Geomechanics of Geological Carbon Sequestration

Abstract

Geological Carbon Sequestration (GCS) is an effective way to fight against global warming by capturing and injecting CO2 into geological formations to ensure permanent storage as well as to prevent the environmental and health threats posed by carbon dioxide emissions. Security has been a key factor in the social acceptance of this technology, besides the issues related to economics. From a scientific point of view, the safety issues during CO2 injection and long-term storage are highly related to geomechanics. This chapter provides a basic knowledge of the geomechanical issues involved in the GCS process to increase the understanding of safety issues and to improve the social acceptance of the technology among researchers and those interested in the technology.

1. Introduction

To date, the application of GCS on a commercial scale is considered to be an effective solution for reducing the greenhouse effect [1]. GCS projects are carried out in highly permeable, porous formations at a certain depth, and CO₂ is typically injected in a supercritical state. It is necessary to ensure that the CO₂ injected into the subsurface does not or rarely leak within a very long time (at least 1000 years) for large-scale applications and public acceptance [2, 3, 4, 5, 6]. The types of CO₂ leaks are classified as physical and chemical and the essence of these is the geomechanical issues during CO₂ injection and storage, such as excessive stress changes, fault activation, damage to wellbore integrity, and caprock failure due to continuous injection and long-term storage [7, 8, 9, 10, 11, 12]. This chapter introduces the geomechanical issues involved in the GCS process from the perspectives of the CO₂ trapping mechanism, in-situ stress changes, caprock performance, wellbore integrity, and induced seismicity.

2. Trapping mechanisms

In recent years, an increasing number of studies have focused on the short- and long-term effects of CO₂ injection into the subsurface. In most projects, CO₂ is injected in a supercritical state which can be stored in a gaseous, liquid, or supercritical state depending on the formation conditions. At the initial stage of injection, CO₂ will move toward the caprock layer due to the temperature-pressure conditions and density difference, and will eventually be blocked by the caprock layer. Then, the CO₂ can be captured as residual gas when groundwater intrusion occurs during the movement. In addition, CO₂ can be dissolved in groundwater and chemical reactions can occur by contact with rocks, which will contribute to CO₂ capture. Therefore, there are four trapping mechanisms for CO₂ in the storage process, that is, stratigraphic trapping, residual trapping, solubility trapping, and mineral trapping. These mechanisms are activated at different periods of the sequestration, as shown in Figure 1. Stratigraphic trapping is in charge of the initial CO₂ storage. Residual trapping and dissolved trapping play an important role in the transport of CO₂. Mineral trapping is formed when the CO₂ diffuses in the formation and contacts the rock. At this time, CO₂ is in the most stable state and the risk of leakage is minimized [14, 15, 16, 17, 18].

Figure 1.

Relative importance of trapping mechanisms with time [13].

2.1 Stratigraphic trapping

The stratigraphic trapping mechanism is determined by geological structure [19]. A complex geological structure is formed during the deposition of the formation, and the locations with high and low permeability determine the fluid flow within the formation. The CO₂ injected into the formation will rise or move laterally until reaching a low permeable or impermeable caprock because the density of CO₂ is less than that of the fluid formation. CO₂ will be confined below the caprock in a supercritical, liquid, or gaseous state. Physical traps for storing CO₂ are formed by low-permeability formations or structures. The typical structural trap includes an anticline or a sealed fault, as shown in Figure 2.

Figure 2.

Typical structural traps (reproduced from [20]).

2.2 Residual trapping

Residual trapping is a phenomenon in which CO₂ is trapped in the pores of rocks by capillary force. While the CO₂ is injected, it will enter the rock pore space and replace the original fluid. The difference in density between groundwater and CO₂ causes an upward. Then, the groundwater re-enters the rock pore space and the wetting phase (groundwater) will replace part of the weak wetting phase (CO₂). The replacement of CO₂ by groundwater leads to a significant reduction in the percentage of CO₂ in the rock pores, which are eventually trapped in the small pores, as shown in Figure 3. Thus, the isolated CO₂ is trapped as a stable phase by a trapping mechanism called residual trapping or capillary trapping [15, 21].

Figure 3.

Schematic diagram of residual trapping (reproduced from [20]).

