Regional saline aquifers offer the greatest potential for very large-scale underground CO2 storage as a means of mitigating greenhouse gas emissions. Their dynamic storage capacity, in terms of induced increases in formation pressure, will limit the rate at which CO2 can be injected and may ultimately limit the amount of CO2 that can be stored. Generic flow models were generated to examine the effects on pressure evolution of various reservoir parameters (dimensions, permeability, porosity, presence and nature of flow barriers). CO2 injection involves dominantly hydrogeological (single-phase flow) processes in much of the reservoir and surrounding adjacent strata, with additional two-phase flow effects around the CO2 plume itself. Large, thick aquifers with no significant flow barriers can accept high injection rates (c. 10 million tonnes of CO2 per year) without undue pressure effects. However, flow barriers, such as faults, increase induced pressures considerably; for reservoirs with such features, careful site characterization and operational planning will be required for large storage projects. The principles established from the generic modelling were applied to a real aquifer storage operation at Sleipner in the North Sea. Here, CO2 is being injected into the Utsira Sand, a large relatively homogeneous reservoir. Modelling indicates that pressure increase should be negligible. In fact, observed wellhead pressures do show a small rise, but this can be attributed to temperature changes in the fluid column in the wellbore. Pressure changes in the reservoir are likely to be very small.