Potential high temperature corrosion problems due to co‐firing of biomass and fossil fuels

Over the past few years, considerable high temperature corrosion problems have been encountered when firing biomass in power plants due to the high content of potassium chloride in the deposits. Therefore, to combat chloride corrosion problems co‐firing of biomass with a fossil fuel has been undertaken. This results in potassium chloride being converted to potassium sulphate in the combustion chamber and it is sulphate rich deposits that are deposited on the vulnerable metallic surfaces such as high temperature superheaters. Although this removes the problem of chloride corrosion, other corrosion mechanisms appear such as sulphidation and hot corrosion due to sulphate deposits. At Studstrup power plant Unit 4, based on trials with exposure times of 3000 h using 0–20% straw co‐firing with coal, the plant now runs with a fuel mix of 10% straw + coal. Based on results from a 3 years exposure in this environment, the internal sulphidation is much more significant than that revealed in the demonstration project. Avedøre 2 main boiler is fuelled with wood pellets + heavy fuel oil + gas. Some reaction products resulting from the presence of vanadium compounds in the heavy oil were detected, i.e. iron vanadates. However, the most significant corrosion attack was sulphidation attack at the grain boundaries of 18‐8 steel after 3 years exposure. The corrosion mechanisms and corrosion rates are compared with biomass firing and coal firing. Potential corrosion problems due to co‐firing biomass and fossil fuels are discussed.     

Mechanical and microstructural properties of HVOF sprayed WC–Co and Cr3C2–NiCr coatings on the boiler tube steels using LPG as the fuel gas

The characteristics and the phase composition of high velocity oxy fuel (HVOF) sprayed WC–Co and Cr₃C₂–NiCr coatings applied onto boiler tube steel substrates using liquid petroleum gas (LPG) as the fuel gas, have been evaluated. The coatings were examined using metallography, SEM/EDAX and XRD techniques. An attempt has been made to describe the transformations that take place during HVOF spraying. The purpose of this study was to compare the microstructure, porosity, surface roughness and microhardness of HVOF sprayed WC–Co, Cr₃C₂–NiCr coatings deposited on boiler steels. The paper will also investigate if there is an application of the deposit in energy generation plants with a view to enhance the life of the component and reduce tube failures in such power plants.     

Influence of Preoxidation on High-Temperature Corrosion of a FeCrAl Alloy Under Conditions Relevant to Biomass Firing

Preoxidation of a commercial FeCrAl alloy (Kanthal APM) was evaluated as a surface modification approach to reduce alkali chloride-induced corrosion during biomass firing in power plants. Samples of the alloy preoxidized at 900 °C in O₂ or O₂ + 10 vol% H₂O, and at 1100 °C in O₂, were coated with KCl and exposed at 560 °C to a gas mixture comprising of 12 vol% CO₂, 6 vol% O₂, 3 vol% H₂O, 400 ppmv HCl and 60 ppmv SO₂. The oxide formed at 1100 °C showed no reactivity with the corrosive species. By contrast, all samples preoxidized at 900 °C suffered severe attack, resulting in formation of Fe-, Cr- and Al-containing corrosion products in a heterogeneous morphology, similar to non-preoxidized samples. The observed differences with respect to the degree of corrosion attack on the preoxidized samples are discussed in terms of the composition and thickness of the different types of Al₂O₃ layers obtained by the preoxidation treatment.     

Field test corrosion experiments in Denmark with biomass fuels. Part 2: Co‐firing of straw and coal

In Denmark, straw is used for generating energy in power plants. However during straw combustion, potassium chloride and SO₂ are released in the flue gas and through condensation and deposition processes they will result in the formation of superheater deposits rich in potassium chloride and potassium sulphate. These components give rise to varying degrees of accelerated corrosion. This paper concerns co‐firing of straw with coal to reduce the corrosion rate from straw to an acceptable level. A field investigation at Midtkraft Studstrup suspension‐fired power plant in Denmark has been undertaken where coal has been co‐fired with 10% straw and 20% straw (% energy basis) for up to approx. 3000 hours. Two types of exposure were undertaken to investigate corrosion: a) the exposure of metal rings on water/air cooled probes, and b) the exposure of a range of materials built into the existing supertheaters. A range of austenitic and ferritic steels was exposed in the steam temperature range of 520–580°C. The flue gas temperature ranged from 925–1100°C. The rate of corrosion was assessed by precision measurement of material loss and measurement of oxide thickness. Corrosion rates are lower than for 100% straw‐firing. The corrosion products and course of corrosion for the various steel types were investigated using light optical and scanning electron microscopy. Catastrophic corrosion due to potassium chloride was not observed. Instead a more modest corrosion rate due to potassium sulphate rich deposits was observed. Corrosion mechanisms include sulphidation, oxidation and hot corrosion.     

