This paper evaluates key parameters in CO 2 storage in saline aquifers. A reservoir simulator was used to simulate 30 years of CO 2 injection followed by 470 years of shut in. Two retention mechanisms were modelled: hydrodynamic and solubility trapping. Solubility trapping was found to be the most important means for storing CO 2 . This effect was enhanced by the creation of convective flow patterns which lead to a greater dissolution of CO 2 . Tests were carried out on a homogeneous model, and the effects of CO 2 diffusion in brine, vertical to horizontal permeability ratio, residual saturations, salinity and injection well completion interval were investigated. Results were compared with those from other studies to develop a more general understanding of factors affecting CO 2 storage. To increase the realism of this study, the effect of geological heterogeneity was also examined. Three types of heterogeneity were investigated: low level random variations in sandstone permeability, stochastic shale layers and a fault. The low level heterogeneity did not have a large effect, although it distorted the convective pattern, while the presence of shales did have a large effect. CO 2 tends to become trapped beneath the shale layers increasing the lateral migration. The amount of dissolved CO 2 was largest in the models with an intermediate amount of shale. It was found that the fault did not affect the pressure distribution in the aquifer, unless the transmissibility was very low. However, the distribution of CO 2 was affected by the location of the well relative to the fault.