Corrosion control in carbon storage by injection of sodium formate solution

Abstract

Carbon dioxide (CO₂) leakage presents a significant risk to carbon storage in saline aquifers. Buoyant forces can cause CO₂ in resident brine to migrate into overlying formations through faults, fractures, or existing wells. Wells are especially prone to leakage because CO₂ produces an acidic environment, as recently observed in the Illinois Basin Decatur Project (IBDP). This study was motivated by the question of how to mitigate the risk of leakage caused by corrosion in well tubulars.

This research, for the first time, explores the use of sodium formate solution as a corrosion control method based on an IBDP geological model. To evaluate its effectiveness, reactive transport simulations of CO₂ and sodium formate solution injection were performed using the IBDP model. The simulation cases tested different injection rates (80 and 640 m³/d) and concentrations (5 and 15 wt.%), which resulted in varying amounts of sodium formate being injected. Both pre-flush and post-flush injection strategies were considered.

Results indicated that in the pre-flush scenarios, formate can effectively be dispersed by the subsequently injected CO₂ (e.g., 150 to 350 meters from the well), while raising the pH above 4.5. However, to mitigate pH reduction near the injector, formate does not need to disperse widely; the scenario involving approximately 2.5 × 10³ tonnes of sodium formate resulted in an average pH of 4.45 with a standard deviation of 0.27 along the injection well for 25 years, remaining safely above 4.0, which is the recommended pH range for corrosion control of 13 chrome steel pipe.