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Metal sulfide grain boundary precipitates of a ferrous model alloy with 13 wt.% chromium formed at 650°C under a gas atmosphere containing 0.5% SO2 and 99.5% Ar were investigated after ageing for 3 h, 6 h, and 12 h. The precipitates formed along grain boundaries were identified as Cr5S6 using energy-dispersive x-ray spectroscopy in transmission electron microscopy and electron backscatter diffraction analysis. Serial focused ion beam slicing was conducted followed by three-dimensional reconstruction to determine the number, size, and penetration depth of the precipitates evolved at the different time steps. There was a linear increase in the number of precipitates with time, while their average size increased only for the initial aging time but became constant after 6 h. Based on these results, a model for grain boundary sulfidation of ferritic alloys is discussed.
To increase efficiency, modern steam plants are pushing their operational regime from super-critical (600 °C/300 bar) to ultra-super-critical (740/760 °C/350 bar) stretching existing turbine materials to their limits. The focus is on new generation functional materials and technologies which complement the inherent properties of existing materials.
Current work proposes a novel High Power Impulse Magnetron Sputtering (HIPIMS) Deposition technology, for the first time, for deposition of a ceramic based CrN/NbN coating with a nanoscale multilayer structure (bi-layer thickness Δ = 1.9 nm) with superior adhesion (LC2 = 80 N) to protect low Chromium P92 steel widely used in steam power plants. Thermodynamic calculations predict the equilibrium phases and aggressive gaseous compounds generated by the interaction of steam with the coating. CrN/NbN coated P92 steel samples oxidised at 600 °C in a high pressure (50 bar) 100% steam atmosphere for up to 1000 h reveal the coating's superior oxidation resistance and protective mechanisms, especially against the detrimental effect of Hydrogen. High temperature (650 °C) Tensile Strength, Low Cycle Fatigue and Creep tests confirm that, unlike other state-of-the-art PVD technologies, HIPIMS is not detrimental to the mechanical properties of the substrate material. Water droplet erosion tests confirm no measurable weight loss after 2.4 X 10⁶ impacts.
Insights into early damage mechanisms during high-temperature gas corrosion provide important aspects for the prediction of the long-term stability of hightemperature materials exposed to a hot and corrosive environment. The current work presents a real time study concerning the combined oxidation and sulfidation of ferritic model alloys in a hot SO2 containing atmosphere using energy dispersive X-ray diffraction. The applied high temperature reactor allows the transmittance of high energetic X-rays in order to collect X-ray diffraction pattern of the sample surface in situ during the reaction with the reactive environment. The results revealed that the first phases crystallizing on iron with 2 wt% chromium and with 9 wt% chromium are oxides. The aging experiments at T = 650° C with 0.5% SO2 and 99.5% Ar were followed in situ and caused an external mixed oxide-sulfide layer on top of iron with 2 wt% chromium. On the higher alloyed material the external scale consists of iron oxides and the inner scale of mixed (Fe,Cr)-oxides and chromium-sulfides. The oxide content continuously increases parallel to an increase of the sulfide amount. Thus, the initially formed (Fe,Cr)-oxides do not have a protective character and support the transport of sulfur through the growing oxide scale.
Comprehensive insights into the early stages of corrosion mechanisms provide fundamental knowledge to further understand and model long time material behaviour. The present work studies the early stages of combined oxidation and sulphidation of ferritic model alloys for time scales up to 250 h at 650 °C to observe the influence of chromium during the corrosion under SO2. Model alloys were used to focus on the reaction of the intended elements: Fe, Cr, S, and O. Pure iron simultaneously forms magnetite and iron sulphide in an early stage of corrosion, covered by a pure oxide layer after 100 h. Iron with 13 wt% Cr shows hematite and mixed Fe-Cr-oxides first, before sulphides nucleate in the inner corrosion zone. With increasing ageing time a magnetite layer is observed below the hematite layer. Quantitative phase fractions of all corrosion products observed were determined from cross section images. Characterization of the Fe13Cr corrosion scale by FIB revealed a highly porous structure in the inner corrosion zone where Cr-rich (Fe, Cr)-sulphides are present, and caused the scale to spall easily.
