CO2-water alternated gas (WAG) injection is one of the effective methods for developing offshore low-permeability oil fields. However, factors such as impurities in the gas source and the complex environment of low temperature and high pressure pose risks of flow blockage in the wellbore. By establishing a numerical model for injection wellbores in offshore oilfields, key production parameters for four operating conditions are simulated. Four operating conditions are water injection, gas injection, water injection well shut-in, and gas injection shut-in. The temperature, pressure, liquid holdup, and phase change patterns of the entire wellbore under each operating condition are analyzed, and the risk of hydrate formation in the entire wellbore is assessed based on hydrate formation conditions. The results indicate that the overall pressure inside the wellbore is high under all operating conditions, but there are significant variations in temperature and liquid holdup, leading to a higher risk of hydrate formation in the low-temperature zones of the wellbore. Optimization methods such as increasing the injection gas/water temperature, reducing injection gas/water rates, and adjusting shut-in cycles can mitigate the low-temperature effects in the wellbore, thereby reducing the risk of hydrate formation during water injection well shut-in and gas injection well shut-in. Moreover, there is a positive correlation between the methane impurity content in the gas and the risk of hydrate formation in the wellbore. The findings of this study can guide the development of risk prevention and control strategies for offshore CO2-water alternated gas injection wellbores, providing a theoretical basis for the safe implementation of water–gas alternated wellbore operations on offshore platforms.