2.3 Solubility trapping

Solubility trapping is the dissolution of CO₂ in the formation fluid to achieve CO₂ storage. After injection, CO₂ is dissolved in the fluid formation until reaching saturation, due to the interaction of CO₂, groundwater, and hydrocarbons. The density difference between the fluid formation and CO₂ causes the CO₂ to migrate upward to contact more water formation that is not saturated. Meanwhile, CO₂ dissolved in the groundwater will slightly increase its density. Both of these phenomena increase the exchange of CO₂ and groundwater and accelerate solubility trapping. The solubility of CO₂ depends on the temperature, pressure, and saturation of the formation water [22].

2.4 Mineral trapping

Mineral trapping is a long-term trapping mechanism that involves contact and reaction with stratigraphic minerals and organic substances after CO₂ injection to form a stable mineral phase, resulting in long-term storage of CO₂. For example, the forming of carbonate minerals reduces the porosity and permeability of the rock and enhances the stability and integrity of the reservoir over time. The reaction rate of formation minerals with CO₂ depends on temperature, pressure, pH, and the concentration of other substances. It is noted that the forming of carbonate mineralization is a very slow process, as the reaction rates are usually very low, and therefore mineral trapping will only become important on geological time scales [23].

3. Stress response

The geomechanical issues in the GCS process are all driven by changes in the formation of pressure and ground stress. Therefore, it is important to first clarify the characteristics of the stress response in the formation for investigating the geomechanical issues.

3.1 Effective stress and stress path

3.1.1 Effective stress

The mechanical response of the rock is the result of the combination of pore pressure and in-situ stress. Terzaghi (1996) proposed the effective stress principle for describing the mechanical response of porous media. Effective stress is defined as the stress applied on the porous medium or the total stress minus the product of the pore pressure (fluid pressure) and the effective stress coefficient. In one-dimensional conditions it can be expressed as follows [24, 25]:

$${\sigma }^{\text{'}}=\sigma -\alpha P_p$$E1

where ${\sigma }^{\text{'}}$ is the effective stress; $\sigma$ is the total stress; $\alpha$ is the effective stress coefficient; $P_p$ is the pore pressure.

The three-dimensional condition is expressed as:

$${\sigma }_{\mathit{ij}}^{\text{'}}={\sigma }_{\mathit{ij}}-\alpha P_p{\delta }_{\mathit{ij}}$$E2

where ${\sigma }_{\mathit{ij}}^{\text{'}}$ is the index notation of the effective stress tensor; ${\sigma }_{\mathit{ij}}$ is the index notation of the total stress tensor; ${\delta }_{\mathit{ij}}$ is Kronecker’s delta, when$i=j,{\delta }_{\mathit{ij}}=1;i\ne j,{\delta }_{\mathit{ij}}=0$.

The effective stress coefficient, also called the Biot coefficient, can be calculated by the following equation.

$$\alpha =1-\frac{K_{\mathit{dry}}}{K_m}$$E3

where $K_{\mathit{dry}}$ is the bulk modulus of the dry porous rock; $K_m$ is the bulk modulus of the matrix mineral in the rock. In Terzaghi’s effective stress law $\alpha$ =1.

3.1.2 Stress path

The stress path, also known as the “stress history in the plane of maximum obliquity” is a common concept in geotechnics and rock mechanics. It refers to the trajectory of the stress path and stress history in the stress plane of stress space of a point in the core under the action of external forces, and is generally divided into effective stress path (ESP) and total stress path (TSP).

To understand the stress paths, consider a typical triaxial stress experiment in a core (Figure 4a). At any time, the stress state in the core can be represented by a Mohr circle (Figure 4b). It should be noted that during the triaxial experiments, the pore pressure can be neglected so that the total stress is equal to the effective stress. In triaxial compression tests, the maximum principal stress (${\sigma }_1$) is applied along the axis of the cylindrical rock specimen, and the minimum principal stresses (${\sigma }_2$ and ${\sigma }_3$) are applied on the lateral surface of the specimen. It is necessary to supplement the Mohr-Coulomb theory. Shear damage occurs at that point when the shear stress is equal to the shear strength of the material in any plane. The shear stress (shear strength) on the damaged plane depends on the normal stress on the shear plane and the properties of the rock and is a function of the normal stress on the shear plane [27, 28, 29].

Figure 4.

(a) Triaxial stress experiment schematic; (b) laboratory stress path schematic; (c) schematic of total stress circle and effective stress circle (reproduced from [26]).