Thin Sol-Gel Alumina Coating as Protection of a 9% Cr Steel Against Flue Gas Corrosion at 650 °C
(2018)
Samples of sol-gel alumina coated and uncoated P92 steel were exposed to flue gas at 650 °C for 300 h. As result of this treatment a 50 µm thick bi-layered oxide scale had formed on the surface of the uncoated sample. Below the scale a 40 µm thick inner oxidation zone was detected. In contrast, the porous, micron thick alumina coating enabled the formation of a chromium oxide scale with a thickness of some nanometers at the interface between steel substrate and coating. In this case high temperature corrosion of the steel was prevented so far.
X5CrNiCuNb16-4 has been proven to be sufficient resistant in corrosive environments, but shows rather unusual corrosion behaviour in CCS environment. Therefore a series of 30 specimens was tested at stress amplitudes between 150 MPa and 500 MPa (sinusoidal dynamic test loads, R=-1; resonant frequency ∼ 30 Hz). Due to the rather heterogeneous fine machined surfaces (Rz=4) the specimens are comparable with prefabricated parts. X5CrNiCuNb16-4 reached the maximum number of cycles (10 x 106) at a stress amplitude of 150 MPa and lies 60% below the stress amplitude measured in air. The scatter range TN = 1:34 is disproportionately large. Although the fracture surface exhibited the typical striations and corroded surface areas no significant differences were found. The hardness was found to be homogeneous in all specimens tested at 335 HV10. Non-metallic inclusions were found within the microstructure, but no correlation could be found between the inclusions and early rupture. Still specimens that showed inclusions at the fracture surface and its cross section endured lower number of cycles. Additionally Aluminium was analysed in specimens with low number of cycles and may be cause for early rupture during corrosion fatigue tests. These findings reveal a very high sensitivity on a homogeneous microstructure upon the corrosion and corrosion fatigue behaviour of X5CrNiCuNb16-4 and needs to be taken into account when regarding this steel as pipe steel during injection of CO2 into saline aquifers.
Unusual Corrosion Behavior of 1.4542 Exposed a Laboratory Saline Aquifer Water CCS-Environment
(2017)
Differently heat treated coupons of 1.4542 were kept at T=60 °C and ambient pressure as well as p=100 bar for 700 h - 8000 h in an a) water saturated supercritical CO2 and b) CO2-saturated synthetic aquifer environment similar to on-shore CCS-sites in the Northern German Basin. Surface corrosion layers are homogeneous but unusually discontinuously ellipsoidal. After 8000 h at 100 bar maximum corrosion rate in the liquid phase is approximately 0.014 mm/year, with normalizing providing best corrosion resistance and approximately 0.003 mm/year in the supercritical phase where hardening+tempering at 670 °C leads to lowest corrosion rates.
In coal-fired power plants using oxyfuel combustion process with carbon capture and sequestration, instead of air, a mixture of oxygen and recirculated flue gas is injected in the boiler. A series of steels were exposed to CO2-SO2-Ar-H2O gas mixtures at 600 °C for 1000 h to compare their high temperature corrosion behavior. During the corrosion process, carburization, decarburization and recrystallization were observed underneath the oxide scale depending on the gas mixture and alloy composition. The conditions that lead to carburization are not yet completely understood, but decarburization can be simulated using thermodynamic and kinetic models. In this work, the results of these simulations are compared with measured values for one of the alloys that displayed a decarburized region. Since the mobility of carbon in the scale is not known, two strategies were adopted: simulation of alloy-atmosphere contact; and estimation of the carbon flux to produce the observed decarburization. The second approach might give an insight on how permeable to carbon the scale is.
