Sequestration of carbon dioxide (CO₂) in depleted gas reservoirs is an attractive choice, especially in The Netherlands, to reduce CO₂ emissions into the atmosphere. Injection of CO₂ in the subsurface geological formations can distort local thermal, chemical and geomechanical equilibria. As such, it results in highly coupled (thermo)physical effects in the near wellbore region, referred to as “near wellbore effects”. In this work, qualitative and quantitative descriptions of the near wellbore effects in depleted gas fields on macroscopic scale are provided. The primary focus is on the thermal effects (i.e., Joule-Thomson effect, water vaporization and CO₂ dissolution) and specific chemical effects (i.e., salt precipitation and hydrate formation). Occurrence and the corresponding magnitude of certain near wellbore effects influence the injectivity of CO₂ both positively and negatively. In several occasions these effects can lead to severe reduction of the injectivity. To accurately model these effects, thermal multi-component multi-phase simulations are conducted using both TOUGH2-ECO2MG and CMG-GEM commercial-grade simulators. Important is that these simulations include precipitation of salt and phase changes of CO₂ during repressurization of the reservoir. Extensive sensitivity study on numerous 1D, 2D and 3D reservoirs with various injection parameters and degrees of heterogeneity is carried out. A comprehensive 3D geological model of the nearly depleted P18-4 gas field (located in the Dutch North sea) is also investigated, in order to examine the near wellbore effects in a real-field application. Moreover, the potential control of the near wellbore thermal effects by interplay of controllable operational parameters (e.g. rate, temperature or composition) and the local reservoir pressure and temperature conditions is presented. Results reveal that the high injection rates targeted for real CO₂ injection (i.e., 1.1 Mt/yr) in combination with low initial reservoir pressures (> 40 bar) and a large reservoir volume provide favorable conditions for development of predominantly excessive cooling effects (15 ^oC) near the wellbore. Injection of CO₂ in gaseous conditions at low temperatures can cause such strong cooling that hydrate can form, which can potentially jeopardize the injection process due to clogging of the reservoir. However, as for its specific geometry and well location, the thermal effects are significantly less pronounced in the P18-4 field model. Besides, heterogeneity of the formations plays a key role in the distribution of the appearing effects along the wellbore. Overall, for the considered cases, the injectivity is found to be enhanced rather than decreased by the studied near wellbore effects, with the proviso that the conditions in the near wellbore region remain outside the hydrate formation window.