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The environmental concerns about availability of fossil fuels and greenhouse gas effect increase and alternative renewable fuels for power plants are gaining significantly of importance. One of the alternative renewable fuels is biomass but it is a difficult fuel because of its diversity and complexity. It can contain high percentages of K and Cl responsible for corrosion together with sand that have additionally an abrasive effect during combustion. Because of permanently extending the surface reaction due to abrasion the corrosion of the materials increases. In particular in power plants, the superheater tubes are exposed to a corrosive abrasive attack that is one of the main sources of concern. The development of new alloys for multilayer surface, which combines corrosive and abrasive resistance is therefore of high importance. Those new technical approaches must be at the same time cost-effective to be an alternative to conventional materials. This paper presents the principle of experimental methods developed for the investigations of high temperature corrosion combined with abrasion in thermochemical processes with high hydrochloric acid concentrations like during biomass combustion. The aim of the presented investigation methods it to test and develop suitable alloys for coatings for the super heater tubes of biomass power plants. First results of abrasion investigations show improved abrasion resistance compared to the multi-component reference material Alloy 625.
Carbon Capture, Utilization and Storage (CCUS) has been proposed as a promising technology for the mitigation of CO2 emissions into the atmosphere from fossil-fuel-operated power generation plants. As the reliability and cost effectiveness of the pipeline transport network is crucial to the overall operability and resilience of the CCUS system, it is vital to realize the possible corrosion risks of the employed pipeline steels corresponding to the impurity level of the gas source.
Recent studies have shown that even the high alloyed materials might be susceptible to general and/or localized corrosion by the condensates forming from the impurities such as SOx, NOx, CO, O2 and water [1]. Up to now, however, there is no regulation procedure which defines the maximum acceptable level of impurities and the combination of them for each employed pipeline steels. Herein, systematic experiment series were conducted by mixing pure CO2 gas with varying concentration of each impurity and with the varying combination of them. Each time, the mixture was then fed (1 L/min) into the reactor containing 12 specimens for 120-600 h at 5°C (to simulate the sub-level pipeline transport). The resulted condensate was collected and analyzed by ionic chromatography and atomic absorption spectroscopy to determine the chemical composition. In this study, the “worst-case scenario” gas mixture, containing 2.5 % H2O, 1.8 % O2, 1000 ppm NO2, and 220 ppm SO2 as impurities, resulted in the condensate containing H2SO4 0.114 M and HNO3 0.0184 M (pH 2.13). This “original” condensate was then re-produced to carry out exposure tests and electrochemical characterization including corrosion potentials and impedance spectroscopy in CO2 saturated condition for 7-14 days at the same temperature. The corrosion rate was also measured by mass loss method.
We can conclude that, at the initial stage, HNO3 plays the dominant role in Fe dissolution process, while H2SO4 is responsible for the pit initiation followed by pitting corrosion. Future studies will be focused on the combination effect from the impurities and the exposure test under the regularly changing condensate to mimic the real CO2 pipeline system.
Properties of pipe steels for CCS (carbon capture and storage) technology require resistance against the corrosive environment of a potential CCS-site (heat, pressure, salinity of the aquifer, CO2-partial pressure). The influence of austenitzing in heat treatment routines of two different injection pipe Steels (1.4034, X46Cr13 and 1.4021, X20Cr13) was evaluated. Steel coupons were austenitized at different temperatures (900- 1050 °C) for different lengths of time (30-90 min) before quenching and annealing prior to long term corrosion experiments (60°C, 100 bar, artificial brine close to a CCS-site in the Northern German Basin, Germany). In general, fewer pits are found on X46Cr13. Comparing steels with 13% chromium each the higher carbon content of X46Cr13 (0.46% C) results in a lower number of pits compared to X20Cr13 (0.20% C). It is found that neither the carbon content of the steels nor austenitizing temperature has much influence, but local corrosion behaviour is most susceptible towards austenitzing time.
Properties of pipe steels for CCS (carbon capture and storage) technology require resistance against the corrosive environment of a potential CCS-site (heat, pressure, salinity of the aquifer, CO2-partial pressure). The influence of austenitzing in heat treatment routines of two different injection pipe steels (1.4034, X46Cr13 and 1.4021, X20Cr13) was evaluated. Steel coupons were austenitized at different temperatures (900-1050 °C) for different lengths of time (30-90 min) before quenching and annealing prior to long term corrosion experiments (60°C, 100 bar, artificial brine close to a CCS-site in the Northern German Basin, Germany). In general, fewer pits are found on X46Cr13. Comparing steels with 13% chromium each the higher carbon content of X46Cr13 (0.46% C) results in a lower number of pits compared to X20Cr13 (0.20% C). It is found that neither the carbon content of the steels nor austenitizing temperature has much influence, but local corrosion behaviour is most susceptible towards austenitzing time.