Microstructure, smoothening effect, and local defects of alumina sol-gel coatings on ground steel
(2017)
Porous alumina films with thicknesses of a few microns were prepared via a dip-coating technique on steel P92. The coating is shown to protect the steel against massive corrosion, which is typical in the hot reactive environment of coal fired power plants. To mimic real conditions ground steel plates were coated with a boehmite-sol. This leads to an overall smoothing of the formerly rough surface. In the following short annealing step the inner porous construction with worm-like particles consisting of nano-crystallites and amorphous alumina is formed. Due to the simultaneous diffusion of chromium and iron ions out of the bulk steel material into the porous alumina coating, a dense interface with satisfactory adhesion is formed. However, the film exhibits few local defects like cracks or dense alumina nodules caused by steep edges in the ground surface or agglomeration of boehmite-sol components, respectively. Cracks especially have to be avoided. This problem can be overcome so far by slight modifications in the sol preparation process and surface treatment of the substrates. Nevertheless the results demonstrate the potential of sol-gel based alumina coatings as a time- and cost-saving protection type for commercial steel P92.
The paper presents the microstructure, chemical and phase composition of thin scale, obtained as a result of high temperature corrosion of X20Cr13 stainless steel. Samples were exposed to gas atmosphere of the following composition: 0.25 vol.% of SO2 and 99.75 vol.% of Ar at 600 °C for 5 h. As a consequence, thin compact scale was formed on steel surface.
This scale consisted of three different zones. An amorphous zone was formed close to steel surface. Then, nanocrystalline Zone could be observed. Finally, larger grains were formed during the corrosion process. The analysis of the chemical composition revealed higher concentration of chromium near steel surface. In contrast, to chromium, the content of iron, increased near the scale surface. It was found out that the (Cr, Mn, Fe)5O12 phase appeared in the thin scale.
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.
The materials in oxyfuel power plant will be subjected to CO2– and SO2–rich gases on the fireside. The oxidation behaviour of two 9–12 % Cr steels T92 and VM12 was studied under dry oxyfuel environment in the temperature range of 580–650 °C for up to 1,000 h. The oxide structure and morphology were analyzed using various experimental techniques. A complex temperature dependence of oxidation rate is observed for both T92 and VM12 whereby the oxidation rate decreased with increasing temperature. This is attributed to increased Cr-enrichment in the inner scale with increasing temperature. T92 and VM12 alloys are also susceptible to carburization in an oxyfuel environment.
In corrosive environments such as CCS bore holes or geothermal power plants the materials loaded cyclically are also exposed constantly to the highly corrosive hot thermal water. The lifetime reduction of (X46Cr13, AISI 420C) is demonstrated in in-situ-laboratory experiments (T=60 °C, geothermal brine: Stuttgart Aquifer flow rate: 9 Nl/h, CO2). S-N plots, micrographic-, phase-, fractographic- and surface analysis were applied to obtain sustainable information on the corrosion fatigue behavior. Maximum number of cycles (here 12.5 x 106 cycles to failure) is reached at σa =173 MPa. No typical fatigue strength exists and passive corrosion fatigue is most likely failure cause.
Transmission of captured CO2 in pipelines is an essential part of the carbon capture and sequestration process chain. Dependent of the fuel, the combustion process and the capture technology the resulting gas contains impurities that might cause corrosion effects in pipelines constructed of low alloyed steels. Corrosion testing under simulated conditions therefore is a prerequisite for the installation of reliable and safe CCS systems. Sulfur and nitrogen oxides together with water vapor form corrosive acids. Their behaviours and corrosive effects in static pressurized experiments were critically investigated in the present study. The results indicate that experimental limitations might influence the predictive capability of corrosion tests with sulfur dioxide. The limited supply of corrosive constituents in static test might lead to an underestimation of the corrosion risk.