The coordinates on the Mohr circle when considering the effective normal and shear stresses in the plane at an angle of 45^o to the principal plane are calculated by [30, 31, 32]:

$$\text{The effective normal stress}{p}^{\text{'}}=\frac{{\sigma }_1^{\text{'}}+{\sigma }_3^{\text{'}}}{2}$$E4

$$\text{The effective shear stress}{q}^{\text{'}}=\frac{{\sigma }_1^{\text{'}}-{\sigma }_3^{\text{'}}}{2}$$E5

where ${\sigma }_1^{\text{'}}$ is the effective maximum principal stress; ${\sigma }_3^{\text{'}}$ is the effective minimum principal stress.

Connecting the points corresponding to coordinates $p^{\text{'}}$ and $q^{\text{'}}$ on each Mohr circle, as shown in line AB, is the stress path. In the formation conditions, the in-situ stress generally refers to the total stress. The pore pressure separates the effective stress circle from the total stress circle, as shown in Figure 4c, but they have the same diameter. In GCS engineering, shear failure, fault activation, and caprock failure can be determined by plotting the effective stress Mohr circle and effective stress path at a point in the formation [32].

3.1.3 Stress path coefficient

Effective stress is the key parameter for determining whether or not damage will occur in the rock. The injection of CO₂ will lead to an increase in the pore pressure. According to Eq. (1), the effective stress decreases, and the response to the Mohr circle is shifted to the left, as shown in Figure 5. Assuming constant total stress, the Mohr circle simply translates to the left until it intersects the failure envelope, resulting in shear damage. However, the increase in pore pressure leads to the expansion of the formation, which further leads to the change in total stress. The ratio of the variation of the total stress and the variation of the pore pressure is the stress path coefficient [33].

Figure 5.

Trend of Mohr circle with increasing pore pressure at constant total stress.

$${\gamma }_v=\frac{\mathrm{\Delta }{\sigma }_v}{\mathrm{\Delta }{p}_p},{\gamma }_h=\frac{\mathrm{\Delta }{\sigma }_h}{\mathrm{\Delta }{p}_p}$$E6

where ${\gamma }_v$ is the vertical stress path coefficient; ${\gamma }_h$ is the horizontal stress path coefficient; $\mathrm{\Delta }{\sigma }_v$ is the vertical stress variation value; $\mathrm{\Delta }{\sigma }_h$ is the horizontal stress variation value; $\mathrm{\Delta }{p}_p$ is the pore pressure variation value.

3.2 Effective stress variation law

During field construction, once fluid injection begins, the reservoir stress will change with the rapid propagation of fluid pressure in the injection zone, causing the change in the reservoir stress field. In this case, the calculation of the effective stress requires consideration of the stress path coefficients. In a formation with a wide lateral distribution, the horizontal stress path coefficient can be calculated as [33, 34]:

$${\gamma }_h=\frac{\mathrm{\Delta }{\sigma }_h}{\mathrm{\Delta }{p}_p}=\alpha \frac{1-2\mu }{1-\mu }$$E7

where $\mu$ is the Poisson’s ratio.

The horizontal stress path coefficient is less than 1 because is less than 1. However, the vertical total stress can be considered to remain constant since the vertical formation expansion is not constrained, that is, the vertical stress path coefficient is equal to 0. It means that the horizontal total stress will change, while the vertical total stress remains constant. At this time the maximum and minimum effective stress change differently, Mohr’s circle will not only move but also the diameter will change, as shown in Figure 6.

Figure 6.

Mohr circle variation considering stress path coefficients.

4. Caprock integrity

The effective and shear stress in the formation continues to change during the injection of CO₂. The tensile or shear damage will occur when the effective or shear stress reaches a certain critical point, forming fractures and providing leakage channels for CO₂.

4.1 Failure type

Two types of failures can occur during the continuous injection process, that is, tensile and shear failure. The effective stress continues to decrease to 0 as the pore pressure increases during the continuous injection of CO₂. Then it grows in the opposite direction and changes from compressive stress to tensile stress. Tensile failure will occur when the tensile stress exceeds the tensile strength of the rock. The principle is the same as that of hydraulic fracturing. Therefore, it is necessary to calculate the fracture pressure of the formation before injection, and then inject CO₂ at a pressure lower than the fracture pressure. Typical fracture pressure calculation methods can be found in hydraulic fracturing-related studies. The shear failure will occur when the shear stress at a point reaches its shear strength. The Mohr-Coulomb criterion is used to determine whether a shear failure has occurred in the rock.

The maturity of hydraulic fracturing technology has made the determination of tensile failure easier. And the existence of stress path coefficients leads to a more complicated determination of shear damage. More importantly, the shear effect of injecting CO₂ varies in different fault regimes [35, 36, 37, 38, 39].

