**5.2 Mechanisms of sequestration**

There are several mechanisms involved in the sequestration processes. In a typical CO2 sequestration, some of the injected gas dissolves in the formation water (solubility trapping), some may be trapped as residual gas saturation (nonwet trapping), and some may react with host minerals to precipitate carbonate, i.e., mineral trapping.

### **Figure 8.** *CO2 sequestration in various geological settings [from helpsavenature.com].*

In trapping mechanism, the injected CO2 is trapped in reservoirs in a manner similar to natural gas. Further vertical movement of natural gas (similar to CO2) is hampered by cap rock, which is impermeable. Although combination of all of the sequestration mechanisms render CO2 immobile in the geological repositories, the structural/stratigraphic and residual fluid mechanisms have the most dominant and imminent effect on trapping or retaining CO2 in aquifers [51]. This mechanism is mainly governed by density of injected CO2. The density difference between the injected CO2 and brine determines further movement of CO2 plume to rise or sink.

In nonwet trapping, once the supercritical CO2 is injected into the formation, it relocates fluid as it passes through the porous rock. As CO2 continues to move, some of the CO2 is left as disconnected droplets in the interstices due to interfacial forces. This process occurs when relative permeability to nonwet phase, i.e., CO2, becomes zero; nonwet phase therefore is rendered immobile assuming the formation is water-wet. Just like trapping of oil droplets (as nonwetting phase) in the pores containing wetting-phase (being brine), CO2 fills the interstices between pores and is trapped as discontinuous phase. The phenomenon is largely dominated by interfacial tension between the phases and wetting characteristics of the surface [52, 53].

Dissolution of CO2 in water is another important process responsible for sequestration of 20–60% injected CO2 in the geological formations. Dissolution mechanism occurs during migration of CO2 along its pathway in the injected formation. Over time, the injected CO2 dissolves into the formation brine, increasing its density. As a result, CO2-saturated brine sinks slowly and does not reach the surface. Moreover, the dissolution of injected high-pressure CO2 is in the formation brine acidifies the indigenous formation water [10]. Estimating capacity of this mechanism requires reservoir simulation and knowledge of CO2 supply ratio and injection rate, rock/fluid properties, and reactions [54].

In CO2 mineralization, CO2 reacts with minerals in rock to form stable components such as carbonates and aluminosilicate. It occurs along the migration pathway of CO2 into reservoir. Both rate and magnitude of reaction are dependent on the presence of reactive minerals [52] and formation water chemistry [55, 56]. Effective time for mineralization may vary from 500 to 1000 years. However, mineralization can give rise to precipitation of certain minerals and it leads to blockage of pore throat, thereby reducing permeability leading to loss of injectivity. The process is very slow and confined CO2 becomes immobile. The amount of CO2 sequestrated by this mechanism can be significant. Knowledge of mineralogy of a rock is the main requirement in predicting the behavior of CO2 in this mechanism.

## **5.3 CO2 sequestration capacity**

The estimation capacity can be calculated using:

$$\mathbf{G}\_{\text{CO}\_2} = \mathbf{A} \times \mathbf{h} \times \boldsymbol{\Phi} \times \boldsymbol{\rho} \times \mathbf{E} \tag{1}$$

where G is the volume of CO2, A is the area, h is the thickness, Φ is the porosity, and E is the efficiency factor for the CO2 sequestration operation. The abovementioned parameters are mostly in the following range: mostly within the following range in physical parameters:


*CO2-EOR/Sequestration: Current Trends and Future Horizons DOI: http://dx.doi.org/10.5772/intechopen.89540*

• Porosity (Φ): 0.05–0.30

*Enhanced Oil Recovery Processes - New Technologies*

rate, rock/fluid properties, and reactions [54].

**5.3 CO2 sequestration capacity**

range in physical parameters:

• Aquifer thickness (h): 50–400 m

surface [52, 53].

In trapping mechanism, the injected CO2 is trapped in reservoirs in a manner similar to natural gas. Further vertical movement of natural gas (similar to CO2) is hampered by cap rock, which is impermeable. Although combination of all of the sequestration mechanisms render CO2 immobile in the geological repositories, the structural/stratigraphic and residual fluid mechanisms have the most dominant and imminent effect on trapping or retaining CO2 in aquifers [51]. This mechanism is mainly governed by density of injected CO2. The density difference between the injected CO2 and brine determines further movement of CO2 plume to rise or sink. In nonwet trapping, once the supercritical CO2 is injected into the formation, it relocates fluid as it passes through the porous rock. As CO2 continues to move, some of the CO2 is left as disconnected droplets in the interstices due to interfacial forces. This process occurs when relative permeability to nonwet phase, i.e., CO2, becomes zero; nonwet phase therefore is rendered immobile assuming the formation is water-wet. Just like trapping of oil droplets (as nonwetting phase) in the pores containing wetting-phase (being brine), CO2 fills the interstices between pores and is trapped as discontinuous phase. The phenomenon is largely dominated by interfacial tension between the phases and wetting characteristics of the

Dissolution of CO2 in water is another important process responsible for sequestration of 20–60% injected CO2 in the geological formations. Dissolution mechanism occurs during migration of CO2 along its pathway in the injected formation. Over time, the injected CO2 dissolves into the formation brine, increasing its density. As a result, CO2-saturated brine sinks slowly and does not reach the surface. Moreover, the dissolution of injected high-pressure CO2 is in the formation brine acidifies the indigenous formation water [10]. Estimating capacity of this mechanism requires reservoir simulation and knowledge of CO2 supply ratio and injection

In CO2 mineralization, CO2 reacts with minerals in rock to form stable components such as carbonates and aluminosilicate. It occurs along the migration pathway of CO2 into reservoir. Both rate and magnitude of reaction are dependent on the presence of reactive minerals [52] and formation water chemistry [55, 56]. Effective time for mineralization may vary from 500 to 1000 years. However, mineralization can give rise to precipitation of certain minerals and it leads to blockage of pore throat, thereby reducing permeability leading to loss of injectivity. The process is very slow and confined CO2 becomes immobile. The amount of CO2 sequestrated by this mechanism can be significant. Knowledge of mineralogy of a rock is the main

where G is the volume of CO2, A is the area, h is the thickness, Φ is the porosity, and E is the efficiency factor for the CO2 sequestration operation. The abovementioned parameters are mostly in the following range: mostly within the following

• Areal extent of worldwide sedimentary basins (A): 70–80 million km2

GCO2 = A × h × Φ × ρ × E (1)

requirement in predicting the behavior of CO2 in this mechanism.

The estimation capacity can be calculated using:

**138**

