## 3 Reservoir-Scale Simulations
### Geomechanical Processes
The results showed that the fractures will open due to a reduction in normal effective stress, and fracture re-activation will result in an increase in permeability across the caprock; thus, CO\({}_{2}\) leakage could occur. Moreover, the modelling studies carried out by [PERSON] et al. [107] and [PERSON] et al. [108] confirmed that pressure behaviour within the caprock in the presence of fractures was significantly different, to otherwise, and that the leakage pathway via the seal can be detected by monitoring any significant change in pressure within the caprock during CO\({}_{2}\) injection. Furthermore, [PERSON] et al. [109] focused on modelling the geo-mechanical behaviour related to the subsurface uplift of only the reservoir under different CO\({}_{2}\) injection rates, along with setting different boundary conditions using a simple model of the Sleipner site. The results showed that the key impact of the fluid pressure was the expansion of the Utsira sand formation, and, in addition, the Nordland shale (seal) was found to be soft due to the shale not being fully lithrified from the top to the base. Thus, the ability of Nordland shale (seal) to adopt the dilation from the Utsira formation (reservoir) is possible. However, several areas within the Utsira formation have impermeable sites which would increase in terms of their pore pressure and expansion, and therefore the threat of fracturing and shear deformation remains a possibility. [PERSON] et al. [79] studied the impact of a variety of sealing thicknesses and progressively transitioning layered lithologies, along with using different relative permeability curves, on the sealing integrity caused by the pressure evolution during injection. In particular, they studied how a gradation in rock properties at the base of the seal would affect the propagation of pressure. They considered the impact of the overpressure in the seal caused by the injection in both closed and open systems but neglected several other factors, such as heterogeneities in the body of the reservoir. The study outcomes indicated that the magnitude of pressure within the CO\({}_{2}\) storage is influenced by the relative permeability and porosity variation of the caprock, which introduces the possibility of caprock failure. The type, orientation, and width of strata at the base of the caprock controlled the rate of pressure diffusion into the seal. The effect of the layering was significant, and the depth of heterogeneity covered the region where overpressure changes were substantial, which was the first few metres of the caprock. Additionally, a closed system resulted in the cycling of brine within the reservoir, which would potentially negatively affect the integrity of the caprock, especially near the injection zone. However, the expansion of the caprock pore volume, provided by the expansion of the formation due to the injection pressure, increased the storage capacity of the seal itself, as long as it did not result in geomechanical degradation of the seal. The interaction of CO\({}_{2}\) with caprocks containing swelling clays, such as smectite, can lead to potential local shear failure under unfavourable stress conditions [110]. The stress build-up caused by the poroelastic response of mudrocks, following the sorption of aqueous CO\({}_{2}\) into swelling clays, can lead to fault reactivation and facilitate leakage. Laboratory tests have shown that swelling clays can develop swelling strain and swelling stress when in contact with CO\({}_{2}\)[110]. This is because, depending upon the initial hydration state of the clay, the interlayer spaces between smectite platelets can greatly expand when the CO\({}_{2}\) concentration therein increases. [PERSON] et al. [110] examined the larger-scale consequences of such processes with a macroscopic model describing the elastic deformation of shale resulting from the diffusional and pressure-driven flux of CO\({}_{2}\) dissolved in brine.