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.     

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.     

Field test corrosion experiments in Denmark with biomass fuels. Part 1: Straw‐firing

In Denmark, straw and other types of biomass are used for generating energy in power plants. Straw has the advantage that it is a “carbon dioxide neutral fuel” and therefore environmentally acceptable. Straw combustion is associated with corrosion problems which are not encountered in coal‐fired plants. The type of corrosion attack can be directly ascribed to the composition of the deposit and the metal surface temperature. A series of field tests have been undertaken in the various straw‐fired power plants in Denmark, namely Masnedø, Rudkøbing and Ensted. Three types of exposure were undertaken to investigate corrosion: a) the exposure of metal rings on water/air cooled probes, b) the exposure of test tubes in a test superheater, and c) the exposure of test tubes in existing superheaters. Thus both austenitic steels and ferritic steels were exposed in the steam temperature range of 450–600°C. The corrosion rates were assessed by precision measurements of material loss and internal corrosion. The corrosion products and course of corrosion for the various steel types were investigated using light optical and scanning electron microscopy. Corrosion mechanisms are discussed in relation to temperature and deposit composition.     

Influence of novel cycle concepts on the high‐temperature corrosion of power plants

The aim to reduce CO₂ emissions has triggered the evaluation of new cycle concepts for power plants. CO₂‐capture concepts are also evaluated to add on new and existing power plants. For combined cycle power plants (CCPP), different cycles are investigated such as integrated gasification (IGCC) or oxy‐fuel firing. Besides the difference in combustion compared to a conventional CCPP, the environmental boundary conditions are changed and will affect the oxidation and corrosion life of the materials in the hot‐gas path of the gas turbine and the heat‐recovery steam generator. For the circulating fluidised bed power plants, the biomass co‐firing and the oxy‐fuel firing are also foreseen for CO₂‐emission reduction. The fireside corrosion of the water walls will be influenced by these concepts and the changed fuel. The corrosion risk has been evaluated for two new power plant concepts: combined cycle with exhaust gas recirculation and pulverised coal‐fired boiler with oxy‐fuel firing. Based on this evaluation, the consequences for the testing conditions and the material selection have been discussed in detail.     

KCl‐induced corrosion of Ni‐based alloys containing 35–45 wt% Cr

Ni–(35–45)Cr–4Nb alloys containing different fractions of α‐Cr were exposed to potassium chloride (KCl)‐induced corrosion. The corrosion exposures were carried out for 168 hr at 600°C in a 15% (vol/vol) H₂O (g) + 5% (vol/vol) O₂ (g) + N₂ (g; balance) atmosphere using KCl‐free (reference) and predeposited KCl samples. To mimic the KCl deposition in real boilers, 24 hr exposures where KCl vapor condensed continuously onto samples were also performed. The corrosion attack of the studied materials increased significantly when KCl was present compared to the KCl‐free samples. For the KCl exposures, the corrosion attack drastically increased when a significant α‐Cr fraction was present. α‐Cr was either selectively attacked or dissolved through solid‐state diffusion and a layered build‐up of the outer external scale of K₂CrO₄ and chromia could be observed. For the in situ condensed KCl exposure, severe corrosion was observed already within the 24 hr exposure, indicating a higher corrosion rate compared with when KCl was predeposited.     

Effects of nonhalide anions on the stress corrosion cracking behaviour of alloy 7475 in the tempers T651 and T7351

