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For reliability and safety issues of injection wells, corrosion resistance of materials used needs to be determined. Herein, representative low-cost materials, including carbon steel X70/1.8977 and low alloyed steel 1.7225, were embedded in mortar to mimic the realistic casing-mortar interface. Two types of cement were investigated: (1) Dyckerhoff Variodur commercial Portland cement, representing a highly acidic resistant cement and (2) Wollastonite, which can react with CO2 and become stable under a CO2 stream due to the carbonation process. Exposure tests were performed under 10 MPa and at 333 K in artificial aquifer fluid for up to 20 weeks, revealing crevice corrosion and uniform corrosion instead of expected pitting corrosion. To clarify the role of cement, simulated pore water was made by dispersing cement powder in aquifer fluid and used as a solution to expose steels. Surface analysis, accompanied by element mapping on exposed specimens and their crosssections, was carried out to trace the chloride intrusion and corrosion process that followed.
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 SO4 2-, 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.
Geothermal energy is an interesting alternative to polluting fossil energy sources. Therefore, in Belgium, two wells have been drilled for a deep geothermal power plant. However, the environment to which the installations are exposed is challenging. The geothermal brine has 165 g/l total dissolved solids (of which 90% are sodium and chlorine) and the production temperature can be up to 130 °C. To assess their suitability to be used in a geothermal power plant, the corrosivity of the artificial brine to three common construction materials was investigated with exposure and electrochemical tests. The metals under consideration are a low-alloyed carbon steel (S235JR), an austenitic stainless steel (UNS S31603) and a duplex stainless steel (UNS S31803). The carbon steel, that was found to corrode uniformly, could be considered as a constructional material if a sufficient wall thickness is chosen. The austenitic stainless steel and the duplex stainless steel demonstrate very low uniform
corrosion rates. They are however susceptible to pitting and crevice corrosion. To guarantee safe operation of the geothermal power plant, the susceptibility of the alloys to stress corrosion cracking should be tested and in situ experiments should be performed.
This work examined the factors that influence the droplet corrosion of CO2 pipeline steels caused by oxyfuel flue gases in dense phase CO2 at 278 K, simulating the underground transport conditions. The wetting properties were studied by contact angle measurement, revealing pH and time dependency on the reactive wetting behaviors of carbon steel X70. Exposure tests with CO2 saturated water droplet on steel surface showed that the impurities (220 ppmv SO2 and 6700 ppmv O2) diffused into the droplet and then reacted with metal surfaces in dense phase condition, forming the corrosion products. The corrosion rate was confirmed strongly depending on the droplet volume as well as the SO2 concentration. Condensation experiments carried out on freshly polished coupons in CO2 with 200 ppmv H2O, 220 ppmv SO2 and 6700 ppmv O2, showed that the formation and aggregation of droplets is time and temperature dependent. At 278 K, condensation happened stronger and the corrosion products, mainly consisted of dense hydrated FeSO3/FeSO4. While at 288 K, more fluffy corrosion products consisting of iron oxide/hydroxide and hydrated FeSO3/FeSO4 were found. Further exposure tests on carbon steel coupons with different surface roughness did not reveal the difference in weight loss/gain and therefore the corrosion rate.
Recent studies have shown that even at a very low concentration of impurities (less than 100 ppmv of SO2, NO2, O2 and H2O) the droplet formation and condensation of sulfuric and nitric acids in dense phase CO2 are possible and observable. To reveal the mechanism of droplet corrosion in dense phase CO2 at high pressure and low temperature, further studies on factors that affect wettability and resulting corrosion behaviors of transport pipeline steels are needed. In this study, effects of surface morphology were investigated by varying surface roughness of carbon steel coupons exposed to CO2 stream containing impurities to measure the wettability by contact angle and to observe the condensation as well as possible droplet corrosion that followed. Other considered factors were: pH of the droplet, temperature, droplet volume, and exposure time.