Corrosion Testing of Well Casing Materials at 450°C in Simulated Superhot Geothermal Well Environment

Abstract Interest in harnessing geothermal energy from superhot or supercritical resources has grown significantly globally, leading to the launch of multiple projects worldwide. Most of these initiatives involve drilling deeper than conventional high-temperature geothermal wells (>3 km) to access superhot geothermal fluids (>350 °C) with higher enthalpy (>2.086 MJ kg−1) to obtain higher power output per well. But construction and production of these wells face significant challenges, particularly corrosion, due to high temperatures and the presence of corrosive non-condensable gases like CO2, H2S, and HCl. To assess the durability of commonly used geothermal well casing materials under such harsh conditions, material testing is required in demanding conditions at high temperatures and pressures (>350°C, >100 bar) with corrosive gases. This study investigates the corrosion resistance of API L80 grade carbon steel (CS) and 13Cr stainless steel (SS) casing materials under simulated superhot geothermal conditions using a high-temperature, high-pressure (HTHP) autoclave. The materials were tested at 450 °C and 167 bar in H2O vapor containing H2S and CO2 gases for 168 hours. Both materials had very low uniform corrosion rates (<0.02 mm/year). The L80-13Cr SS had lower CR than CS showing better corrosion resistance than the L80-CS as well as no pits were detected as for the CS. The high superheat and low density of the steam likely contributed to the low CR of both materials as well as the surface layer formed from reaction products during the HTHP corrosion test. Specifically, the formation of a continuous and protective surface film with chromite (Fe2Cr2O4) and iron silicates on the L80-13Cr SS is considered to have contributed to better surface protection than the surface film formed on the L80-CS.