4.2 Normal fault regime

In a normal fault regime formation, as shown in Figure 7a, the maximum principal stress is the vertical (overburden) stress and the minimum principal stress is the minimum horizontal principal stress. In this stress regime, the initial Mohr circle of the formation is shown in Figure 7b and the variation of the Mohr circle with the injection of CO₂ is shown in Figure 7c. The variation of the maximum effective stress is greater as compared to that of the minimum effective stress when the pore pressure increases. The phenomenon that can be observed is that the radius of the Mohr circle will decrease and move slightly to the left, which implies the reduction of the shear stress. Therefore, at the early stage of CO₂ injection, the Mohr circle will move away from the damage envelope and the stability of the caprock and fault will increase to some extent. The shear stress decreases continuously with the injection of CO₂ until the maximum and minimum effective stresses are equal, and then the Mohr circle reverses [40, 41].

Figure 7.

(a) Normal fault regime; (b) initial Mohr circle; (c) schematic of Mohr circle variation.

4.3 Strike-slip fault regime

In the strike-slip fault regime as shown in Figure 8a, both the maximum and minimum principal stresses are in the horizontal direction. In this regime, the initial Mohr circle of the formation is shown in Figure 8b. The maximum and minimum effective stresses have the same variation and the diameter of the Mohr circle is constant when CO₂ is injected into the strike-slip regime formation because the horizontal stress path coefficients are the same. However, the Mohr circle rapidly moves to the left and closer to the damage envelope due to the reduction of the effective stress, causing the formation to become unstable, as shown in Figure 8c [42].

Figure 8.

(a) Strike-slip fault regime; (b) initial Mohr circle; (c) schematic of Mohr circle variation.

4.4 Thrust fault regime

In a thrust fault regime, as shown in Figure 9a, the maximum principal stress is the horizontal stress, while the minimum principal stress is the vertical stress. In this regime, the initial Mohr circle of the formation is shown in Figure 9b. The maximum effective stress changes less than the minimum effective stress when CO₂ is injected. Therefore, the radius of the Mohr circle increases and rapidly moves to the left during the injection process, and the shear stress increases (Figure 9c). The distance between the Mohr circle and the damage envelope will decrease rapidly, and then the caprock stability will decrease. Therefore, according to the trend of the Mohr circle, the reservoir and caprock will be more stable in the normal fault regime than in the thrust regime [40, 43].

Figure 9.

(a) Thrust fault regime; (b) initial Mohr circle; (c) schematic of Mohr circle variation.

In summary, the changes in Mohr circles are very different when CO₂ is injected into formations with different stress regimes. Generally, the formation is most stable in the normal fault regime, followed by the strike-slip regime, and the least stable is the thrust regime.

5. Well integrity

Well integrity is generally defined as the ability of a well to produce or inject a fluid while preventing harmful fluid leaks to reduce the risk of uncontrolled leakage of fluids formation throughout the life of the well. Well integrity is key to the success of geologic carbon sequestration and CO₂ enhanced recovery operations. Modern wells are designed with multiple barriers to create a controlled injection or production pathway and to isolate the fluid in the formation along with its depth. Wells will be impacted by physical, chemical, and mechanical stresses, which can reduce the effectiveness of the barrier and ultimately lead to loss of integrity. In CO₂ injection areas, these effects may be amplified because of high temperature and pressure variations in the injection well, higher injection pressure, and reactions between the CO₂-brine mixture with the well material. A well with compromised integrity may not be able to prevent upward transport of injected CO₂ and other formation fluids (e.g. brine, hydrocarbons). The leaked liquid will become greenhouse gas if it is released into the atmosphere and will contaminate drinkable groundwater resources if it leaks into subsurface water formations [44, 45].

5.1 Leak path

The function of cement sheath in oil and gas wells is to seal formation fluids, support and suspend casing, protect the wellbore, and provide a certain alkaline environment to avoid casing corrosion and ensure wellbore integrity. However, after carbon dioxide is injected into the subsurface, it will corrode the cement sheath and casing under suitable humidity and pressure conditions cause problems, such as a decrease in the strength of the cement sheath and an increase in its permeability. Furthermore, the corrosion effect, cement hardening, and alternate injection processes will impact casing and cement sheath strength and stress distribution in the near-well region, exacerbating wellbore integrity failure. Figure 10 shows the CO₂ leak path due to wellbore integrity failure [45, 47].

