Retardation of High-Temperature Fuel Ash Corrosion of Fireside Boiler Tubes via Nanoparticles

The high-temperature corrosion rate of boiler tubes was studied as a function of inhibitor concentration, time, and temperature in the absence and presence of fuel ash. Samples of steel tubes were taken from boilers that operate in Northern Baghdad Station for Electric Power Generation. Fuel ash was collected from the boiler combustion chamber, as well. Normal and nano-MgO were used as a corrosion inhibitor in different mixing ratios. A weight loss technique was used to evaluate the corrosion rates, while scanning electron microscopy was used to study the surface morphology. It was seen that corrosion rates increased with both time and temperature, and decreased with the addition of inhibitors. The maximum inhibitor efficiency was 81 %, obtained via using nano-MgO at mixing weight ratio 2:1, 600 °C, and 10 h. The Presence of fuel ash had harmful effects on the steel surface.     

Review on high temperature corrosion of PCF boilers in Poland

The paper presents selected data on power industry in Poland. The information given comprises electric energy production, number of power plants, steam and fuel (coal) characteristics as well as chemical compositions of construction materials being currently in use for furnace wall and superheater tubing. Briefly discussed are also the results of investigations on fireside corrosion of pcf boilers. It has been found that the high temperature corrosion phenomena observed on furnace wall tubes in the vicinity of burners are related with local reducing conditions and chlorine content in coal whereas those encountered on superheater tubes are associated with fused ash deposits. Preventive measures to combat fireside corrosion and slagging planned for the nearest future are the application of bimetallic coextruded tubes and the dosage of additives in coal combustion.     

External corrosion in coal-fired boilers: Assessment from laboratory data

The reactions of coal impurity constituents in the flame are discussed in this paper with particular reference to the formation of corrosive deposits on the heat transfer surfaces in boilers. Consideration is given to the factors which make it difficult to give accurate predictions of metal wastage rates in these environments at high temperatures on the basis of laboratory experiments. These difficulties arise from variations in the operating conditions and are particularly problematic for the steam generating tubes which are located in the walls of the combustion chamber. Non-equilibrium reducing conditions can exist in this region and there is a large temperature gradient through the ash deposit and the corrosion scale on the tube surface. Molten sulphate deposits can be formed on the superheater tubes at the highest temperatures, and the temperature gradient again has an important influence on corrosion rates. The nature and concentrations of the coal impurities and also the influence of heat flux therefore have to be taken into account in the prediction of corrosion rates from laboratory data which may frequently have been obtained under isothermal conditions.     

Corrosion experience with carbon steel in spray absorption FGD plant

Carbon steel is the traditional material for boiler flue gas ducts and stacks. The introduction of flue gas desulphurisation systems in existing power plant units requires major changes in the flue gas system from boilers to the flue stack. In the semidry spray absorption plant at Studstrupværk power plant carbon steel has been used. This concept was chosen to utilize part of the existing carbon steel ducting and avoid the use of expensive high alloyed materials and coating systems. During the first year of operation emission of fine flakes of rust from the ducting and the stack become a major problem. To overcome this, corrosion testings were performed in laboratory and in the plant. The corrosion problems were found to be related to an atmospheric corrosion with hygroscopic chloride containing deposits. The aim of the tests was to establish the critical humidity for corrosion of carbon steel in FGD plant products and deposits. The examinations cover products and deposits from different operational conditions and parts of the Studstrupværk power plant. The laboratory tests were followed by corrosion probe tests in the plant and full scale operation tests with the plant. The results of this programme showed that carbon steel can be used and corrosion can be kept at a very low level by controlling the humidity of the flue gas below 40% RH with fresh water as process water and down to 30% RH with salt water as process water. In practice this has to be controlled by the temperature difference between the flue gas and the adiabatic saturation temperature of the flue gas. Effective insulation of the ducting has been found to be of outmost importance as the humidity should be measured relative to the surface temperature. Experience from the plant shows that the most severe corrosion is found in cold spots.     

Fireside corrosion in German fossil-fuel fired power plants. Appearence,mechanism and causes

Fireside corrosion in German fossil fuel-fired boilers is described out of the view of a laboratory engaged with failure analysis. With German boiler design and German fossil fuel ferritic steels can be used for the tubing in the evaporator and superheater section. Corrosion rates, which have to be expected normally are below 10 nm/h for evaporator tubes and below 25 nm/h for superheater tubes. The appearance of corroded tubes is described and discussed in respect of the corrosion mechanism. In the evaporator section enhanced corrosion risk is mainly due to an increased chemical load, namely reducing conditions or chlorine compounds in the combustion products. In the superheater section higher than normal metal temperatures and stresses, by which the integrity of the oxide layer is destroyed, are the most important factors for increased corrosion rates.     

