Treated oilfield produced water is injected into reservoirs to increase the depleted reservoir pressure and enhance oil recovery. The main challenges in this process are injectivity decline and high tubing head pressure (THP) which is most often caused by the deterioration in the reservoir permeability. This investigation focuses on identifying root causes behind injectivity decline in a sandstone reservoir in Oman. Acid stimulation has been applied to improve the reservoir permeability, but it turned out to be non-feasible due to frequency of such interventions and high associated costs. Several factors, such as injection water quality and reservoir mineralogy, can adversely affect the reservoir permeability and cause injectivity decline. Various approaches to tackle this problem have been adopted in this study including; water analysis, scale modeling, formation damage simulation and core flooding experiments. The scale modeling results showed compatibility between formation and injection water where the scaling potential for both barium sulphate (BaSO4) and calcium carbonate (CaCO3) scales were unlikely to form at reservoir conditions. Injection water analysis showed that, in some cases total suspended solids and oil content exceeded the recommended limit, which might contribute to reservoir permeability decline. XRD analysis of the reservoir core samples revealed that fines and expansive clays are the main components. The core flooding experiments demonstrated that reservoir pore throats get plugged due to two main factors; the suspended solid particles present in the injected water and swelling clays present in reservoir core samples. The formation damage simulator showed that fines migration and clay swelling are the two main possible formation damage mechanisms. To enhance the water injectivity process, the use of a clay swelling inhibitor along with a filtration system to remove suspended particles in the injected water are recommended for the reservoir studied.