Abstract: To address the corrosion and flow assurance in multiphase pipelines transporting fluids coexisting with CO₂, H₂S, and Cl^-, this study systematically analyzed key risks including hydrate formation, scaling, slug flow, and corrosion through numerical simulation method. A pipeline thermo-hydraulic model was established using PVTsim and OLGA software, based on the Peng-Robinson 78 Peneloux (T) equation of state and the OLGA S-3-Phase multiphase flow model. Corrosion rates were predicted using the NORSOK M-506 and De Waard 95 models. The results show that the corrosion rate is closely related to the partial pressure of corrosive gases, temperature, and flow velocity. The maximum corrosion rate of 1^# and 2^# pipeline reached 2.0 mm/a (in high-velocity regions), 2.1 mm/a (in high-temperature and high-pressure regions), respectively. Hydrate formation risk is regulated by temperature and pressure. Scaling is dominated by CaCO₃, with a maximum scaling mass concentration of 488.7 mg/L. Slug flow is concentrated in uphill sections, with a maximum liquid holdup of 0.7.