For carbon dioxide (CO2) storage operations, hydrate formation in the CO2-injection system could be an issue for pipeline material integrity and safety. Numerous and extensive CO2-hydrate research has been carried out for pure CO2 and its mixtures, in both theoretical models and experimental determination. This study aims to use existing CO2-hydrate studies in the concept selection stage by application of sensitivity studies of representative operational conditions with laboratory-data-derived hydrate curves and commercial thermodynamic simulators. Hydrate formation was studied for various operational conditions of CO2-injection wells injecting into a saline-aquifer formation. Thermal/hydraulic analysis identified the operational conditions of the injection well. Then, thermodynamic calculation determined the hydrate tendency and minimum water content required to form hydrates. In cases in which hydrates are expected to form, it is recommended to inject thermodynamic inhibitors to prevent hydrate formation. Both monoethylene glycol (MEG) and methanol can be used readily for this application. However, when water-flushing operations are required to remove potential near-wellbore halite precipitation, MEG is preferred because it is less prone to exacerbate salting-out effects compared with methanol.