Corrosion of Steel Pipelines in Supercritical CO2 Environments: Effects of Injection Pressure and Temperature

Combining carbon capture and sequestration with enhanced oil recovery (EOR) could potentially reduce the carbon footprint through permanent storage of carbon dioxide (CO2) at the end of the EOR operations. However, severe corrosion risks to surface facilities and pipelines come along with the benefits of CO2 injection. The present study, therefore, investigates the corrosion resulting from contact between supercritical carbon dioxide (sCO2)-saturated water and carbon steels typical of Alaska pipelines. Carbon steel was allowed to contact the corrosive environment for 72 h, while the corrosion rate was monitored using linear polarization resistance. It was found that injecting sCO2 into the test brine (synthetic Ugnu field salinity) increased the general corrosion by twofold compared to liquid CO2 owing to the solubility and the kinetics of the corrosion byproducts. The increase in sCO2 injection pressure at a fixed temperature (40°C) was proportional to an increase in corrosion rate (up to 8.83 mm/y). At a fixed pressure (12.7 MPa), increasing the temperature decreased the corrosion rate. As part of the effort to mitigate corrosion of CO2 in an sCO2 environment and to validate inhibitor performance outside of common operating conditions, the inhibiting potential of an imidazolium-based ionic liquid was also evaluated. The findings revealed inhibition efficiency up to 65% at low concentrations (up to 51 ppm) of the inhibitor. The addition of ionic liquid (IL) causes the corrosion to shift from a general type to pitting owing to a partial surface coverage. Results revealed further that ILs work better on carbon steel with low manganese concentration in the coupon steel.