The need for a more efficient coal power plant generation (e.g. oxyfuel technology) results in modified process parameters and enhanced corrosion. To reach the necessary service life of high temperature parts protective coatings may be a sufficient technical solution. A modified Yoldas sol (Al2O3 based) was used to coat X20CrMoV12-1 by spin coating. After appropriate heat treatments transition alumina coatings being about 400 nm thick were obtained. Oxidation studies were carried out in laboratory air at temperatures up to 650 °C for up to 500 h exposure time. In case of the uncoated sample a rough oxide layer formed on the surface and a remarkable weight gain (2.62 mg/cm²) were detected. The sol–gel alumina layer (mainly δ-Al2O3) demonstrated a high protection, i.e. a very low weight gain (0.05 mg/cm²). Diffusion of alloying elements into the coating was observed. No indication of spallation of the coating occurred. Local defects (2 µm–30 µm) in the coating led to the formation of iron-oxide islands.
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.
Materials testing under mechanical stress, pressure and turbulent flow of impure supercritical CO2
(2013)
The climate change necessitates measures to reduce carbon dioxide (CO2) emissions in the atmosphere, one of which is carbon dioxide capture and storage (CCS). Transmission of pressurized liquid or supercritical CO2 containing residual flue gas constituents in pipelines is an important component of CCS systems. Material testing under conditions as close as possible to real conditions is a prerequisite for reliable and safe implementation of CCS. A novel pipeline corrosion test facility was developed, accounting for major mechanical, physical and chemical influencing factors: elastic deformation, pressure, temperature, gas composition and flow velocity can be independently adjusted. Radial and tangential stress distributions on a round sample were experimentally investigated, indicating a good accordance with expected theoretical values. In this contribution the idea of the novel corrosion test facility and the assembled equipment as well as first results are presented and discussed.----------------------------------------------------------------------------------------------------Die Klimaveränderung macht Maßnahmen zur Reduktion von Kohlendioxidemission (CO2) in die Atmosphäre erforderlich, Rückhalt und Speicherung in tiefen geologischen Formationen (carbon capture and storage (CCS)) stellt eine davon dar. Der Transport von verflüssigtem oder superkritischem CO2 mit Verunreinigungen in Pipelines stellt einen wichtigen Teil von CCS-Systemen dar. Die Materialprüfung unter möglichst realitätsnahen Bedingungen ist eine wichtige Voraussetzung für die Einrichtung zuverlässiger und sicherer CCS-Systeme. Hierzu wurde eine neue Versuchseinrichtung zur Korrosionsprüfung von Pipelinewerkstoffen entwickelt, die folgende wesentliche physikalische und chemische Einflussgrößen berücksichtigt: Elastische Verformung, Druck, Temperatur, Gaszusammensetzung, und Fließgeschwindigkeit können unabhängig voneinander eingestellt werden. Die Verteilung der Radial- und Tangentialspannungen wurden in einer Rundprobe untersucht, und die Ergebnisse zeigten gute Übereinstimmungen mit den theoretisch zu erwartenden Werten. In dem vorliegenden Beitrag werden die Idee zu der neuen Korrosionsprüfeinrichtung und erste Ergebnisse vorgestellt sowie diskutiert.
Carbon capture and storage (CCS) includes processing of supercritical carbon dioxide (scCO2). The carbon dioxide (CO2) stemming from flue gases contains acid forming impurities, especially in the case of coal fired power plants. In the present work, the mobility and reactivity of acids in supercritical scCO2 was investigated. The corrosive attack of low alloyed carbon steel (material 1.0484) by water (H2O) alone in scCO2 was negligible. Nitric acid (HNO3) was very mobile and corrosive towards the carbon steel while sulfuric acid did not migrate through the scCO2 to react with the steel surface. Hydrochloric acid in scCO2 was very mobile and reactive towards both carbon steel and high alloyed test equipment. Gravimetric analyses revealed a severe material loss after corrosion in the presence of HNO3. Thickness measurements showed localized material losses.