High-temperature degradation and protection of ferritic and austenitic steels in steam generators

The useful life of superheaters and reheaters of power stations which use heavy fuel oil is shortened and their continuous service is inhibited by corrosion (fireside) and creep-type problems. The increase of corrosion attack on boilers is caused by the presence of fuel ash deposits containing mainly vanadium, sodium, and sulfur which form low-melting-point compounds. The tubes are exposed to the action of high stresses and high temperatures, producing the so-called “creep damage.” In this work, two kinds of results are reported: lab and field studies using a 2.25Cr-1Mo steel. The laboratory work was in turn divided into two parts. In the first, the steel was exposed to the action of natural ash deposits in oxidant atmospheres at 600 ° for 24 h. In the second part, tensile specimens were creep tested in Na₂SO₄, V₂O₅, and their mixture over a temperature range of 580 to 620 °. In the field work, components of a power station were coated with different types of nickel-and iron-base coatings containing chromium, Fe-Cr, and Fe-Si using the powder flame spraying technique. After testing, the coated tubes were analyzed using electron microscopy. The results showed that all the coating systems had good corrosion resistance, especially those containing silicon or chromium.     

Hochtemperaturschäden bei hitzebeständigem Stahlguß

High temperature failures of heat resistant cast steel Heat resistant cast steel can fail by high temperature, the atmosphere, deposits and mechanical stresses. High temperature corrosion by gas atmospheres can be oxidation, nitriding, carburization, metal dusting, sulphur and chlorine attack. Corrosion by deposits as oil ash or chromates and liquid metals as copper base alloys, lead, tin and zinc leads to a rapid reduction in wall thickness. Besides there are mechanical stresses which lead to failures by stress rupture cracks or thermoshock. The additional effect by material aging should be considered as well.     

Enhancement of Service Life of Steam Generating Tubes in Oil-Fired Boiler for Power Generation Employing Plasma Spray Technology

The effects of Ni-50 mass% Cr alloy coating, that is plasma-sprayed onto the fire-side of steam generating tubes in a heavy oil-fired boiler, on the high temperature corrosion resistance were examined. One of the severe environments in the industrial manufacturing facilities, where thermal sprayed coatings are employed, is the high temperature corrosion such as the oxidation, sulfidation, and low melting fuel ash corrosion in the fire-side of boiler tubes. In the fossil fuel-fired steam generating boiler facilities, the degradation or failure of steam generating tubes that were derived from the contaminants in a lower grade fuel have often occurred. The situation of degradation of the water evaporator and superheater tubes and corrosion-preventing effects of plasma sprayed coating are described. The enhanced effects of plasma sprayed Ni-50 mass% Cr alloy coating for the suppression of hot corrosion failure of the steam generating tubes of boiler are summarized.     

Recent plant experience and research into fireside corrosion in Japan

The increasing use of heavy oil as a fuel in power stations has given rise to intensified research in the field of fireside corrosion in Japan. The problems which have to be tackled are described in terms of experiences gained in the operation of oil and coal fired boilers. The main types of damage encountered are nonuniform wastage of tubes in connection with carburization. In this context significant interdependences have been found in connection with coal deposition (especially sodium and sulphur contents). On the basis of this experiences and of the results of corrosion tests in the laboratory and in the field it has been found that the measure offering the best prospect for corrosion control might be the use of coextruded tubing which would allow a combination of high corrosion resistance and high creep strength. In addition to that some modified alloys (e.g. Alloy 800 H, CR 30 A or NF709) offer an interesting potential whereby the high chromium content (more than 20%) is the main criterium.     

燃煤火电厂锅炉“四管”的高温腐蚀

燃煤火电厂锅炉的高温腐蚀主要发生在受热面的“四 管”,即水冷壁管、过热器管、再热器管和省煤器管.腐蚀的主要类型是硫腐蚀、氯腐蚀、 水蒸汽腐蚀和钒腐蚀.本文综述了燃煤火电厂锅炉存在的典型高温腐蚀现象和机理,并简要 的介绍了一般防腐蚀措施.     