Comparison of corrosion behaviour of thermal sprayed and diffusion‐coated materials

In this paper, the corrosion behaviour of thermal sprayed and diffusion‐coated materials are compared. The result of the high temperature corrosion test shows that the layers with NiCr applied by atmospheric plasma spraying (APS) and high velocity oxy fuel flame spraying (HVOF) are more resistant than the layers with NiCrBSi and Cr₃C₂/ NiCr. Furthermore, the layer with NiCr on 15 Mo 3 is more resistant than that on 13 CrMo 44 as base material. The corrosion behaviour of Al, Cr, and Cr/Si diffusion‐coated materials on 13 CrMo 44‐ are better than those same diffusion coatings on 15 Mo 3‐surfaces. In particular, the Cr diffusion‐coated materials show the highest corrosion resistances in this work. Also, the diffusion‐coated materials have higher resistances than thermal sprayed materials in HCl‐H₂O‐O₂‐N₂‐atmosphere.     

Study of corrosion behaviour of A106 carbon steel absorber for CO2 removal in amine promoted hot potassium carbonate solution (Benfield solution)

The CO₂ absorber is one of the largest pressure vessels in ammonia plants, which are suffering from severe corrosion problems worldwide. The aim of the present study is to examine the corrosion behaviour of A106 carbon steel absorber for CO₂ removal in amine promoted hot potassium carbonate solution (Benfield solution). This study simulates CO₂ removal unit in ammonia production process at Abu Qir Fertilizers and Chemical Industries Company (Alexandria, Egypt) and many other plants all over the world. A typical Benfield solution contains hot potassium carbonate K₂CO₃, potassium bicarbonate KHCO₃, diethanol amine (DEA) as a promoter and potassium metavanadate KVO₃ as corrosion inhibitor. The rate of galvanic corrosion of carbon steel absorber/stainless steel pall packings couple in Benfield solution was measured without adding the corrosion inhibitor KVO₃ in order to measure the influence of corrosive solution. The corrosion rate was measured by weight loss technique in relation to different operating parameters such as solution velocity, solution temperature, %K₂CO₃, CO₂ loading, %DEA and the effect of the presence of solution contaminants. In general, increasing solution velocity, solution temperature, %K₂CO₃, CO₂ loading and the presence of solution contaminations increase the corrosion rate. However, the increase in %DEA in solution decreases the corrosion rate. The strong dependence of corrosion rate on both solution and gas velocities indicates the diffusion controlled nature of the corrosion process. In addition, estimation of activation energy revealed a value of 4·8 kcal mol^?1. Surface morphology study depicted the presence of a porous solid film of corrosion products on carbon steel surface. It has been found that the liquid phase diffusion of bicarbonate to the steel solution interface is the rate determining step.     

Corrosion Behavior of AISI 316L Stainless Steel and ODS FeAl Aluminide in Eutectic Li2CO3–K2CO3 Molten Carbonates under Flowing CO2–O2 Gas Mixtures

A kinetics study on AISI 316L stainless steel and ODS(Oxide-Dispersion-Strenghtened) FeAl iron aluminide was conducted concerningits corrosion behavior in moltenLi₂CO₃-K₂CO₃ eutectic at 650°C in flowingCO₂-O₂ gas mixtures. The corrosion resistance of FeAl ODS wasdemonstrated to be significantly superior to that of austenitic AISI 316Lsteel under all gas conditions tested in this work. At low CO₂partial pressure (PCO₂=0.3 atm) the corrosion rate of bothalloys decreased with time due to the formation of a protective oxidelayer. In dry CO₂ gas, corrosion of AISI steel proceeded at anear-linear rate, indicative of a surface-controlled reaction. FeAl corrodedinitially following parabolic behavior, but, on further reaction, exhibitedsome weight loss. A similar behavior was also observed in a67CO₂-33O₂ gas mixture. Corrosion of FeAl in highCO₂ gas has been postulated to initiate by acidic fluxing ofyttria particles. The attack then develops as pitting and leads to furtherreaction by general corrosion as a consequence of the formation ofactive-passive electrochemical cells between the interior of pits and theexternal surface. The weight loss of AISI 316L in67CO₂-33O₂ gas can be ascribed to the high oxidizing power ofthe gas causing a continuous dissolution of theCr₂O₃ layer into a soluble chromate.     

