Corrosion of Carbon Steel in Artificial Geothermal Brine: Influence of Carbon Dioxide at 70 °C and 150 °C

Abstract

This study focuses on the corrosion mechanism of carbon steel exposed to an artificial geothermal brine influenced by carbon dioxide (CO2) gas. The tested brine simulates a geothermal source in Sibayak, Indonesia, containing 1500 mg/L of Cl−, 20 mg/L of SO42−, and 15 mg/L of HCO3− with pH 4. To reveal the temperature effect on the corrosion behavior of carbon steel, exposure and electrochemical tests were carried out at 70 °C and 150 °C. Surface analysis of corroded specimens showed localized corrosion at both temperatures, despite the formation of corrosion products on the surface. After 7 days at 150 °C, SEM images showed the formation of an adherent, dense, and crystalline FeCO3 layer. Whereas at 70 °C, the corrosion products consisted of chukanovite (Fe2(OH)2CO3) and siderite (FeCO3), which are less dense and less protective than that at 150 °C. Control experiments under Ar-environment were used to investigate the corrosive effect of CO2. Free corrosion potential (Ecorr) and electrochemical impedance spectroscopy (EIS) confirm that at both temperatures, the corrosive effect of CO2 was more significant compared to that measured in the Ar-containing solution. In terms of temperature effect, carbon steel remained active at 70 °C, while at 150 °C, it became passive due to the FeCO3 formation. These results suggest that carbon steel is more susceptible to corrosion at the near ground surface of a geothermal well, whereas at a deeper well with a higher temperature, there is a possible risk of scaling (FeCO3 layer). A longer exposure test at 150 °C with a stagnant solution for 28 days, however, showed the unstable FeCO3 layer and therefore a deeper localized corrosion compared to that of seven-day exposed specimens.

Laboratory tests simulating corrosion in geothermal power plants: influence of service conditions

“…8. This EEC is similar to those successfully used in other studies to describe a metal/porous corrosion layer/ electrolyte system (Aristia et al 2019;Bousselmi et al 1999;Farelas et al 2010). Each time constant and element in the equivalent circuit represents a part of the interface electrolyte/porous corrosion product layer/metal.…”

Effect of CO2 Partial Pressure on the Corrosion Inhibition of N80 Carbon Steel by Gum Arabic in a CO2-Water Saline Environment for Shale Oil and Gas Industry

“…However, CO 2 gas dissolves in the fluid to form the weak carbonic acid, which in turn dissociates into bicarbonate and carbonate anions [ 4 , 5 ]. The presence of this weak acid can lead to severe corrosion attacks on the steel structures [ 4 , 5 , 6 ].…”

“…[ 8 ]. The literature reports that the presence of a high concentration of chloride ions in a CO 2 -containing fluid can exponentially accelerate the dissolution of the steel [ 6 , 9 ].…”

“…The CO 2 -EOR process can significantly increase the dissolution of the tube. As reported by many studies, the severity of the CO 2 corrosion attack increases with an increase in CO 2 partial pressure due to the increase in acidity of the fluid [ 4 , 5 , 6 ]. Therefore, understanding how the CO 2 partial pressure can influence the inhibitory action of certain corrosion inhibitors in CO 2 saline environments is important and can help to minimize the material and economic losses.…”

Monitoring and mitigating corrosion in geothermal systems

“…Error bars indicate the error value from data fitting. Adapted from Aristia et al [ 24 ] (Open access Creative Common CC BY license). [Color figure can be viewed at wileyonlinelibrary.com]…”