INTRODUCTION TO INCONEL ALLOY 740: AN ALLOY DESIGNED FOR SUPERHEATER TUBING IN COAL-FIRED ULTRA SUPERCRITICAL BOILERS

1. IntroductionW hile w orldw ide environm entalrestrictionsare requiring pow ercom paniesto reduce SO x,N O x andCO 2 em issions, econom ic pressuresare sim ultaneously necessitating im provem entsin the therm aleffi-ciency ofallcoal-fired plants. A ddin…     

The influence of surface oxide composition and structure on carburization in carburization in carbon monoxide – carbon dioxide

The oxidation and carburization of two 20 Cr 30 Ni alloys with nominally 0 and 0.5 wt % Si have been investigated by cyclic exposure to carbon monoxide and carbon dioxide at 1000°C. In carbon monoxide a chromium oxide film is formed which inhibits further carbon deposition. In carbon dioxide an iron chromium oxide of the spinel type is formed which during subsequent exposure to carbon monoxide acts as a catalyst for carbon deposition. In some areas a breakthrough of the initially formed chromium oxide layer occurs during carbon dioxide treatment. Extensive carbon penetration takes place in these breakthrough areas. The spinel formation and the breakthrough is retarded in the silicon-containing steel owing to the formation of a thin continuous silica layer at the metal-chromium oxide interface. This has a beneficial effect on the carburization resistance. The results also imply that it is possible to lower the catalytic effect of the tube material on carbon deposition or even on coke formation by controlling the surface oxide composition and structure.     

INTRODUCTION TO INCONELEL ALLOY 740： AN ALLOY DESIGNED FOR SUPERHEATER TUBING IN COAL-FIRED ULTRA SUPERCRITICAL BOILERS

Chinese utilities as well as those worldwide are facing increased demand for additional electricity, reduced plant emissions and greater efficiency. To meet this challenge will require increasing boiler temperature, pressure and coal ash corrosion resistance of the materials of boiler construction of future coal-fired boilers. A new nickel-based tube alloy, INCONEL^R alloy 740, is described aiming at meeting this challenge. Emphasis will be on describing the alloy＇ s mechanical properties, coal-ash and steam corrosion resistance. Microstructural stability as a function of temperature and time is addressed as well as some of the early methodology em- ployed to arrive at the current chemical composition.     

Effect of hot corrosion on the creep properties of types 321 and 347 stainless steels

Problems caused by hot corrosion and creep damage on superheater and reheater tubes of power plants using heavy oil as fuel inhibit the continuous service of the boilers and shorten their design lives. The acceleration of hot corrosion attack of boilers is caused by the presence of fuel ash deposits containing V, Na, and S, in the form of Na₂SO₄ and V₂O₅, which form low melting point phases. In addition to this, the tubes are exposed to the action of both high stresses and high temperatures, producing a continuous plastic deformation of the tube walls called creep damage. Creep rupture tests were carried out in the temperature range 620 to 670 °C in static air in the presence of corrosive environments using 321H and 347H type stainless steels used in superheater and reheater tubes under hot corrosion and creep environments. The corrosive environment includes synthetic Na₂SO₄, V₂O₅, and the mixture 80% V₂O₅-20%Na₂SO₄. Also, the role of the different elements present in the environments on corrosion was investigated using electronic microscopy and x-ray diffraction techniques.     

Effects of fuel impurities on the fireside corrosion of boiler tubes in advanced power generating systems—a thermodynamic calculation of deposit chemistry

Thermodynamic equilibrium calculation relating fuel chemistry with flue-gas composition and volatile condensate deposits on tube metals upon combustion of various “dirty” fuel was conducted for a better understanding of the deposit chemistry of superheater tubes in steam-generating boilers. Corrosive impurities such as sodium, potassium, chlorine, and sulfur, inevitably involved in fuel, were considered in the calculation. Possible influence of flue-gas temperature on deposit chemistry was investigated as well.Based on the flue-gas composition and the deposit chemistry, corrosion environments of steam-generating boilers firing various “dirty” fuel were discussed.     

Impact of Deposits and Their Morphology on the Active Corrosion of Iron in Chlorine- and Sulfur-Containing Atmospheres in the Temperature Range of 350–500 °C

Iron-based alloys have shown high corrosion rates under ash deposits typical for waste-to-energy plants. The ashes on superheater tubes in waste incineration are multicomponent systems including alkali and alkali–earth chlorides and sulfates. Under and within such salts, the corrosive effect on the alloy is induced by a complicated interplay of such ash products. On the one hand, in chlorine-containing atmospheres iron-based alloys are believed to be attacked by the so-called active corrosion, including the formation of volatile corrosion products and their transformation into stable iron oxides. At the same time, they form complex scales, involving among other compounds iron sulfides, chlorides, and oxides. Thus, in order to directly investigate the influence of a deposit on the corrosion in waste-to-energy plants and to reproduce the scales observed on field tested superheaters, this work compares the scale formation and metal wastage under different chemically inert alumina deposits with different grain sizes to a synthetic salt as well as to an actual deposit taken from a superheater tube in a plant.     