天然气管线钢CO2腐蚀研究进展

天然气管线面临日益严重的CO₂腐蚀问题。针对管线内特定的腐蚀环境,总结了当前CO₂腐蚀在反应机理、影响因素以及腐蚀控制方面的研究进展,最后展望CO₂腐蚀研究今后的发展方向。     

Laboratory corrosion tests for simulating fireside wastage of superheater materials in waste incinerators

Laboratory corrosion tests were performed to clarify the effects of relative amounts of fused salts in tube deposits on corrosion rates of superheater materials in WTE plants. All test exposures were at 550 °C and of 100 h duration. The nine synthetic ashes used as corrodents consisted of mixtures of chlorides, sulfates and oxides. The test materials were alloy steel T22, stainless steels TP347H, TP310HCbN, and alloys HR11N and 625. The gas atmosphere consisted of 500 to 3000 ppm HCl‐30 ppm SO₂‐10% O₂‐10% CO₂‐20% H₂O‐bal.N₂. Generally, the relative amount of fused salts in non‐fused ash constituents at 550 °C increased with increasing the chlorine content of the ashes. The corrosion rate of T22 steel did not depend directly on ash chlorine content, but for ashes of 7.7 wt.% Cl, the corrosion rate depended on the calculated amount of fused salt at 500 °C. The corrosion rates of TP347H steel and alloy 625 were maximum for ashes of 6–8 wt.% Cl. For ashes of 7.7 wt.% Cl, the corrosion rates of T22 steel, stainless steels, and alloys increased with ashes having higher amounts of fused salts. Increased HCl content of the gas caused higher corrosion of the stainless steels and high‐nickel alloys, but there was no clear corrosion‐exacerbating effect with T22 steel.     

Experiences with high temperature corrosion at straw‐firing power plants in Denmark

By the end of 2009, there will be eight biomass and five biomass co‐firing plants in Denmark. Due to the steep increase of corrosion rate with respect to temperature in biomass plants, it is not viable to have similar steam data as fossil fuel plants. Thus for the newer plants, Maribo Sakskøbing, Avedøre 2 biomass boiler, Fyn 8 and Amager 1 (Fyn 8 and Amager 1 are under commissioning), the steam temperature of the final superheaters are approximately 540 °C and the steel type used is an 18–10 stainless steel, (TP347H). However there is still a need to monitor corrosion rates, and to collate data to enable better lifetime prediction of vulnerable components in straw‐firing plants since the corrosion rates are so much faster than in coal firing plants. Therefore, there are continued investigations in recently commissioned plants with test tubes installed into actual superheaters. In addition temperature is measured on the specific tube loops where there are test tube sections. Thus a corrosion rate can be coupled to a temperature histogram. This is important since although a superheater has a defined steam outlet temperature, there is variation in the tube bundle due to variations of heat flux from the flue gas. This paper will describe the corrosion investigations for tube sections removed from Maribo Sakskøbing and Avedøre 2 biomass boiler which have been exposed for up to 30 000 h. In addition to monitoring the corrosion rates of actual components, there is a need to measure corrosion rates at higher temperatures to assess if there is a possibility to increase the outlet temperature of the plant, thus making the plant more cost effective. For this purpose Avedøre 2 biomass boiler has a test superheater loop fabricated in TP347H FG (the same material as the final superheaters). Some results from this test superheater will also be described. Effects of flue gas temperature and flue gas direction on corrosion rates are also discussed.     