Dealing with first corrosion screening experiments to predict the reliability and safety of Germanys first Carbon Capture and Storage site in the northern Bassin of Germany, northwest of the Capital Berlin, laboratory experiments have been established to simulate the particular conditions at T=60 °C, highly saline aquifer water similar to 'Stuttgart Aquifer', but only at ambient pressure. With mounting 2 independent full 2-grade titanium autoclave systems (running up to 250 bar and 300 °C) pressures up to p=100 bar are possible. In 2010 a specific corrosion chamber of 2-grade titanium working up to 100 °C, flowing aqui fer water with different gas mixtures was designed to fit to a high cycle fatigue testing machine. Long term fatigue experiments simulating fatigue crack growth under corrosive environments will soon start. These experiments may not only help engineering a CCS site, but results can be used to improve the maintenance of geothermal energy production sites, especially moved parts such as pumps and shafts.
The CCS technique involves the compression of emission gasses in deep geological layers. To guarantee the safety of the site, CO2-corrosion of the injection pipe steels has to be given special attention when engineering CCS-sites. To get to know the corrosion behaviour samples of the heat treated steel 1.72252CrMo4, used for casing, and the stainless injection-pipe steel 1.4034 X46Cr13 were kept at T=60 °C and ambient pressure as well as p=100 bar for 700 h - 8000 h in a CC 2-saturated synthetic aquifer environment similar to possible geological on-shore CCS-sites in the northern German Basin. The isothermal corrosion behaviour obtained by mass gain of the steels in the gas phase, the liquid phase and the intermediate phase gives surface corrosion rates around 0.1 to 0.8 mm/year at ambient pressure and much lower about 0.02 to 0.2 mm/year at 100 bar where the CO 2 is in its supercritical state. Severe pit corrosion with pit heights around 4.5 mm are only located on the 42CrMo4 steel. Main phase of the continuous complicated multi-layered carbonate/oxide structure is siderite FeCO 3 in both types of steel.
CO2-induced corrosion of casing and tubing steels is a relevant safety issue for compressing emission gasses into deep geological layers (CCS, Carbon Capture and Storage). The influence of CO2 and pressure of the surrounding media on steels is demonstrated in laboratory experiments providing a corrosive environment similar to a geological onshore CCS-site in the Northern German Basin (T = 60 °C, p = 1 - 100 bar, Stuttgart Aquifer, CO2-flow rate of 3 l/h, 7008000 h exposure time). Corrosion kinetics and microstructures were characterized using specimens of heat treated 42CrMo4 (1.7225, casing) and soft annealed X46Cr13 (1.4034, tubing).
The appropriate strength of steels used for saline aquifer carbon capture and storage sites (CCS) is usually achieved by applying heat treatments. Thus, heat treatment influences the corrosion resistance for injection pipe steels with 13% chromium and different carbon content: 1.4034/X46Cr13 and 1.4021/X20Cr13 in CO2 saturated saline aquifer water at 60 °C, 1 and 100 bar. X46Cr13 shows better corrosion resistance with respect to corrosion rate, number of pits and maximum intrusion depth. Low corrosion rates are obtained for steels with martensitic microstructures exposed to supercritical CO2 at 100 bar, whereas normalized steels show better corrosion resistance at ambient pressure.
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.
Future coal power plants will in case of oxyfuel combustion be operated with altered atmospheres. Hence, corrosion attack might become more severe and steels have to be protected. An alumina-sol was used to coat X20CrMoV12-1 (X20) with alumina to test the protection. Testing was performed at 600 °C in flowing H2O–CO2–O2 and static laboratory air for 1000 h. Oxidation under air is minor compared to exposure in oxyfuel atmosphere. In both cases a multilayered oxide (hematite, magnetite, spinel) was formed on uncoated steels. Carburization appeared on uncoated X20 in H2O–CO2–O2. The coating demonstrates a high protection.