The stress corrosion cracking behaviour of 7475 plate material in the tempers T651 and T7351 was investigated performing constant load tests. Short transverse specimens were permanently immersed in aerated aqueous 0.6 M sodium chloride solutions with additions of 0.03 M sodium sulphate, 0.03 M sodium nitrate and 0.1 M sodium bicarbonate. Chloride solutions containing sulphate, nitrate or/and bicarbonate promoted environment‐induced cracking. A short transverse threshold stress below 50 MPa was found for 7475‐T651 plate material. Neutral 0.6 M NaCl solution was less conducive to stress corrosion cracking. Specimens of alloy 7475 in the overaged temper T7351 failed at applied stresses above 300 MPa. This failure resulted from overload fracture caused by a reduction of cross‐sectional area due to pitting corrosion, as confirmed by fractography showing severe pitting attack. Fractographic examinations of 7475‐T7351 specimens failed during immersion in chloride‐nitrate‐bicarbonate containing solutions with or without addition of sulphate after long exposure time periods revealed slight transgranular stress corrosion cracking, too. Pronounced transgranular environment‐induced cracking was observed on the fracture surfaces of specimens which were exposed to an aqueous solution containing chloride, sulphate, nitrate, and bicarbonate for 30 days at applied stress and were subsequently tensile tested in an inert environment.     

Die Korrosion austenitischer Überhitzerstähle durch Alkalisulfat/Alkalichlorid-Gemische in Luft und in Verbrennungsgasen

The corrosion of austenitic superheater steels by alkali sulphate/alkali chloride mixtures in air and combustion gases In view of the fact that, in superheaters, with metal temperatures in excess of 590° C, deposits with sulphate content give rise to heavy corrosion, investigations have been carried out into the behaviour of three austenitic steels exposed to alkali sulphate/alkalie chloride mixtures at temperatures ranging from 540 to 760° C. The atmosphere above the crucibles during the tests consisted of air and a synthetic combustion gas to which SO₂ and SO₃ had been added. The tests showed that the pure sulphates are harmless, but that even a small quantity of NaCl (0.5 to 2 percent.) may result in catastrophic oxidation (at temperatures between 630 and 760° C). In the synthetic combustion. gas, potassium sulphate was found to be more corrosive that sodium sulphate. A chloride additon has no major effect except at temperatures above 630° C, presumably due to complex alkali-iron-sulphates. With all tests, corrosion was intergranular.     

Gaseous corrosion of alloys and novel coatings in simulated environments for coal,waste and biomass boilers

The reduction of emissions from power generation plants is a key part of the Kyoto Protocol. Reduced emissions per unit of power produced can be achieved via increased thermal efficiency and this can be achieved by increasing steam parameters (i.e. temperature and pressure). Increased steam parameters in turn leads to accelerated corrosion of boiler components. Biomass and solid waste fuels introduce a number of aggressive species into process environments that result in enhanced rates of boiler degradation. This paper reports on studies, both theoretical and experimental, of the corrosion behaviour of high‐alloy steels and Ni‐base alloys as well as coatings for use in high efficiency coal and/or biomass‐ and waste‐fired power plants. Coatings produced within the SUNASPO project have been laboratory tested in gaseous atmospheres representative of coal combustion, biomass combustion and waste incineration. Laboratory tests were carried out mainly in the temperature range 500 °C to 800 °C. Initial results showed the poor performance of traditional uncoated low‐alloy boiler steels P91 (9% Cr) and HCM12A (12% Cr), as well as the higher alloy steel, 17Cr/13Ni. Results show the beneficial effects of coatings containing Al, Si, Al + Si, Al + Ti and Al + B in reducing the rate of corrosive attack. In a combustion product gas containing 100 ppm HCl and 1000 ppm SO₂, aluminizing affords corrosion resistance of low‐alloy steels such as HCM12A and P91 similar to that of Alloy 800 over 1000 h of test. The presence of Al inhibits internal, sometimes localized corrosion by promoting the formation of a protective surface oxide layer even at relatively low temperatures. The results of experiments in simulated coal; biomass and waste atmospheres are presented and discussed in terms of both corrosion kinetics and mechanisms of degradation.     

