Corrosion model of CO2 injection based on non-isothermal wellbore hydraulics

• Corrosion behaviors of carbon steel and stainless steel are investigated to examine the condition of CO2 injection wells.
• The corrosion model is applied to both on- and off-shore wells.
• This study provides insights on the material selection of CO2 injection wells, accurate design of injection operations, and leakage monitoring and risk assessment in wellbore.

In this study, the corrosion behaviors of carbon steel and stainless steel are investigated for water-saturated CO2 system to examine the condition of CO2 injection wells in CO2 sequestration and enhanced oil recovery (EOR) operations. In our model, potential nonisothermal effects resulting from CO2 injection activities, including Joule-Thomson effect, heat transfer between CO2 stream and surrounding well/rock formation, the adiabatic (de-) compression of CO2, and the frictional losses, are accounted. The model is applied to onshore and offshore wells using realistic data. In the offshore well, the depth is considered to vary as a power function of lateral distance from the sea floor to the perforation. Depending on scales of injection, our calculations show that the corrosion rates in the tubing wall from the wellhead to bottomhole is on the order of 1 mm/y for carbon steel. For stainless steel, the rate obtained is 0.0057 mm/y. Results of this study provide insights on the material selection of CO2 injection wells, design of injection operations, as well as leakage monitoring and risk assessment in wellbores.