO₂ sequestration efficiency of up to 0.95.

Commercial simulation tools (e.g., TOUGHREACT) enable probabilistic modeling of CO₂ geological sequestration under data uncertainty, supporting forward modeling, data synthesis, and velocity inversion. Zhang [117] employed the FLAC3D-TOUGHREACT simulator to analyze multiphase reaction mechanisms in CO₂ geological sequestration and the changes in formation pressure post-CO₂ injection, noting that CO₂ injection raises formation pressure while concurrently causing a temperature drop of 0.5–2 °C; water flooding has a minor effect on formation temperature with a change of approximately 0.01 °C. Cui [118] compared porosity prediction accuracy across several algorithms, including Random Forests, BP Neural Networks, Support Vector Machines, and XGBoost, demonstrating Random Forest algorithm had significant advantages in predicting the porosity of mudstone shale, addressing the challenge of incomplete porosity distribution due to the inability to obtain continuous core samples.

4.2. Monitoring

Leakage constitutes the primary safety risk in CO₂ geological sequestration, where structural integrity determines overall containment security. Comprehensive system monitoring is essential. As illustrated in Figure 13, when the reservoir and caprock become damaged and create connections to the external environment, or when the injection well experiences failure, it can lead to the failure of the entire sequestration system. Therefore, continuous monitoring and early warning systems for the entire sequestration system are necessary. Shchipanov [119] developed an integrated reservoir characterization technology combining pressure transient analysis (PTA) and rapid simulation, which used real-time data of downhole pressure gauge, for early detection of CO₂ leakage. The injection well consists of an inner steel pipe and an outer cement casing, which, due to prolonged exposure to CO₂, may lead to changes in the properties of cement and steel. Loizzo [120] laboratory tests revealed cement carbonation reducing sealing integrity, steel corrosion microcrack formation, and microannuli development at casing–cement interfaces, creating potential CO₂ migration pathways.

During CO₂ injection, the properties of reservoir rocks may change, allowing for the use of geophysical methods to compare pre- and post-injection data for monitoring purposes, Using the Ketzin (Germany) project as an example, vertical electrical resistivity tomography, fiber-optic distributed temperature sensing, and downhole pressure measurements emphasized a smart casing technology that monitors underground fluid flow by measuring changes in electrical resistivity. As shown in Figure 14, it was observed that the electrical resistivity of rocks correlates positively with the saturation of CO₂ gas in pores over different injection periods [122]. Due to extraction being restricted over large parts of the reservoir, spatial resolution is inherently limited; simultaneously, seismic monitoring technology provides extensive spatial coverage.

Pore-pressure changes induced by CO₂ injection constitute the dominant triggering mechanism for seismic events. Pressure exceeding critical thresholds may reactivate faults or fracture rock masses, potentially generating low-magnitude earthquakes. Current monitoring relies primarily on reflection seismology, wherein geophone arrays record reflected energy signals. Processed data yield high-resolution subsurface models while simultaneously enabling fracture characterization [123]. Conductivity monitoring is similar to the seismic monitoring method; during CO₂ injection, the electrical conductivity of the entire rock will change. By analyzing the conductivity, variations in CO₂ concentration and displacement direction can be assessed [124]. Rippe [125] integrated seismic full-waveform inversion with electrical conductivity imaging. This combination addresses single-method limitations, thus improving monitoring accuracy for CO₂ injection.

Two- and three-dimensional physical models are extensively employed in CO₂ geological sequestration research. Although three-dimensional models provide superior reservoir imaging, their computational and financial costs exceed those of two-dimensional alternatives. Machine learning techniques can detect dynamic changes in underground CO₂ plumes to prevent potential leaks. Zhou [126] applied machine learning methodologies to directly infer geological changes from seismic data, establishing an explicit mapping between seismic attributes and CO₂ leakage signatures. By considering the temporal and spatial characteristics of seismic data and incorporating convolutional neural networks, a new network architecture was developed. This model effectively generates useful features by addressing the spatial–temporal characteristics of the seismic data, integrating them with LSTM network structures. The specific workflow is illustrated in Figure 15, utilizing temporal sequence information to enhance monitoring precision. Additionally, Chen [127] developed a reduced-order model based on multivariate adaptive regression splines and developed a filtering-based data assimilation program, proposing a monitoring design workflow based on machine learning and uncertainty quantification, effectively assessing CO₂ leakage risk indicators under different monitoring designs.

Artificial intelligence (AI) demonstrates significantly superior capabilities in data processing compared to traditional methods, enabling effective reduction in labor costs. AI can accurately identify signals imperceptible to the human eye, and based on historical data, effectively predict high-risk zones such as fault reactivation zones and weak caprock formations. However, due to the scarcity of large-scale CO₂ geological storage projects, substantial volumes of real leakage data are difficult to obtain, restricting model training and resulting in insufficient generalization capability. This necessitates the integration of multimodal data, though multisource data fusion presents significant challenges. Furthermore, training methodologies based on a single lithology lack universal adaptability and are prone to failure when applied to other reservoir types. Dynamic perception capabilities remain inadequate, preventing timely responses to geological events. High reliance on sensors, requiring dense deployment, leads to prohibitively high monitoring costs.

