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Organisationseinheit der BAM
Integrated Coating System for Corrosion Protection of Carbon Steel in Artificial Geothermal Brine
(2022)
Corrosive geothermal brines are a major challenge to geothermal power-plants. For cost reasons, plant designers prefer to use carbon and low alloyed steels, which are susceptible to uniform and localized corrosion when exposed to geothermal brines having acidic and saline properties. To solve such problem, coatings or inhibitors would be a protective solution as an alternative to the use of high alloyed materials.
This study investigated a coating system consisting of polyaniline/silicon dioxide based on resources locally available in Indonesia. Protection against corrosion of carbon steel was shown by long-term (28 day) exposure and electrochemical tests of coated carbon steels, performed in an artificial acidic and saline geothermal brine, comparable to the conditions encountered at a site in Indonesia.
Therefore, an integrated coating system is proposed for corrosion protection, combining the electrochemical functionality of polyaniline and the physical advantages of silica.
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.
CCUS-Technologie (CO2-Abtrennung; Nutzung und Speicherung, engl. Carbon Dioxide Capture, Utilization and Storage) gilt als eine vielversprechende Methode zur Abschwächung des Beitrags von fossilen Emissionen zur globalen Erwärmung. Dabei wird das in den Verbrennungsprozessen entstandene Treibhausgas aufgefangen, zu verschiedenen Lagerstätten transportiert und langzeitig gespeichert bzw. einer chemischen Nutzung zugeführt.
In bisher veröffentlichten Untersuchungen wurde gezeigt, dass die CO2-Transport-Pipelines in hohem Maße gefährdet sind, wenn sie korrosiven Begleitstoffen des CO2-Stroms, wie SOx, NOx bei einem hohen Wasserdampfanteil ausgesetzt sind. Screening-Tests zeigten, dass bei einer Konzentration von 1000 ppmv H2O die Reaktionen und Kondensation von SO2 und NO2 mit O2 und H2O zu Säuretropfen (pH ~ 0,5) auf der Oberfläche von Metall-Prüfkörper und Gefäß führen. Die Werkstoffe 1.0582, 1.8977, 1.4313 und 1.4562 wurden in CO2-gesättigtem Kondensat mit unterschiedlichem Verhältnis der säurebildenden Komponenten untersucht. Diese Studien zeigten grundsätzlich den Mechanismus sowie die Rolle jedes CO2-Strom-Begleitstoffes auf den Korrosionsprozess. Allerdings spiegeln die bei Auslagerung und elektrochemischen Messungen in der künstlichen CO2-gesättigten Kondensat-Lösung auftretenden Bedingungen nicht im Detail die Realität in der Praxis, wo sich nur Tröpfchen bilden, wider.
Diese Arbeit konzentriert sich auf den Korrosionsprozess von Kondensat in Form von Tröpfchen, auf der Oberfläche von Rohrleitungswerkstoffen unter CO2-Atmosphäre bei 5 °C (Simulation des Transportzustandes). Die Experimente wurden nicht nur für Auslagerungsversuche, sondern auch für elektrochemische Tests mit nur einem Tröpfchen (weniger als 20 µL) konzipiert. Die Auslagerungs-versuche wurden sowohl unter Normaldruck als auch bei hohem Druck (> 70 bar) durchgeführt, wobei das CO2 als dichte – den Tropfen umgebende - Phase vorliegt. Die korrodierten Prüfkörper wurden rasterelektronenmikroskopisch (REM) und mittels Energiedispersiver Röntgenspektroskopie (EDX) analysiert, um nicht nur Korrosionsform, sondern auch die Elementverteilung der Korrosionsprodukte zu zeigen.
Synergistic effects of impurities in the condensate on the corrosion of CO2 transport pipeline
(2017)
For the reliability of transport pipelines the corrosion resistance of the materials used needs to be determined in conditions, which are possible during the transport process. In some situations condensation of components out of the CO2 stream can occur. To study the effect of condensate on transport pipeline steel, a “worst-case scenario” gas mixture, containing 2.5 % H2O, 1.8 % O2, 1000 ppmv NO2, and 220 ppmv SO2, was proposed, fed (1.5 L/min) into a glass reactor containing coupon-shaped specimens for 120 600 h at 278 K (to simulate the underground pipeline transport), and resulted in the condensate containing 0.114 M H2SO4 and 0.0184 M HNO3 (pH 2.13). Basing on this “original” condensate, exposure tests and electrochemical characterization together with pH and conductivity in CO2 saturated condition at the same temperature were carried out. The role of each gas impurity and the combination of them, when the condensate is formed, was studied by investigating the role of individual and varying combination of acidic components in the condensate on the corrosion behaviors of the commercial pipeline-steel (L360NB). It can be concluded that although the condensation of NOx in form of HNO3 causes faster corrosion rate, it is the condensation of SOx or the combination of SOx and NOx that may cause much more severe problems in form of localized and pitting corrosions. Different to the corrosion products formed in CO2 atmosphere without impurities (mainly iron carbonate) the corrosion products resulted from these acidic condensation have no protectability, indicating the need of controlling gas quality during the transportation within the pipeline network.
