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Carbon Capture and Storage (CCS) is identified as an excellent technology to reach the target of CO2 reduction. However, the safety issue and cost-effectiveness hinder the future of CCS. For the reliability and safety issues of injection wells, the corrosion resistance of the materials used needs to be determined.
In this study, representative low-cost materials including carbon steel 1.8977 and low alloyed steel 1.7225 were investigated in simulated pore water at 333 K and under CO2 saturation condition to represent the worst-case scenario: CO2 diffusion and aquifer fluid penetration. These simulated pore waters were made from relevant cement powder to mimic the realistic casing-cement interface. Electrochemical studies were carried out using the pore water made of cement powder dissolved in water in comparison with those dissolved in synthetic aquifer fluid, to reveal the effect of cement as well as formation water on the steel performance. Two commercially available types of cement were investigated: Dyckerhoff Variodur® and Wollastonite. Variodur® is a cement containing high performance binder with ultra-fine blast furnace slag which can be used to produce high acid resistance concrete. On the other hand, Wollastonite is an emerging natural material mainly made of CaSiO3 which can be hardened by converting to CaCO3 during CO2 injection.
The results showed the pH-reducing effect of CO2 on the simulated pore water/aquifer (from more than 10 to less than 5) leading to the active corrosion process that happened on both 1.8977 and 1.7225. Electrochemical characterization showed negative free corrosion potential and polarisation curves without passive behaviors. The tested coupons suffered from pitting corrosion, which was confirmed by surface analysis. Interestingly, basing on the pit depth measurements from the tested coupons and the hardness of cement powder, it is suggested that Variodur® performed better than Wollastonite in both aspects. The electrochemical data was compared to that resulted from exposure tests to give a recommendation on material selection for bore-hole construction.
Electrochemical deposition of polyaniline on carbon steel for corrosion study in geothermal solution
(2019)
Polyaniline has been widely developed for many applications, e.g. sensor, supercapacitor components, electrochromic devices, and anticorrosion pigments. Although the addition of polyaniline pigment in organic coatings has been an alternative for corrosion protection in industrial applications, the protection mechanism is still not fully understood. Herein in this study, as a part of the development of polyaniline/silicon dioxide coating for geothermal application, polyaniline has been deposited electrochemically on carbon steel surface in oxalic acid medium and tested in geothermal solution to understand the contribution of polyaniline to the corrosion protection of a polyaniline-based composite in the geothermal system. To observe the surface/interface reaction between the electrolyte and electrode surface during the electrochemical polymerization, electrochemical impedance spectroscopy (EIS) was applied after each cycle. For corrosion study in the geothermal application, an artificial geothermal solution was used with the composition of 1,500 mg/l Cl⁻, 20 mg/l SO₄²⁻, 15 mg/l HCO₃⁻, 200 mg/l Ca²⁺, 250 mg/l K⁺, and 600 mg/l Na⁺, and pH 4 to simulate a geothermal brine found in Sibayak, Indonesia. An electrochemical measurement was performed by monitoring the open circuit potential over seven days, with the interruption by EIS every 22 hours. The experiments were performed at room temperature and 150 °C (1 MPa) in an oxygen-free environment. Impedance spectra showed a reduction of the total impedance value of approximately 10 times for specimens measured at 150 °C compared to the specimens measured at room temperature, suggesting a less stable layer at high temperature.
This contribution provides current findings regarding materials susceptibility for carbon capture, utilization and storage (CCUS) applications. Basing on results gathered in 2 German long-term projects (COORAL and CLUSTER) suitable materials are introduced as well as dominating impurities of the CO2-stream and corrosion mechanisms. Investigations cover the whole CCUS process chain and provide material recommendations for certain parts.
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.
Specific amounts of oxidizing and reductive impurities as well as some moisture were added to dense phase CO2 to replicate CO2 streams from sources in a CCS pipeline network. Due to the moisture content being only 50 ppmV no visible acid condensation took place. To simulate stress conditions at the inside pipeline surface due to fluid pressure (10 MPa) specimens were preloaded using a load frame. Experiments conducted at 278 K and at 313 K revealed the highest corrosion rate at lower temperature. Corrosive effect of impurities was strongest applying mixed atmosphere, containing oxidizing and reductive components, closely followed by CO2 streams with pure oxidizing character. By far, the lowest corrosion rate (10x lower) resulted from reductive atmosphere. In general, at constant temperature and pressure the CO2 stream composition strongly influences the morphology, thickness and composition of the corrosion products. Applying oxidizing or mixed impurities, iron hydroxides or oxides (e.g. goethite, hematite) occur as dominating corrosion products, capable to incorporate different amounts of sulfur. In contrast, using reductive atmosphere very thin corrosion layers with low crystallinity were developed, and phase identification by XRD was unfeasible. SEM/EDX analysis revealed the formation of Fe-O compounds, most likely attributed to the oxygen partial pressure in the system induced by CO2 (≥0.985 volume fraction) and volatile H2O. In addition to the surface covering corrosion layer, secondary phases had grown locally distributed on top of the layer. These compounds are characteristic for the applied atmosphere and vary in number, shape and chemical composition.