5. Summary and Conclusions

This article systematically reviews the mechanisms of SC-CO₂ geological sequestration, changes in mineral components, porosity, and permeability of caprock after CO₂ injection, surface deformation, and seismic activity caused by fault activation, as well as the numerical simulation and monitoring of CO₂ geological sequestration. Some shortcomings remain in the capture mechanisms, degradation mechanisms, and monitoring aspects:

(1)

We systematically review the four mechanisms of CO₂ geological storage, analyzing their respective principles, influencing factors, and applicable conditions. Discussions are extended to the coupling effects between these mechanisms, including the impact of mineral reactions on residual trapping. Future research priorities are proposed for each capture mechanism. For structural trapping, subsequent research should strengthen precise monitoring of the direction and migration velocity of CO₂. For residual trapping, continuous attention must be paid to subsurface pressure changes during the injection process to avoid excessive pressure that could generate new fractures and trigger gas remobilization. Research on the primary factors influencing CO₂ solubility and analysis of dissolution efficiency under diverse geological conditions are essential to effectively assess CO₂ storage capacity. Mineral trapping is intrinsically linked to the mineral composition of the rock. As rocks rich in carbonate minerals exhibit enhanced reactivity with CO₂, lithological characterization of the formation is crucial during the site selection process.

(2)

The injection of SC-CO₂ can create cooling zones within the formation, leading to non-isothermal effects that may alter the stability of faults distant from the cooling area. The thermal effects induced by this temperature difference can impact the efficiency and safety of CO₂ geological sequestration. Significant temperature disparities may damage caprock and activate faults, providing pathways for CO₂ leakage. However, the rock response mechanisms under thermo-hydro-mechanical–chemical (THMC) multiphysics coupling remain poorly understood. This is particularly true regarding the impact of non-isothermal effects induced by temperature gradients on fault stability. Consequently, it is imperative to establish a comprehensive understanding of these rock response mechanisms under coupled THMC conditions, with specific emphasis on how temperature-gradient-driven non-isothermal phenomena influence fault stability.

(3)

Formation parameters exhibit uncertainty; initial data obtained through logging may not adequately represent the complex actual geological conditions. In numerical simulations, parameters such as permeability and porosity are predominantly derived from laboratory measurements or localized well logs. This approach fails to effectively characterize reservoir-scale heterogeneity. Consequently, strengthening geological exploration is particularly important. Utilizing geostatistical methods to analyze logging and seismic data can help represent the distribution of formation parameters more accurately, thus establishing a more realistic numerical model.

(4)

Caprock exhibits diversity, such as anticlines, planar structures, etc. Current research lacks depth regarding the capture mechanisms, migration directions, and leakage risks of CO₂ under different caprock configurations. It is essential to establish an integrity assessment model considering caprock morphology factors to evaluate CO₂ plume migration and leakage risks more accurately. Moreover, due to the long timescale of geological sequestration, the lack of long-term experimental data supporting caprock integrity creates a need to emphasize the interactions of temperature, pressure, and chemical reactions during numerical simulations to improve the modeling capacity for CO₂ diffusion, flow, and fracture leakage processes.

(5)

Current monitoring techniques still exhibit limitations. Methods such as seismic and electrical resistivity face inherent trade-offs between spatial resolution and temporal continuity, and a unified multi-scale monitoring framework is lacking. Furthermore, machine learning models are predominantly trained on site-specific data, lacking cross-regional and cross-lithological validation, which compromises their generalization capability. Consequently, future efforts should focus on integrating multi-source data including seismic, electrical resistivity, pressure, and temperature to develop AI-powered monitoring models with robust spatiotemporal generalization capabilities.

This review establishes a unified framework encompassing the critical issues throughout the entire process of geological CO₂ storage, structured along the mainline of trapping mechanisms–degradation characteristics–simulation methods–monitoring technologies. It integrates the latest experimental and simulation findings concerning structural, residual, solubility, and mineral-trapping mechanisms, elucidating the dynamic between multiple mechanisms. This provides a theoretical foundation for assessing storage potential.

By synthesizing methodologies from rock mechanics, geochemistry, and multi-physics coupling simulations, the review identifies the dominant factors controlling caprock integrity failure, thereby providing a basis for evaluating the integrity of the reservoir–caprock system. Furthermore, it proposes a parameter updating strategy termed “Experimental Dat-Statistical Inversion-Multi-field Coupling”. This integrated strategy significantly reduces prediction bias inherent in traditional models due to geological heterogeneity and parameter uncertainty.

To meet practical requirements, it is essential to form an interdisciplinary research team that integrates resources from geology, geophysics, geochemistry, fluid mechanics, rock mechanics, and environmental science. This team should develop a comprehensive risk management and decision support platform capable of continuous risk assessment, prediction and early warning, and decision optimization throughout the CO₂ geological sequestration project, providing a scientific basis and intelligent tools for engineering implementation and management, ultimately enhancing project safety and success rates.