A Water Chemistry Model Applied to Corrosion under Geologic Conditions

Industrial wellbore systems are designed to isolate fluids in the subsurface and are typically planned for a 30-50 year service life. In the geologic sequestration of CO₂ in depleted oil and gas reservoirs, wellbores will have to perform for 100’s of years. As a consequence, one of the key questions in the viability of sequestration is whether long-term wellbore integrity is feasible in high-salinity, high-CO₂ fluids likely to be present in CO₂ storage reservoirs. Isolation in wellbores is usually accomplished by a combination of Portland cement and steel. In this study, we focus on predicting the corrosion rate of steel under typical CO₂ sequestration conditions.
We have developed a mechanistic model for predicting corrosion rates of mild steel present in most wellbore systems. The model includes water chemistry and an electrochemistry module. The water chemistry module uses a Pitzer model for activity coefficients and Duan and Sun’s 2006 model for CO₂ solubility. The electrochemical module accounts for mass transfer processes and electrochemical kinetics. The electrochemistry includes the primary oxidation reaction (the dissolution of iron) and the primary reduction reactions (the formation of H₂ gas from carbonic acid, bicarbonate ion, hydrogen ion, and/or water).
High salinity solutions reduce corrosion rates significantly mainly due to the “salting-out” effect of reduced CO₂ solubility. For example, an increase in salinity from 5 to 20 wt% salt results in a 50% reduction in corrosion rate as observed in our experiments.  We are extending the uniform corrosion model to account for scale formation and to represent localized corrosion. The mechanistic model will be incorporated into the mass and transport code, FLOTRAN, to conduct simulations of corrosion in under leaky CO₂ conditions.