Al2O3 coatings are often used as protective layers on steels against electrochemical and high-temperature corrosion because they are chemically inert and stable at elevated temperatures. This study presents preliminary work on the possibilities of using Al2O3 sol-gel coatings for corrosion protection of martensitic stainless steels in geothermal environments. Al2O3 sol-gel coatings were applied on UNS S42000, which is known to be susceptible to uniform and localized corrosion. The coated steel specimens were then tested in two types of artificial geothermal water, which simulate the geothermal fluids found in Sibayak (SBY), Indonesia, and North German Basin (NGB), Germany, respectively. SBY has pH 4 and 1.5 g/L of chloride ions, whereas NGB has a pH of 6 and 166 g/L of chloride ions. All experiments were carried out in autoclaves at 150 °C and 1 MPa under the deaerated condition. Evaluations were performed by investigating the surface profiles of both uncoated and coated steels before and after the corrosion test using a Laser Scanning Microscope (LSM) and Scanning Electron Microscope (SEM). Finally, Electrochemical Impedance Spectroscopy (EIS) was performed to compare the corrosion resistance of Al2O3 coated steels in SBY and NGB solutions. It was observed from the corrosion test that Al2O3 coatings are more suitable for use in the geothermal water with a higher pH.
Nachdem im Verbundprojekt COORAL das Hauptaugenmerk auf überkritisches CO2 gelegt wurde, d. h. Transport über kurze Strecken bei erhöhter Temperatur, wurde in CLUSTER ein größeres lokales Transport-Netzwerk betrachtet, bei dem CO2 bei geringeren Temperaturen, also vorwiegend im flüssigen Zustand transportiert wird. Wurden in COORAL die CO2-Ströme von Kohlekraftwerken untersucht, ging es in CLUSTER zusätzlich um die Emissionen von relevanten Industrien, deren CO2-Emissionen nicht ohne Weiteres vermieden werden können.
Aufgrund der Erfahrungen in COORAL konnte eine Auswahl von kommerziellen Werkstoffen getroffen werden, die für einen konkreten Einsatz für CCS zur Verfügung stünden. Die gemischten und fluktuierenden CO2-Zusammensetzungen sind bei geeigneten Begrenzungen der Begleit¬stoffe im CO2 bezüglich Korrosionsvorgänge beherrschbar. Die Machbarkeit eines lokalen CCS-Clusters erscheint daher gegeben, soweit dies die Anlagen für Kompression, Transport und Injektion betrifft.
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.
Carbon Capture and Storage (CCS) is identified as an excellent technology to reach the target of CO2 reduction. However, the safety issue and cost effectiveness hinder the future of CCS. For the reliability and safety issues of injection wells the corrosion resistance of the materials used needs to be determined.
In this study, representative low cost materials including carbon steel 1.8977 and low alloyed steel 1.7225 were embedded in cement to mimic the realistic casing-cement interface. Electrochemical studies were carried out using these metal-cement specimens in comparison with those made of metal only in CO2 saturated synthetic aquifer fluid, at 333 K, to reveal the effect of cement on the steel performance. The results showed the protective effect of cement on the performance of pipeline metals during polarisation process. However, the corrosion current density was high in all cases, with and without cement, indicating that the corrosion resistance of these materials is low. This conclusion was supported by the surface analysis of the polarized specimens, which revealed both homogenous and pitting corrosions.
To study the effects of condensed acid liquid, hereafter referred to as condensate, on the CO2 transport pipeline steels, gas mixtures containing a varying concentration of H2O, O2, NO2, and SO2, were proposed and resulted in the condensate containing H2SO4 and HNO3 with the pH ranging from 0.5 to 2.5. By exposing the pipeline steel to the synthetic condensate with different concentration of acidic components, the corrosion kinetic is significantly changed. Reaction kinetic was studied using electrochemical methods coupled with water analysis and compared with surface analysis (scanning electron microscopy (SEM), energy-dispersive X-ray spectroscopy (EDS), and X-ray diffractometry (XRD)) of corroded coupons. The results showed that, although the condensation of NO2 in the form of HNO3 causes faster general corrosion rate, it is the condensation of SO2 in the form of H2SO4 or the combination of SO2 and NO2 that may cause much more severe problems in the form of localized and pitting corrosions. The resulting corrosion forms were depended on the chemical nature of acids and their concentration at the same investigated pH. The effects of changing CO2 flow rate and renewing condensate on pitting corrosion were further studied.