Updated CO2/H2S internal corrosion model of natural gas pipelines based on flow field calculations

The ‘A line’ of the Sichuan Natural Gas East Transportation in China was used as the subject of the study, and an existing CO₂/H₂S corrosion model was utilised to predict the uniform corrosion rate. Then, the flow parameters were simulated by computational fluid dynamics based on turbulence theory, and the influence on the corrosion rate of the pipeline was analysed in a detail to more accurately describe the corrosion problems of natural gas pipelines that contain CO₂/H₂S. After that, an updated CO₂/H₂S corrosion model under the influence of flow filed was proposed by modifying the existing CO₂/H₂S corrosion model. The actual condition was calculated by the updated CO₂/H₂S corrosion model. Results show that flow parameters, namely, velocity, turbulent kinetic energy and phase distribution, affect pipeline corrosion. The flow parameters did not change significantly at the small scale changes in the pipeline (5 and 15°) of a broad and smooth flow channel of the large diameter gas transport pipeline. The shape of corrosion often appears in the form of an elliptical sheet. The corrosion location and the corrosion rate calculated by the updated model are consistent with the wall thickness detection data in the site conditions, which verified that the updated CO₂/H₂S corrosion model is valid. The updated CO₂/H₂S corrosion model influenced by the flow field can predict the corrosion distribution and the corrosion rate of the three-dimensional key positions in natural gas pipelines.     

Which are the right test conditions for the simulation of high temperature alkali corrosion in biomass combustion?

The use of renewable energy sources for the generation of electricity has gained much interest in recent years. Biomass has the potential of being a CO₂ neutral energy source that could provide a significant proportion of the ever‐increasing energy demand. The easiest and most straightforward utilization of the energy content of biomass is direct combustion. The thermal energy of the biomass released in the combustion process is utilized by heating water or steam to produce electricity or heat or both (CHP). Whereas the heat production requires only modest temperatures in the water or steam circuit, producing electricity with high efficiency is not possible without high steam parameters (temperature and pressure). The heat market being quite saturated, the economic potential is in the electricity market. High heat transfer surface temperatures coupled with biomass fired steam generators have resulted, however, in serious corrosion of the heat transfer surfaces, especially in the hottest section of the convection superheaters. The type of corrosion found in biomass boilers is not encountered in fossil fuel fired boilers and the mechanism causing it is not fully understood. The development of new alloys that could withstand these harsh environments would benefit tremendously if the test conditions in the laboratory tests could be chosen so that they adequately resemble the corrosion environment in real boilers. Currently the high corrosion rate is believed to be caused by gaseous KCl that condense on the heat transfer surfaces. While KCl is certainly found in the corroded superheater tubes and probably has an important role in the corrosion reactions with the alloy, the formation of KCl on the cooled surface can also be heterogeneous. In this paper a discussion on the effect of alkali hydroxides, especially KOH, is presented. Biomass fuels have normally a high content of alkali metals and a low content of sulfur and chloride. The excess alkali will produce alkali hydroxides in the combustion environment. Alkali hydroxides then react with CO₂ in the flue gases to form carbonates as the flue gases are cooled. The reaction with CO₂, is however, very temperature dependent. The equilibrium being completely on the K₂CO₃ side with a gas temperature below 700 °C and completely on KOH side with a gas temperature above 900 °C. The hottest superheaters are normally located in the area where the flue gas temperature is 850°C–1000 °C. This makes KOH condensation on the tubes possible and subsequent heterogeneous reactions with HCl, SO₂ and CO₂ in molten phase forming KCl, K₂SO₂ or K₂CO₃. Although KOH is not thermodynamically stable at typical tube surface temperatures, a continuous flux condensing from the flue gases results in a corrosion environment on the tube where its activity has to be taken into account. Therefore it is suggested that KOH, either in gaseous or molten phase should be included in the laboratory test environments used for the testing of alloys for biomass combustion applications.     

Failure mechanism of MCrAlY coating at the coating‐substrate interface under type I hot corrosion

MCrAlY coatings are widely used to provide protection of hot component in modern gas turbine engines against high‐temperature oxidation and hot corrosion. Coating‐substrate interface, where the substrate is only partially covered by the ?coatings, is vulnerable to the hot corrosion attack. The accelerated degradation at the coating‐substrate interface can cause fast spallation of the coating, leading to the early failure of the gas turbine components. In this paper, MCrAlY powder was deposited on IN792 disks by high‐velocity oxygen‐fuel spraying. The hot corrosion behavior of the coated sample was investigated using (0.8Na, 0.2K)₂SO ₄ salt deposition at 900°C in lab air. Results showed a minor attack in the coating center, however, an accelerated corrosion attack at the coating‐substrate interface. The fast growth of corrosion products from substrate caused large local volume expansions at the coating‐substrate interface, resulting in an early coating spallation.     

