We establish a fluid property model for carbon capture and storage (CCS) within the unified framework of classical compositional reservoir simulation by employing the standard volume-translated Peng-Robinson (PR-VT) Equation of State (EOS) and Lohrenz-Bray-Clark (LBC) viscosity correlation. We spend tremendous effort on the collection of high-quality data and our model demonstrates excellent numerical accuracy because each parameter is well defined through the extensive calibration with data from experiments, National Institute of Standards and Technology (NIST) and reliable correlations. We successfully address all the questions that could be encountered in the prediction of phase behavior and physical and transport properties of CCS fluid systems: the multiple components of injection gas, the gas solubility in aqueous phase and water (no salts) solubility in non-aqueous phase, the density and viscosity of aqueous phase with dissolved gas and of non-aqueous phase with dissolved water, and the impact of different ionic species on gas solubility, density and viscosity of aqueous phase. Moreover, we propose a modified procedure to perform the multi-component multi-phase equilibrium computation that implements our model and overcomes the challenge due to thermodynamic inconsistency caused by phase-dependent parameters. Since CO2/brine system has zero degree of freedom at fixed temperature and pressure in two-phase state, we are able to create the ‘exact’ black oil table by applying the phase equilibrium computation integrated with our model. It is of particular significance because the corresponding black oil simulation for CO2 injection in saline aquifer could be performed on any commercial reservoir simulator in large scale to satisfy most of the requirements of CCS studies.