In view of current interest in geological CO2 sequestration and EOR, this study investigated water-based and gas-based CO2 injection strategies for coupled EOR and storage purposes. For water-based CO2 injection strategy, carbonated water injection (CWI) was investigated as an alternative injection mode that could improve sweep efficiency and provide safe storage of CO2. Despite its potential, CWI has not been very much studied. This thesis presents the details on the performance of CWI of moderately viscous oil (>100 cP), which has not been reported before. The effects of oil viscosity, rock wettability and brine salinity on oil recovery from CWI were also studied and significant findings were observed. To the author’s knowledge, no attempt has been made to experimentally quantify the CO2 storage by CWI process and to model the nonequilibrium effects in the CWI at the core scale using the commercial reservoir simulators. These are amongst the main innovative aspects of this thesis. The experimental results reveal that CWI under both secondary and tertiary recovery modes increase oil recovery and CO2 storage with higher potential when using light oil, low salinity carbonated brine and mixed-wet core. In this study, the compositional simulator overpredicts the oil recovery. The instantaneous equilibrium and complete mixing assumptions appear to be inappropriate, where local equilibrium was not in fact achieved during the CW process at this scale. The author evaluated the use of the transport coefficient (the a-factor) to account for the dispersive mixing effects, and found that the approach gives a more accurate prediction of the CWI process. For the gas-based CO2 injection strategies, a practical yet comprehensive approach using reservoir simulation, Design of Experiment (DOE) and the Response Surface Model (RSM) to screen for and co-optimize the most technically and economically promising injection strategy for coupled EOR and CO2 storage is presented. For the reservoir model used in this study, miscible WAG was found to be most economically promising, while miscible continuous CO2 injection was ranked as the most technically viable. The duration of the preceding waterflood, relative permeability (wettability) and injected gas composition are the three most significant factors to the profitability of oil recovery and CO2 storage through tertiary WAG injection.