Abstract: With the continuous petroleum extraction from deep-water subsea gas fields, many long distance offshore natural gas pipelines have been constructed. The design parameters directly affect the gas flow velocity in pipelines, which may introduce high wall shear stresses on the pipeline internal wall. Moreover, corrosive medium like CO₂, H₂S, O₂, and Cl^- always exists in subsea pipelines under high velocity gas flow, which induces erosion-corrosion. Many pipelines in China have entered the middle or late stage of service, and this has increased the risks and failures induced by erosion-corrosion. Furthermore, more natural gas storages are being built for transportation, which require a high-velocity gas flow for gas injection and production processes. A certain amount of corrosive mediums such as residual drilling fluid, hydrochloric acid, condensate water, CO₂, and H₂S can be found in natural gas, and when combined with a high gas flow velocity, internal erosion-corrosion might occur in the tubing in downhole systems. In this study, a high temperature-high pressure flow loop was applied to investigate the corrosion behavior of L80 steel in a wet gas pipeline with a high gas velocity. The extreme conditions created by the flow loop is 30 m·s^-1 gas velocity, 0.0007% water cut, 0.5 MPa CO₂ partial pressure, and 55℃ environmental temperature. Corrosion rates at different testing periods were calculated through weight-loss measurements. Confocal laser scanning microscopy and scanning electron microscopy were applied to observe the corrosion morphology. The corrosion product constituents were analyzed using X ray diffraction and energy dispersive spectroscopy (EDS), and the results reveal that severe corrosion occurs and a large number of micro pits appear on the L80 coupons surfaces. Moreover, instead of an integral corrosion prod-uct film, FeCO₃ corrosion product chips and Fe₃C are present on the steel.