During the compression of emission gasses into deep geological layers (Carbon Dioxide Capture and Storage, CCS) CO2-corrosion will become a relevant safety issue. The reliability of the steels used at a geological onshore CCS-site in the Northern German Bassin 42CrMo4 (1.7225, AISI 4140) used for casing, and the injection pipe steels X46Cr13 (1.4034, AISI 420 C), X20Cr13 (1.4021, AISI 420 J) as well as X35CrMo17 (1.4122) is demonstrated in laboratory experiments. Samples were kept in a synthetic aquifer environment at T = 60 °C. This corrosive environment is then saturated with technical CO2 at a flow rate of 3 l/h. Microstructures were characterized by X-ray diffraction, light microscopy, scanning electron microscopy, and energy dispersive X-ray analysis, after a series of heat treatments (700 h to 2 years). The non-linear isothermal surface corrosion behaviour of the steels reveals surface corrosion rates around 0.10.8 mm/year, when obtained by mass gain. Severe pit corrosion (pit heights ca. 4.5 mm) are only located on the injection pipe steels. Main phases of the continuous scales are siderite FeCO3 and goethite α-FeOOH. The formation of the non-protective layer is likely to form via a
transient Fe(OH)2-phase.
Basic research on the corrosive effect of flue gases has been performed at the BAM Federal Institute for Materials Research and Testing (Germany). Conditions at both high and low temperatures were simulated in specially designed experiments. Carburization occured in flue gases with high CO2 content and temperatures higher than 500 °C. In SO2 containing flue gases sulphur was detected in the oxide scale. At lower temperatures no corrosion was observed when gases with low humidity were investigated. Humidity higher than 1500 ppm was corrosive and all steels with Cr contents lower than 12% revealed corroded surfaces. At low temperatures below 10 °C a mixture of sulphuric and nitric acid condensed on metal surfaces. Acid condensation caused severe corrosion. Humidity, CO2, O2, and SO2 contents are the important factors determining corrosion. Below 300 °C acid condensation is the primary reason for corrosion. Low humidity and low temperatures are conditions which can be expected in the CO2 separation and treatment process. This work includes major conditions of the flue gas and CO2 stream in CCS plants and CCS technology.
In future power plant technologies, oxyfuel, steels are subjected to steam rich and carbon dioxide rich combustion gases. The effect of simulated combustion gases H2O/CO2/O2 (30/69/1 mol%) and H2O/CO2 (30/70 mol%) on the corrosion behavior of low alloyed steels, 9-12% chromium steels and an austenitic steel were studied. It was discovered that the formation of protective chromium rich oxides is hampered due to the carburization of the base material and the formation of chromium rich carbides. The kinetics of corrosion and carburization are quantified. The effect of temperature and the effect of gas pressure are analyzed statistically.
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).
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.
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.
CO2-corrosion of injection pipe steels is a relevant safety issue when emission gasses are compressed in deep geological layers (CCS). The reliability of the steels used at the geological onshore CCS-site at Ketzin, Germany, is demonstrated in laboratory experiments under an equivalent corrosive environment (T=60 °C,p=1-60 bar, aquifer water, CO2-flow rate of 3 l/h, 700 h8000 h heat treatment). Corrosion kinetics and microstructures were characterized using samples of the heat treated steel 1.7225 (AISI 4140, 42CrMo4) used for casing, and samples of the martensitic stainless injection-pipe steel 1.4034 (AISI 420, X46Cr13).
Influence of pressure and chromium content on corrosion reactions at 600°C in a CO2-H2O atmosphere
(2008)
Der Klimaschutz erfordert die Reduzierung des Ausstoßes von Kohlendioxid. Neue Kraftwerke mit Sauerstoffverbrennung und möglicherweise CO2-Abscheidung sollen eine Reduktion des CO2 im Bereich der Energietechnik ermöglichen. Die heute üblichen Hochtemperaturwerkstoffe werden anderen Umgebungsbedingungen ausgesetzt, und es sind andere Korrosionsraten und Korrosionsreaktionen zu erwarten. In diesem Beitrag werden die Kraftwerkstechnologien kurz vorgestellt und an einem Beispiel erläutert, dass die Oxidation an Luft mit der Oxidation in Wasser nicht direkt vergleichbar ist.
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.