CO2 sequestration in deep saline aquifers is vital to reduce the global carbon footprint. However, this effort can be hampered due to salt precipitation during CO2 injection, which clogs flow pathways leading to a significant reduction in CO2 injectivity. While freshwater has traditionally been employed as the primary solution to dissolve the precipitated salt, the salt tends to re-precipitate upon CO2 reinjection post-treatment, exacerbating the injectivity damage. The project was divided into two stages: (1) simulating salt precipitation scenarios with varying brine salinities to mimic formation damage during CO2 injection in saline aquifers, and (2) critically assessing the impact and effectiveness of acetic acid as a mitigation fluid under different injection scenarios through core-flooding experiments. The results were compared with freshwater and low salinity water (LSW). Mineralogical and petrographical assessments were carried out on the core samples to characterize the Berea sandstone cores. The core flooding experiments were conducted at 60 °C and 1600 psi for CO2 injection, freshwater, LSW and acetic acid flooding. The experimental results revealed significant reductions in permeability (37 -75 impairment) and porosity (18 to 33) due to salt precipitation. Among the treatments, LSW exhibited the lowest efficacy, followed by freshwater, possibly due to clay swelling, fines migration, and capillary trapping effects causing pore throat blockages. In contrast to freshwater and LSW, acetic acid treatment demonstrated improved injectivity, showing a high dissolution potential with up to a 137 increase compared to initial permeability. This study provides a preliminary assessment of the potential of acetic acid for CO2 injectivity enhancement and recommends further investigations on the effects of acetic acid and brine concentrations on the process. © Copyright 2024, Society of Petroleum Engineers.