@article{Yang2024, 
author = {Liu-Yang Yang and Chang-Pu Liu and Hai-Ming Fan and Da-Lei Zhang and Zhi-Yi Wei and Hui-Liang Wu and Chuan He and Ye-Fei Wang},
title = {Unraveling the corrosion behavior and corrosion scale evolution of N80 steel in high-temperature CO2 environment: The role of flow regimes},
year = {2024},
journal = {Petroleum Science},
volume = {21},
number = {6},
pages = {4464-4480},
keywords = {CO2 corrosion, Oil well tubing, High temperature and high pressure, Corrosion scale, Flow regimes},
url = {https://www.sciopen.com/article/10.1016/j.petsci.2024.11.002},
doi = {10.1016/j.petsci.2024.11.002},
abstract = {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 (vrs) 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 vrs exceeds the critical Reynolds number, the vortex cells are disrupted, resulting in viscous dissipation and a reduced corrosion rate.}
}