Corrosion of Ni in Molten Alkali Sulphates

The corrosion of Ni base alloys under molten ash deposits containing considerable quantities of alkali sulphates can take place as a sulphidation or oxidation. The former is very dangerous with respect to gas turbine operation since it gives rise to a decrease in strength of the materials; this type of corrosion is also predominant under thick layers of molten deposits at higher oxygen pressures, the effect being then increased by the poorer transport properties of the melt respect to oxygen diffusion. When cobalt sulphate is found in the ash the accelerated oxidation of Ni base alloys is due to the stable redox system Co⁺²/Co⁺² in the melt Increasing the acidity of the flue gases (increasing SO₃ content) enhances the corrosion rate and the solubility of corrosion products in the melt.     

Special aspects of localized High-temperature corrosion

As in aqueous corrosion a localized corrosive attack can be important in high-temperature corrosion of metallic materials and become, unvoluntarily, a lifetime determining factor for combustion systems. Deposit-induced corrosion is the most important form of localized corrosion on alloy 800 and other materials in advanced coal combustion systems. Coal-ash deposits may cause a sulfidation/oxidation reaction which propagates preferentially along grain boundaries into the underlying metallic material. Preferred grain boundary corrosion may also occur in the walls of the fuel nozzle tubes of gas combustion systems. In this case, an oxidation reaction takes place. The lifetime of the tubes can be increased by use of a special alloy 601 H grade. Pitting may be observed in coal combustion systems. It has also been observed on alloy 601 after service in ceramic firing kilns where it is promoted by the presence of chlorine. Additionally, pitting occurs under carburizing conditions (metal dusting) as does cracking being similar in appearance to stress corrosion cracking in aqueous corrosion. Compared to deposit-induced and grain boundary corrosion, crevice corrosion is of minor importance in high-temperature corrosion. Only one example has been identified so far on alloy 600 but which may also be interpreted as a kind of deposit-induced corrosion.     

Influence of cerium implantation on the nucleation and growth of corrosion products on alloy 800H in a mixed sulphidizing/oxidizing environment

The influence of implantation of cerium on the corrosion behavior of an 32Ni-20Cr austenitic steel, Alloy 800H, in a simulated coal-gasification atmosphere has been examined at 700°C. The composition and microstructure of the corrosion products formed after exposure periods between 1 min and 200 h were examined with a range of surface-analytical techniques. The corrosion mechanism of Alloy 800H was characterized as a mixture of oxidation and sulphidation, primarily of Cr and Fe. The oxides provided protection against catastrophic sulphidation. Cerium implantation reduced the corrosive attack, providing the dose was sufficient. The corrosion was more uniform and the products had a higher Cr/Fe ratio compared to those on the unimplanted alloy. It is proposed that these changes resulted from the formation of a more protective and more stable oxide layer, due to the rapid formation of ceria particles, specifically hindering the formation of the less-stable oxides and sulphides.     

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.     

The hot corrosion of Co-25Cr-10Ni-5Ta-3Al-0.5Y alloy (S-57)

A cobalt-base alloy, Co-25 Cr-10 Ni-5 Ta-3 Al-0.5 Y (S-57), was subjected to hot corrosion in Mach 0.3 burner rig combustion gases at maximum alloy temperatures of 900 and 1000°C. Various salt concentrations were injected into the burner; 0.5, 2, 5 and 10 parts per million synthetic sea salt and 4 parts per million sodium sulphate (Na₂SO₄). The extent of corrosion was determined by measuring the maximum depth of corrosion in the alloy and the corrosion process was studied by metallography, X-ray diffraction, scanning electron microscopy, and electron microprobe analysis. While S-57 was found to possess only moderate oxidation resistance at these temperatures, this alloy resisted significant hot corrosion attack under all but the most severe test conditions. The process of the hot corrosion attack under the most severe conditions of this study was primarily sulphidation.     