Der wartungsfreie Heißwasser-Boiler. Korreferat zu: Korrosionsschutz an Warmwasserboilern mit duroplastischen Kunststoffen

The maintenance-free hot water boiler. Corrosion protection of hot water boilers with duroplastics The corrosion damage caused by water is different from that caused by air. As there are always, in a hot water boiles boundary areas exposed to these media, the only materials suitable for boiler protection are those meeting the following requirements:

• The protection effect must be independent of the composition of the water.
• The composition of the water must not change in the boiler.
• The boilers concerned must not require maintenance.

But corrosion damage on hot water tanks is not conditioned by the composition of the water alone. There is also a possibility of contact corrosion if, e.g., copper pipes or copper beating elements are connected to galvanized boilers. A hot water boiler made of copper will therefore also suffer corrosion damage if material entrained from steel water piping becomes active. Even galvanization can only be applied at temperatures up to 60°C. Above this temperature iron becomes anodic and will corrode. Experience with boilers protected with the organic material known as Si 14 EG can be summed up as follows:

• 1 The duroplastic material known as Si 14 EG is proof against all types of drinking water approved by the public health authorities.
• 1 Some 15,000 boilers with such protection have now been in operation for five years without requiring maintenance, and without loss of protection effect.
• 1 As the hot water boilers thus protected also remain free from incrustations, the heat transfer, and thus the hot water output, remain constant.
• 1 The price of a hot water boiler made of carbon steel and protected with Si 14 EG is lower than that of a copper boiler of equal capacity.

The report concludes by listing the technical requirements for duroplastic coating: The areas to be protected must be accessible for working and inspection; edges must be chamfered; welds must be coherent and free from shrinking cavities and should be smoothed; pipe connections should welded flush with the boiler surface. The text is accompanied by photographs of duroplastically protected boilers.     

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.     

Mechanistic features of molten salt corrosion in coal fired boilers

In general, the hottest outlet sections of both superheaters and reheaters in modern CEGB boilers are tubed in austenitic stainless steels. Experience over the last 10–15 years has indicated that molten salt fireside corrosion can significantly reduce design lives, corrosion rates being a function of

• (i) metal temperature
• (ii) gas temperature
• (iii) coal chlorine content
• (iv) the tube's aerodynamic position

The characteristic visual features of this form of corrosion such as “classical” wastage flats, honeycomb pitting, and localised pitting at tube geometrical features such as weld beads, and lugs is described. Also discussed are some of the metallographic features of molten salt corrosion, including substrate carburization, internal oxidation/sulphidation and corrosion scale morphology. Whilst uncertainty remains in understanding the precise mechanism, the CEGB have adopted a pragmatic approach using new/alternative materials such as shields, coatings and co-extruded tubes. However, such a policy may not be the most economic: for example, in some circumstances the alloy 50 Cr 50 Ni is required to give a guaranteed degree of protection. What is still required is the quantification of the role of Na, K, Cl etc. in fuel on deposition and corrosion rates, and the source and influence of carburization so that further operational control of this molten salt corrosion is available.     

The Inhibitory Effect of Magnesium Sulfonate as a Fuel Additive on Hot Corrosion of Generating Tubes of Power Plant Boiler

Changing the power plant boiler fuel from natural gas into fuel oil during the cold months of the year causes hot corrosion in generating tubes. Visual observations, thickness and thermocouple measurements and ash analysis proved the hot corrosion by displaying the sticky melted ash, thickness reduction, surface temperature of tubes at about 600 °C and existence of complex corrosive elements such as sodium and vanadium, respectively. Therefore, based on the experimental data from the power plant, laboratory studies were performed to survey the corrosion inhibition effect of magnesium sulfonate as an easy to use fuel additive. A low carbon steel, 70 wt%Na₂SO₄–25 wt%V₂O₅–5 wt%NaCl and mineral part of magnesium sulfonate ash were used as the generating tube material, corrosive and additive ashes, respectively. Two groups of specimens were coated with two different compounds of synthetic ashes, in which the first group was containing corrosive salts and the second was a calculated specific combination of mineral part of additive ash and corrosive salts. Specimens were exposed to high temperatures up to 120 h at 600 °C. Power plant observations, XRF, weight loss criteria, SEM and FESEM were used to study the hot corrosion, and results were compared with similar studies. It was concluded that magnesium sulfonate could not attribute to reduce the emission of sulphurous gases. Although the first group of the specimens was highly suffered from corrosion, the other group of samples was protected against hot corrosion and the weight loss was decreased considerably. Morphology and XRD picks of corrosion products were described, and it was also concluded that Na₄V₂O₇ and NaV₃O₈ compounds which are molten at 600 °C were responsible for hot corrosion. The additive inhibited corrosion through formation of Na₃VO₄ with 850 °C melting point and prevented the formation of sticky and corrosive compounds.