The project "Proche Puits" ("Near Wellbore") co-funded by the French National Agency for Research (ANR) started in December 2007 and ended in May 2011. The project consortium gathered three companies (TOTAL, Schlumberger, and GDF-Suez), two applied research institutes (BRGM and IFP Energies nouvelles), two academic research laboratories (CNRS and Université de Lorraine) and a SME (ITASCA). The main processes studied were: i) physical behaviour of flowing fluids (CO2) in the well and their impacts on the bottom hole T-P conditions, ii) thermo-kinetic effects on the petrophysical and physico-chemical processes, iii) drying-out of the near-wellbore porous media and reactivity of highly evaporated residual brines retained by capillary and osmotic forces in the pores, and iv) petrophysical and geomechanical impacts of coupled processes. The understanding of these phenomena based on laboratory experiments and numerical modelling allowed a better interpretation of the coupled processes and the development of advanced concepts of CO2 storage in saline aquifers. The project demonstrates firstly that injection of large quantity of CO2 in deep saline aquifers will lead to a strong water desaturation of the near wellbore because of drying mechanisms. In this context, drying mechanisms can precipitate the salt present in the aquifer and then lead to injectivity alteration due to permeability decrease. Numerical modelling coupling hydraulic and thermal processes were shown to be able to simulate the observed evolution of liquid and gas saturations and to estimate the salt depositions. The numerical simulations approaches were validated with respect to laboratory experiments in controlled conditions allowing the determination of the most important parameters for injectivity design (porosity, relative permeability and capillary pressure curves...). The experimental observations, established at the centimetre scale, were up-scaled in order to extrapolate the results at the near wellbore scale and then, to forecast the impact of CO2 injection on petrophysical properties of the host rock. Finally, obtained results allow the definition of recommendations and risk analyses on the injectivity for CO2 geological storage in aquifer. Injection flow rates, optimum pressure and temperature in wells can then be evaluated to avoid damage in the near wellbore zone and maintain injectivity during the life-period of the well exploitation.