Optimisation of in‐service performance of boiler steels by modelling high‐temperature corrosion

The main objective of the EU OPTICORR project is the optimisation of in‐service performance of boiler steels by modelling high‐temperature corrosion, the development of a life‐cycle approach (LCA) for the materials in energy production, particularly for the steels used in waste incinerators and co‐fired boiler plants. The expected benefits of this approach for safe and cost effective energy production are: ‐ control and optimisation of in‐service performance of boiler materials, ‐ understanding of high‐temperature corrosion and oxidation mechanisms under service conditions, ‐ improvement of reliability to prevent the failure of components and plant accidents and ‐ expanding the limits of boiler plant materials by corrosion simulations for flexible plant operation conditions (steel, fuel, temperature etc.). The technical aim of the EU OPTICORR project is the development of modelling tools for high‐temperature oxidation and corrosion specifically in boiler conditions with HCl‐ and SO₂‐containing combustion gases and Cl‐containing salts. The work necessitates thermodynamic data collection and processing. For development and modelling, knowledge about the corrosion mechanisms and exact data are needed. The kinetics of high‐temperature oxidation and corrosion are determined from laboratory thermo‐gravimetric tests (TG) and multi‐sample exposure tests. The materials studied are typical boiler tubes and fin‐steels: ferritic alloys, the austenitic steel T347 and the Ni‐based alloy Inconel 625. The exposure gases are dry air, air with 15 vol‐% H₂O, and with 2000 ppm HCl and 200 ppm SO₂. The salt deposits used are based on KCl‐ZnCl₂ and Ca, Na, K, Pb, Zn‐sulfates. The test temperatures for exposures with deposits are 320 and 420°C and, for gas exposures, 500 to 600°C. At present the tools being developed are ChemSheet based programmes with a kinetic module and easy‐to‐use interface and a more sophisticated numerical finite‐difference‐based diffusion calculation programme, InCorr, developed for prediction of inward corrosion and internal corrosion. The development of modelling tools for oxidation and high‐temperature corrosion was started with thermodynamic data collection for relevant systems and thermodynamic mappings. Further, there are needs to develop the simulation model and tool for salt‐induced hot corrosion based on the ChemSheet approach. Also, the work on modelling and simulating with the InCorr kinetic modelling tool will be continued to demonstrate the use of the tool for various steels and alloys in defined combustion environments.     

Corrosion in alkanolamine used for acid gas removal: From natural gas processing to CO2 capture

The aim of this paper is to review some of the parameters influencing the corrosivity of alkanolamine solvents used for natural gas purification or for CO₂ capture. In the light of literature data and of new experimental results, the influences of temperature and of acid gas loading are discussed. These two parameters appear to have a strong impact on corrosion rates of carbon steel, with extrapolated corrosion rates of several tens of mm/year for the highest temperature and acid gas loading condition. It is then proposed to discuss about similarities and differences between natural gas processing and CO₂ capture from flue gas. For both applications, alkanolamine processes are used. Still, differences can be found in operating parameters. The most significant gap concerns the lean amine sections. In acid gas treatment, the regeneration of the solvent is often performed down to zero loading. Under these conditions, an extremely low corrosivity of the lean solvent is expected. On the contrary, CO₂ capture from flue gas requires only a partial stripping of the CO₂ in the regeneration section, due to energy efficiency reasons. Then, the lean solvent still contains some acid gas, and subsequently a higher corrosivity. Finally, the general principles for material selection for the different parts of acid gas removal units are discussed, considering both cases of natural gas processing or CO₂ capture.     

