Geological storage of CO2 is an option for mitigating global climate change resulting from greenhouse gas emissions. Effective selection, design, and operation of storage sites require reliable models for predicting the response to CO2 injection. This paper revisits preliminary studies of CO2 storage in the Nisku saline aquifer in Alberta, Canada, which were conducted to assess CO2 injectivity, plume migration, and geomechanical response during 50 yr of injection, using model input parameters estimated from data available at the time. The new work presented here involved modeling of CO2 injection using the same tools but with input parameters obtained from data acquired in an evaluation well. The first series of new simulations modeled fluid flow using a commercial black-oil simulator and predicted a lower maximum injection rate (0.80 million t [Mt]/yr [0.88 million tons (Mtons)/yr] compared to 1.0 Mt/yr [1.1 Mtons/yr]) but a CO2 plume width nearly identical with the preliminary prediction (as a consequence of increases in some parameters that offset decreases in other parameters). The second series of new simulations was undertaken using a coupled thermo–hydro–mechanical simulator and predicted ground surface uplift approximately four times less than the preliminary study and (when injecting above the fracture pressure) fracture dimensions several times greater. As before, thermal effects resulting from cool CO2 injection were observed to promote lateral fracture growth in the aquifer and reduce (but not prevent) vertical growth into the cap rock. Use of the evaluation well data in this study enabled a more confident conclusion that injection above the fracturing pressure is not feasible for this site.