Figure 10.

Schematic diagram of leak pathways related to wellbore integrity (reproduced from [46]).

1. (1) Casing corrosion creating fractures (#1)

2. (2) Incomplete and inadequate cement pouring existing leakage paths (#2, #9)

3. (3) Flow upward through the annulus or naked well (#3, #4)

4. (4) Leakage along the thread of the casing connection (#5)

5. (5) Leakage along formations damaged during drilling (#6)

6. (6) Casing-cement and cement-formation interface debonding resulting in microfractures (#7, #12)

7. (7) Poor cement consolidation quality with permeability (#8)

8. (8) Fractures or gas channels in cement (#10, #11)

5.2 Chemical well integrity failure

Silicate cement is usually used as a sealing material when completing a well. The reaction occurs when the cement comes into contact with CO₂, resulting in the degradation of the cement. The continuous reaction of cement with CO₂ increases the porosity of the cement matrix, which also allows chloride ions to pass through the matrix causing corrosion of the casing [48, 49].

However, the consequences of the reaction between cement and CO₂ are not always harmful. The slight carbonation of CO₂ can reduce the permeability and porosity of the cement without causing failure of well integrity if the cement consolidation quality is excellent. However, a high degree of carbonation will certainly lead to failure or fracturing of the cement structure, failing well integrity. The corrosive effect of CO₂ will be more pronounced if the cement quality is poor with existing defects such as tiny pores or fractures [50, 51].

There are numerous mechanisms of chemical reactions impacting well integrity, and it is necessary to clarify the CO₂ and formation properties, and then the various chemical changes during the interaction of cement materials, wellbore materials, and carbonic acid can be further investigated.

5.3 Mechanical well integrity failure

Geomechanics is a key factor impacting well integrity with effects throughout the life cycle of a GCS project. During the drilling, completion, and application of the well the stresses in the wellbore, the cement sheath, and the near-well area keep changing. The reasons include pore pressure changes due to injection, leakage, and diffusion, thermal stress changes due to temperature differences, and in-situ stress changes due to tectonic shifts or seismic activity. Among them, the stress change in the cement sheath is the most significant. After the cement is poured, it will go through two stages of hardening (liquid cement transforms into solid cement) and shrinkage (solid cement volume shrinks and continues to harden). The change in cement rheology is more obvious during the hardening process. However, in the post-hardening phase, the shrinkage of the cement not only has a large effect on the stresses (because it is a solid shrinkage), but also the shrinkage may lead to plastic deformation or cause debonding at the interface between the cement and the formation or casing. In addition, the casing position may offset from the center of the wellbore, resulting in uneven stresses on the casing and cement sheath, increasing the risk of casing deformation and interface debonding. Thermal stresses are particularly important when CO₂ is injected into the subsurface, especially in the case of cyclic loading, causing coupling between thermal stresses and other stress fields, promoting fracture growth within the cement or debonding at the cement interface [46, 52, 53].

In conclusion, well integrity issues may be encountered during the entire GCS life cycle due to the influence of multiple factors such as coupled stress-thermal-chemical. Therefore, it is necessary to take into account the combined effect of these factors in GCS engineering for well integrity problems, which are generally studied using numerical simulation.

6. Induced seismicity

From a safety and public perception point of view, a more unacceptable issue for CO₂ injection into the underground formation is the microseismic activity caused by fault activity or surface uplift during the injection process. Sometimes the intensity of induced seismicity will be perceived by humans. Slight shear sliding of fractures is induced when the induced seismic magnitude is very low. It will be more beneficial for CO₂ injection if the fractures are confined within the reservoir, as fracture sliding enhances permeability. However, microseismicity caused by GCS is difficult to control. Seismic events which can be sensed may have serious consequences such as massive CO₂ leakage, damage to injection wells, vertical surface displacement damaging buildings or infrastructure, etc. For example, several of the largest seismic events in the United States in 2011 and 2012 may have been caused by nearby disposal wells. The largest of these was a 5.6 magnitude seismic that occurred in Oklahoma, destroyed 14 buildings and injured two people. For the public, a perceptible seismic event would cause serious panic. Therefore, it is important to minimize or avoid seismic activity to ensure that geological energy projects such as GCS are carried out [39, 54, 55, 56].