Carbon Capture Utilization and Storage (CCUS) is a promising technology for the reduction of CO2 emissions, e.g. from fossil-fuel operated power plants or cement mills. Crucial points for a sustainable and future-proof CCUS procedure are reliability and cost efficiency of the pipeline transport network. Due to the absence of certified benchmarks for upper limits, systematic experiments with impurities in the CO2 stream were carried out. For oxidation processes SO2 and NO2 acted as corrosive components, and for reductive atmosphere H2S. Carbon steel L485MB (pipeline), martensitic steel 1.4313 (compression) and austenitic steel 1.4562 (injection) were selected as specimens. Experiments were performed at 0 bar or 100 bar and within a temperature range 278 K ≤ T ≤ 313 K. High-alloyed Cr-Ni steels revealed no corrosion (1.4562, 1.4313), while for carbon steel considerable corrosion was observed. The type and intensity of corrosion was strongly coupled with the applied corrosive species and the level of humidity in the CO2 stream, leading to different compositions of acidic condensates. Applying a reducing atmosphere results in very little corrosion rates, but provokes pitting corrosion. In contrast, oxidizing or mixed settings lead to a clearly increased growth of the corrosion layer, but exhibit shallow uniform corrosion. Exceptional nitric acid results in intergranular corrosion. Investigations on the specimens were carried out by optical microscopy, XRD, SEM/EDX, and AAS/IC.
According to the results of the experiments carried out, the following points can be concluded:
1. Exposure tests showed that specimens with the addition of SiO2 particles and polyaniline particles exhibit better corrosion resistance than specimens with the addition of only polyaniline particles or binder only.
2. Open circuit potential measurements showed that in the beginning of the experiments, both coatings had an open circuit potential 100 mV higher than carbon steel. Within one day of immersion, the potential of carbon steel increased significantly, indicating the formation of oxide layer. After extended exposure the carbon steel potential sat between PS1 (which had higher potential) and PS2 (which had a lower potential) and all three were in the range –600 mV to –500 mV vs Ag/AgCl.
3. Both coatings PS-1 and PS-2 were degraded with increasing exposure time, shown by the decrease of absolute impedance value at low frequency range after 2, 4, and 6 days exposure.
4. Potentiodynamic test was performed after 3 hours and 6 days exposure, and it was shown that the coating in the initial stage exhibited more passive behavior than the specimens exposed for 6 days.
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.
This work examined the droplet corrosion of CO2 pipeline steels caused by impurities in CO2 supercritical/dense phase at 278 K, simulating the underground transport condition. The wetting properties of carbon steels (X52 and X70) as well as martensitic steel UNS S41500, and superaustenite UNS N08031 were studied by contact angle measurement, revealing reactive wetting behavior of carbon steels. 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 coupons in supercritical/dense phase condition, forming the corrosion product instantly during pumping process. Due to the active wetting behavior, the carbon steels suffered from heavily attack, while negligible corrosion product was observed in cases of martensitic steel UNS S41500 and superaustenite UNS 08031 coupons. Condensation experiments that were carried out on fresh polished coupons in CO2 with 1200 ppmv H2O showed that the formation and aggregation of droplet is dependent on the presence of impurities. Without SO2 and O2, the same concentration of H2O did not cause observable corrosion process after a week of exposure. With 220 ppmv SO2 and 6700 ppmv O2 even low water concentration (5-30 ppmv) still resulted in heterogeneous nucleation and subsequent growth of droplets, leading to corrosive process on carbon steel surface albeit to a lesser extent.
In this work, the focus was set on the corrosion process of condensate as drops on the surface of carbon steels (X52, X70), martensitic steel UNS S41500, and superaustenite UNS N08031 in CO2 atmosphere with impurities at 278 K (to simulate the transportation condition in a buried pipeline). Exposure tests were performed at both normal pressure and high pressure where CO2 is supercritical or in dense phase. The drop, 1 ‑ 10 μL in volume, was prepared by dropping CO2 saturated ultra-pure water onto the surface of steel coupons in a one-liter-autoclave. The CO2 gas stream, simulating the oxyfuel flue gas with varying concentration of impurities (SO2 and O2 ), was then pumped into the autoclave to observe the condensation and corrosion impacts of impurities. Comparable exposure tests were carried out with the same gas mixture and the same volume of water as vapor to observe the drop formation and the corrosion process that follows. The wettability and stability of drops on the surface of steel coupons in CO2 supercritical/dense phase environment was evaluated additionally by contact angle measurement.
Geothermal energy is one of the most promising energy resources to replace fossil fuel. To extract this energy, hot fluids of various salts and gases are pumped up from a geothermal well having a certain depth and location. Geothermal wells in volcanic regions often contain highly corrosive CO2 and H2S gases that can be corrosive to the geothermal power-plants, which are commonly constructed of different steels, such as carbon steel. This research focuses on the corrosion behaviour of carbon steel exposed to an artificial geothermal fluid containing CO2 gas, using an artificial acidic-saline geothermal brine as found in Sibayak, Indonesia. This medium has a pH of 4 and a chloride content of 1,500 mg/L. Exposure tests were conducted for seven days at 70 °C and 150 °C to simulate the operating temperatures for low and medium enthalpy geothermal sources. Surface morphology and cross-section of the specimens from the above experiments were analysed using scanning electron microscope (SEM) and energy dispersive X-ray (EDX). Electrochemical tests via open circuit potential (OCP) and electrochemical impedance spectroscopy (EIS) were performed to understand the corrosion processes of carbon steel in CO2-containing solution both at 70 °C and 150 °C. Localized corrosion was observed to a greater extent at 70 °C due to the less protectiveness of corrosion product layer compared to that at 150 °C, where FeCO3 has a high corrosion resistance. However, a longer exposure test for 28 days revealed the occurrence of localized corrosion with deeper pits compared to the seven-day exposed carbon steel. In addition, corrosion product transformation was observed after 28 days, indicating that more Ca2+ cations incorporate into the FeCO3 structure.