Filtern
Erscheinungsjahr
Dokumenttyp
Sprache
- Englisch (45) (entfernen)
Referierte Publikation
- ja (45) (entfernen)
Schlagworte
- Steel (17)
- Corrosion (16)
- CCS (14)
- CO2-storage (8)
- Pipeline (8)
- High temperature corrosion (7)
- Oxidation (4)
- Supercritical CO2 (4)
- Carbon capture and storage (3)
- Carbonate layer (3)
Organisationseinheit der BAM
- 5 Werkstofftechnik (14)
- 5.1 Mikrostruktur Design und Degradation (14)
- 5.6 Glas (2)
- 4 Material und Umwelt (1)
- 4.2 Material-Mikrobiom Wechselwirkungen (1)
- 5.2 Metallische Hochtemperaturwerkstoffe (1)
- 5.4 Multimateriale Fertigungsprozesse (1)
- 7 Bauwerkssicherheit (1)
- 7.6 Korrosion und Korrosionsschutz (1)
- 8 Zerstörungsfreie Prüfung (1)
We present a new method for the complete three-dimensional (3D) calibration of scanning probe microscopes (SPM) and other high-resolution microscopes, e.g., scanning electron microscopes (SEM) and confocal laser scanning microscopes (CLSM), by applying a 3D micrometre-sized reference structure with the shape of a cascade slope-step pyramid. The 3D reference structure was produced by focused ion beam induced metal deposition. In contrast to pitch featured calibration procedures that require separate lateral and vertical reference standards such as gratings and step height structures, the new method includes the use of landmarks, which are well established in calibration and measurement tasks on a larger scale. However, the landmarks applied to the new 3D reference structures are of sub-micrometre size, the so-called 'nanomarkers'. The nanomarker coordinates are used for a geometrical calibration of the scanning process of SPM as well as of other instrument types such as SEM and CLSM. For that purpose, a parameter estimation routine involving three scale factors and three coupling factors has been developed that allows lateral and vertical calibration in only one sampling step. With this new calibration strategy, we are able to detect deviations of SPM lateral scaling errors as well as coupling effects causing, e.g., a lateral coordinate shift depending on the measured height position of the probe.
With CO2 being one reason for climate change carbon capture and storage (CCS) is discussed to mitigate climate change. When emission gases are compressed into deep geological layers CO2-corrosion can easily cause failure of injection pipes. Different steels 42CrMo4, X46Cr13 and X20Cr13 were tested as well as X35CrMo17 and X5CrNiCuNb16-4 in a laboratory Environment similar to the conditions of the CCS engineering site at the Northern German Bassin. Samples were exposed to synthetic aquifer water saturated with technical CO2 at a flow rate of 3 NL/h.
Corrosion rates obtained via mass loss vary in a wide range (0,005 to 2.5 mm/year). The precipitations within the corrosion scale revealed a complicated multiphase layer containing siderite FeCO3, goethite α-FeOOH, lepidocrocite γ-FeOOH, mackinawite FeS and akaganeite Fe8O8(OH)8Cl1,34 and spinelphases of various compositions.
Comparative study on high temperature oxidation of T92 steel in dry and wet oxyfuel environments
(2015)
Fireside oxidation of T92 steel was studied after exposure times up to 1000 h in the temperature range of 580–650 °C in simulated dry (CO2–27 % N2–2 % O2–1 % SO2) and wet (CO2–20 % H2O–7 % N2–2 % O2–1 % SO2) oxyfuel environments. Water vapour addition to the oxyfuel gas substantially increased the oxidation rate. The oxide scales developed under wet environment contained more defects, resulting in higher access of oxidants to the substrate material and enhanced oxidation. In addition, the oxide scales had lower chromium enrichment in the inner layer as compared to that in the dry condition. The oxide scales consisted of hematite and magnetite in the outer layer and a mixture of (Fe, Cr)-spinel, sulphides and wustite in the inner layer. The sulphur distribution differed between the oxide scales developed in dry and wet oxyfuel environments. Sulphur was mainly concentrated in the inner layer and at the oxide/alloy interface. In contrast to the wet oxyfuel gas, very high sulphur concentration was measured in the inner oxide scale formed in the dry oxyfuel gas. Additionally, Fe-sulphide was formed at the interface of inner and outer oxide layer in the wet condition.