6.1 Key factors affecting induced seismicity

As shown in Figure 11 [54], the mechanism for inducing seismicity appears to be well known, that is, weakening pre-existing faults by increasing fluid pressure. The formation will release stored elastic strain energy when a fault slips, triggering seismicity. The fault will remain locked as long as the applied shear stress is less than the strength of the contact. The failure condition can be determined according to the effective stress principle and the Mohr-Coulomb criterion.

Figure 11.

Schematic diagram of mechanisms for inducing seismicity [54].

Theoretically, the increase of fluid pressure should be the direct reason for induced seismicity and it can be avoided by changing the injection rate and controlling the formation pressure to avoid induced seismicity. Based on the mechanism of induced seismicity, the possible reasons for seismic events caused by GCS are clarified [57, 58, 59].

1. The pore pressure increases and the stress state changes when the fluid is injected.

2. There is usually a temperature difference between injected CO₂ and the formation, which cools the formation near the injection well, causing thermal stress. The magnitude of thermal stress is proportional to the stiffness of the rock, so the thermal stress is more obvious when CO₂ is injected into a hard formation.

3. The parameter differences between the reservoir and the caprock result in different responses to pressure accumulation and thermal stress.

4. Each microseismic event will result in shear slip as well as stress redistribution. However, not all shear slips and the redistribution of stresses will cause microseismic events.

5. Geochemistry, rock strength, fault strength, and heterogeneity of stress field are all potential factors leading to local stress changes and triggering microseismicity.

6.2 Seismic moment release

At present, the principle and calculation formula of subsurface injection-induced seismicity proposed by McGarr [60] are widely used. The theory is based on the following assumptions to calculate the upper bound seismic moment due to fluid injection into geological formations.

1. There are seismogenic faults in the vicinity of the injection formation that are prone to slip in the contemporaneous state of stress.

2. The stress on the fault is within the seismic stress drop of failure due to earlier seismic activity.

3. The seismic rock mass is fully saturated before injection.

4. The induced seismicity is confined to areas weakened by fluid injection.

If a volume $\mathrm{\Delta }V$ of liquid is injected into a fully saturated formation, the average increase in pore pressure $P$ can be calculated as follows.

$$\mathrm{\Delta }P=\frac{3\lambda +2G}{3}\frac{\mathrm{\Delta }V}{V}$$E8

where $V$ is the volume of the formation weakened by the injection; $\lambda$ and $G$ are Lame’s elastic parameters, $G$ being the modulus of rigidity.

And the upper bound to the cumulative seismic moment is given by:

$$\sum M_0=\frac{2\eta \left(3\lambda +2G\right)}{3}\mathrm{\Delta }V$$E9

where $\eta$ is the coefficient of friction.

The analytical solutions that can accurately calculate the seismic magnitude are difficult to obtain because of the complexity of the induced seismicity. Therefore, more numerical simulations are used for seismic prediction, including the calculation of activation potential using shear slip criterion, based on continuous medium mechanics approach, through fault hydrodynamic approach, and discrete method modeling approach. A seismic event of magnitude 3–4 with a radius of the damage zone between a few hundred meters and one kilometer of the shallow formation can be perceived based on field experience and extensive numerical simulation studies. It is further demonstrated that high-level seismicity is induced only when the fault has continuous permeability and the pressure is distributed over a sufficiently large fault with simultaneous brittle fracture. In fact, even clearly perceivable seismic events may not open new flow channels over the entire thickness of the caprock, that is, seismically induced flow channels are unlikely to cross a formation with multiple caprocks.

7. Conclusions

GCS is an important way to reduce carbon emissions. There are multiple trapping mechanisms after CO₂ injection into the subsurface, including stratigraphic trapping, residual trapping, solubility trapping, and mineral trapping, and each of them plays a role at different times. Geomechanical issues directly determine the success or failure of GCS. The evolution of the in-situ stress and effective stress can be calculated from the pore pressure variation and the stress path coefficient. Further, the integrity of the caprock under different regime conditions can be evaluated based on the variation of in-situ stress. Generally speaking, it is most stable in the normal fault regime, followed by the strike-slip regime, and the most unstable is the thrust fault regime. In addition, acidic fluids or gases can be formed after CO₂ injection, corroding the wellbore and cement sheath, creating multiple leak paths, and leading to failure of wellbore integrity. For the general public, the top concern is whether the GCS project will cause earthquakes. Fortunately, it has been identified based on the current studies that the injection of CO₂ does trigger microseismic events that can be perceived by humans, but the magnitude of the earthquakes and the energy released would not bring damage to buildings or organisms on the ground.