Current and future corrosion challenges for a reliable and sustainable development of the chemical,refinery, and petrochemical industries

The chemical, refinery, and petrochemical industries are facing new challenges in order to develop more environment friendly processes and to manufacture “green” products. Corrosion management is an essential element for the development of a sustainable industrial society, including issues such as the selection and development of corrosion resistant materials, coatings, and environment friendly inhibitors. In this paper, some specific challenges will be discussed. In the chemical industry, the replacement of volatile and toxic solvents by green ones such as supercritical water processes, ionic liquid, or the use of carbon dioxide as an alternative solvent, requires specific corrosion management policies. Another issue for the refinery industry concerns new feedstocks such as opportunity crudes containing corrosive naphthenic acids or the transformation of biomass feed into bio‐oils and biomaterials. Synthetic gas is also becoming a crucial intermediate in natural gas, coal or biomass to hydrocarbon liquids (XTL) processes. Other environmental aspects are the limitation of green house gas (GHG) release from the plants by implementation of CO₂ capture processes and the environment friendly management of water including more restrictive steps concerning its disposal. The implementation of advanced inspection and corrosion control management is also a major element of progress for a sustainable development of the chemical, refinery, and petrochemical industries.     

Simulation of Fe-Cr-X Alloy Exposed to an Oxyfuel Combustion Atmosphere at 600 °C

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.     

Impact of oxyfuel atmospheres H2O/CO2/O2 and H2O/CO2 on the oxidation of ferritic–martensitic and austenitic steels

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.     

钢在高温CO2环境中氧化渗碳腐蚀机理及其涂层防护研究进展

钢材由于具有高强度和耐热性等优异性能而广泛应用于各种零构件,在服役过程中通常面临较为严重的腐蚀问题。CO₂ 腐蚀是钢材应用领域中较为常见的一种腐蚀失效方式。通常,CO₂ 对钢的腐蚀行为表现为其溶于水后产生的碳酸腐蚀,但在高温环境中,CO₂ 可直接使钢表面氧化,同时伴随渗碳现象发生,钢的力学性能与耐腐蚀性能均会因此大幅下降。然而,目前关于钢在高温 CO₂ 环境中的腐蚀行为研究缺乏相关系统总结。综述有关高温 CO₂环境下钢的腐蚀机理,总结高温 CO₂环境中温度、压力以及环境中存在的其他杂质气体对腐蚀方式及机理的影响规律,归纳已有的高温 CO₂氧化与渗碳腐蚀模型的发展状况,概述目前关于抗高温 CO₂ 腐蚀的钢材涂层类型及其防护效果。研究表明,由于含 Cr 钢在高温 CO₂环境中形成的 Cr₂O₃ 层相较于 Fe 氧化物层更加致密,Cr 元素的存在通常有利于钢的耐腐蚀性能。而环境中,温度与压力的升高以及杂质气体的存在往往会加重钢的 CO₂ 腐蚀,但这些因素的影响规律会随着钢的种类及服役环境的变化而变化。目前关于钢的 CO₂腐蚀模型主要为单一的高温氧化模型或者渗碳模型,可预测氧化物层厚度或渗碳深度,但无法准确预测同时发生氧化和渗碳行为的钢的腐蚀寿命。综述相关研究现状不仅能指出现有研究的不足及未来研究的展开方向,还可为高温环境中钢材抗 CO₂腐蚀防护措施的选择及其长周期安全服务寿命评价提供全面理论依据。     

The influence of NaCl and CO2 on the atmospheric corrosion of magnesium alloy AZ91

The influence of NaCl and CO₂ on the atmospheric corrosion of magnesium alloy AZ91 is studied in the laboratory. Samples were exposed under carefully controlled air and flow conditions; the relative humidity was 95%, the temperature was 22.0°C and the concentration of CO₂ was < 1 ppm or 350 ppm. Different amounts of sodium chloride (0–70 μg/cm²) were added before exposure. The corrosion products were analyzed by gravimetry, ion chromatography, X‐ray diffraction and scanning electron microscopy. Mass gain and metal loss results are reported. The combination of high humidity and NaCl is very corrosive towards AZ91. However, the NaCl‐induced corrosion is inhibited by ambient concentrations of CO₂. Exposure in the absence of CO₂ gives rise to heavy pitting, with brucite, Mg(OH)₂, being the dominant corrosion product. In the presence of CO₂ a layer of hydrated magnesium hydroxy carbonate, Mg₅(CO₃)₄(OH)₂ · 5 H₂O forms. A tentative corrosion mechanism is presented that explains the behavior in the two environments.