Static immersion tests of potential injection pipe steels 42CrMo4, X20Cr13, X46Cr13, X35CrMo4, and X5CrNiCuNb16-4 at T = 60°C and ambient pressure, as well as p = 100 bar were performed for 700–8000 h in a CO2-saturated synthetic aquifer environment similar to CCS sites in the Northern German Basin (NGB). Corrosion rates at 100 bar are generally lower than at ambient pressure. The main corrosion products are FeCO3 and FeOOH with surface and local corrosion phenomena directly related to the alloy composition and microstructure. The appropriate heat treatment enhances corrosion resistance. The lifetime reduction of X46Cr13, X5CrNiCuNb16-4, and duplex stainless steel X2CrNiMoN22-5-3 in a CCS environment is demonstrated in the in situ corrosion fatigue CF experiments (axial push-pull and rotation bending load, 60°C , brine: Stuttgart Aquifer and NGB, flowing CO2: 30 L/h, +/- applied potential). Insulating the test setup is necessary to gain reliable data. S-N plots, micrographic-, phase-, fractographic-, and surface analysis prove that the life expectancy of X2CrNiMoN22-5-3 in the axial cyclic load to failure is clearly related to the surface finish, applied stress amplitude, and stress mode. The horizontal grain attack within corrosion pit cavities, multiple fatigue cracks, and preferable deterioration of austenitic phase mainly cause fatigue failure. The CF life range increases significantly when a protective potential is applied.
The most efficient construction materials for boiler water walls and superheaters in steam power plants are ferritic and martensitic steels. In practical operation, tubes are exposed simultaneously to combustion gas and air/steam on their opposite surfaces. The corrosion behavior of ferritic-martensitic steels under such dual atmospheres is nondistinctive and has been investigated in a specially designed test equipment between 500°C and 620°C. The power plant conditions were simulated with a flowing and pressurized (80 bar) combustion gas on the inner side of the tube, which contains water (H2O) and carbon dioxide (CO2). On the outer side, tube material was exposed to air. Oxides that formed on the air side under dual atmosphere conditions were significantly different from the oxide scales formed when the alloy was exposed to air only. It is assumed that the anomalous corrosion behavior during the dual atmosphere exposure is due to hydrogen and carbon diffusion through the bulk alloy from the combustion gas side to the air side. Both species are produced when the material reacts with the gas phase. Because of its high diffusivity, hydrogen is thought to affect the corrosion process on the air side from the beginning of the corrosion exposure, whereas carbon reaches the opposite side after a considerably longer time period.
The process chain for Carbon Capture and Sequestration (CCS) includes tubing for injection of CO2 into saline aquifers. The compressed CO2 is likely to contain specific impurities; small concentrations of SO2 and NO2 in combination with oxygen and humidity are most harmful. In addition, CO2 saturated brine is supposed to rise in the well when the injection process is interrupted. The material selection has to ensure that neither CO2 nor brine or a combination of both will leak out of the inner tubing. In this comprehensive paper the investigated materials range from low-alloy steels and 13% Cr steels up to high-alloy materials. Electrochemical tests as well as long term exposure tests were performed in CO2, in brine and combination of both; pressure was up to 100 bar, temperature up to 60 °C. Whereas the CO2 stream itself can be handled using low alloy steels, combinations of CO2 and brine require more resistant materials to control the strong tendency to pitting corrosion. The corrosion behavior of heat-treated steels depends on factors such as microstructure and carbon content. For different sections of the injection tube, appropriate materials should be used to guarantee safety and consider cost effectiveness.
Steels used within the process chain of carbon capture and storage (CCS) are exposed to conditions that are currently not fully tested. In the present work a number of steels were selected as possible construction materials: Alloyed steels for application in the compression and injection sections and low alloyed carbon steels for use as pipelines. Exposure tests were conducted over 600 hours at ambient pressure in a continuous flow of a simulated gas stream consisting of carbon dioxide with low contents of the relevant flue gas components nitrogen dioxide, sulfur dioxide, carbon monoxide, oxygen and water. Temperatures were adjusted to 5, 60 and 170 centigrade.
When emission gasses are compressed into deep geological layers (CCS) CO2-corrosion of injection pipe steels is a relevant safety issue. The reliability of the steels used at the geological onshore CCS-site at Ketzin, Germany, is demonstrated in 2 years laboratory experiments under an equivalent corrosive environment at ambient pressure (T=60 °C, aquifer water, CO2-flow rate of 3 l/h). Corrosion kinetics and microstructures were characterized using samples of the heat treated steel 42CrMo4 (casing), and samples of the martensitic stainless steel X46Cr13 (injection).