Unraveling the corrosion behavior and corrosion scale evolution of N80 steel in high-temperature CO₂ environment: The role of flow regimes

During CO₂ transportation and storage, metal equipment such as oilfield pipelines suffers from severe CO₂ corrosion, especially in harsh downhole injection equipment. In this study, we investigated the corrosion behavior of oil well tubing in a high-temperature, high-pressure (HTHP) CO₂-containing environment. The evolution of the corrosion scale was also examined under different flow regimes. The results reveal a lower corrosion rate at 150 ℃ compared to 80 ℃ under different flow regimes, with localized corrosion intensifying as temperature and rotational speeds (v_rs) increase. The temperature also induces the corrosion scale conversion of aragonite-type CaCO₃ (80 ℃) to calcite-type CaCO₃ (150 ℃). Specifically, the variation of the corrosion rate and the corrosion scale evolution can be attributed to the vortices within the reactor. The intact vortex cells enhance mass transfer while also promoting nucleation and growth of CaCO₃. However, when v_rs exceeds the critical Reynolds number, the vortex cells are disrupted, resulting in viscous dissipation and a reduced corrosion rate.