# Optimization of Offshore Saline Aquifer CO2 Storage in Smeaheia Using Surrogate Reservoir Models
## 3 Methodology
### Updating the Numerical Model  
According to observations, it was projected that the storage complex would undergo an average pressure drop of 14 bar from 1999 to 2022 [67]. Hence, the pore volume multipliers for the southern and northern regions have been set to 50 and 55, respectively, by sensitivity analysis to obtain a more certain model with respect to the original model.  
As previously stated, the storage thickness decreases in an easterly direction, along with the caprock. Furthermore, as indicated by Figure 6, there are some minor faults and cracks present in the higher layers of zone Beta, where both the storage formation and caprock have been reduced in thickness. Consequently, it is imperative to avert the dispersion of the CO\({}_{2}\) plume into zone Beta to mitigate the risk of probable leakage. Pre-existing faults and fractures, as well as caprock fracturing, contribute to the dangers associated with CO\({}_{2}\) storage. Furthermore, during initial simulations, the bottom hole pressure reached a magnitude of 1000 bar, which is unattainable in real-world operations. Therefore, it is necessary to develop a new well design and optimize the injection process.  
[PERSON] [52] analyzed the sensitivity of the field with respect to well placement, although the model used differs from Statoil's model regarding the presence of the production wells. Statoil's model was assessed in this study with respect to the injection well location. Figure 7 compares the CO\({}_{2}\) plume migration path where the injection well is located in the north of zone Alpha, between zone Alpha and Beta, and in the south of the model.  
Evidence suggests that the injection of CO\({}_{2}\) in the vicinity of zone Beta will inevitably result in leakage. Zone Gamma is excluded from this analysis due to its unavailability in the seismic survey and the uncertainty surrounding its features, despite its significant storage capacity. In addition, the depletion of virtual wells causes the CO\({}_{2}\) plume to vary from its initial route in the absence of virtual wells. Zone Alpha has shown superior performance in controlling the migration path of CO\({}_{2}\). However, to optimize its effectiveness, the injection well must be relocated and modified as a down-dip J-shaped directed well in the northern part of the zone. This redesign should include a lengthy tangent section and perforation towards the northwest. The purpose of this was to ensure that the bottom hole pressure  
Figure 5: Gas saturation distribution in year 2300, after 25 years CO\({}_{2}\) injection with the rate of 5.872 \(\times\) 10\({}^{6}\) sm\({}^{3}\)/day since 2022.  
did not surpass the fracture pressure. The well Alpha was intentionally redesigned with the top of the perforation positioned at a depth of 1600 m TVD ssl.  
According to the stress model, the minimum horizontal stress (Min SH) can be calculated as the upper limit for bottom hole pressure, while the fracture pressure serves as the limit for field pressure [49]. The Min SH at the depth of 1600 m TVD ssl is 216 bar; by considering a safety factor, 200 bar is fixed as the well bottom hole pressure constraint. A simulation scenario was developed to validate the well design by injecting CO\({}_{2}\) at a rate of 5.872 \(\times\) 10\({}^{6}\) sm\({}^{3}\)/day over a period of 35 years (2022-2057). Figure 8 illustrates the CO\({}_{2}\) saturation after a 35-year injection in the new model. The highest bottom hole pressure in well Alpha reached 180 bar.  
Figure 6: Storage structure, consisting of top and bottom surfaces, and faults.  
Figure 7: Well location sensitivity analysis in zones Alpha, Beta, and Gamma.