Evaluation of high‐temperature corrosion life using temperature gradient corrosion test with thermal cycle component in waste combustion environments

In energy conversion facilities such as boilers and pyrolysis reactors that burn waste, fossil fuel, biomass and other materials, many corrosion factors, such as gas temperature and fluctuations in gas temperature, the condition of deposits, and gas composition, influence the high‐temperature corrosion rate of materials in a complex manner. In order to evaluate the corrosion behavior and corrosion life time of materials rapidly and accurately, a temperature gradient corrosion test (TGT) was developed and applied to waste incineration environments. The TGT with thermal cycle was carried out without corrosive deposits in order to investigate the basic effect of gas temperature and fluctuation on corrosion behavior, especially in terms of the stability of protective oxide layers. As a result, it was clarified that gas temperature enhances the environmental factors such as the deposition rate of ash and penetration of corrosive species, while thermal cycle mainly enhances material factors such as the breakdown of protective scales. Furthermore, three application case studies of TGTs for corrosion life estimation were carried out with a comparison between TGT and field corrosion data. From these studies, a good correspondence of corrosion rates between TGTs and field tests was obtained. This correspondence of corrosion rate was explained by the breakdown of the protective oxide layer and the penetration of corrosive species in a corrosion front. The reproducibility and applicability of TGTs in the evaluation of the corrosion life time of materials were clarified based on the consideration of various corrosion mechanisms.     

Long‐term exposure of austenitic steels and nickel‐based alloys in lignite‐biomass cofiring

The aim of this study was to assess the long‐term impact that the addition of biomass provokes on superheater materials exposed to fireside corrosion environments. Alloys covering a broad range of commercially available materials were investigated. Their corrosion kinetics under different corrosive deposits and atmospheres was evaluated, and their corrosion products analyzed to deepen understanding of the underlying corrosion mechanisms. Therefore, three nickel‐based alloys and three austenitic steels containing 20–24 wt.% Cr were tested at 650°C for 7,000 hr. The long‐term exposure shows new mechanistic aspects of Type II hot corrosion that were revealed by accelerated material depletion. The formation of Ni–NiS eutectic and the formation of a Cr depleted zone close to the substrate corrosion product interface are indicative of the breakaway occurrence. Differences in the corrosion behavior are related to the balance of Ni, Mo, Co, and Cr and can serve as the material selection argument. The evaluation concluded with the finding that alloys presenting Mo and Ni might be preferentially used in fireside corrosion in the presence of biomass, whereas the use of austenitic steels suffer less corrosion if no biomass is present in the corrosive atmosphere.     

Corrosion‐technical properties of high‐strength stainless steels for the application in prestressed concrete structures

Experience with prestressed concrete over about half a century has indicated that the corrosion resistance of conventional prestressing steel does not always satisfy, especially the prestressing steels are susceptible to chloride attack (de‐icing salts) and hydrogen (hydrogen‐induced stress corrosion cracking). On the other hand corrosion agents, such as chloride, condensation water, can penetrate in the concrete and arrive at the surface of steels. Hence, corrosion damage of prestressing steels can happen and, in the extreme cases, the prestressed concrete structure collapsed resulting from the failure of the tendon. In this paper, consideration is made to use high‐strength stainless steels as prestressing tendon with bond in concrete. The high‐strength stainless steels of qualities 1.4301 (X5CrNi18‐10), 1.4401 (X5CrNiMo17‐12‐2), 1.4436 (X3CrNiMo17‐13‐3) and 1.4439 (X3CrNiMoN17‐13‐5) with sequence of increasing austenite stability were investigated. For application in prestressing tendon with bond in concrete the cold‐drawn high‐strength stainless steel of quality 1.4401 is an optimal proposition regarding its satisfactory resistance against pitting corrosion and stress corrosion cracking (SCC) in structure‐related corrosive conditions. The lower alloyed steel 1.4301 has an insufficient resistance against the chloride‐induced corrosion because of the lack of molybdenum and the content of deformation martensite due to the strong cold‐drawing of its unstable austenitic structure.     

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.     

The effect of phosphorus-containing additives in fuels on automobile exhaust valve corrosion

It is suggested that the burning of exhaust valves involves the participation of sodium sulphate, arising from salt ingested with the air and sulphur in the fuel. Phosphate salts, such as lead phosphate which arises from lead anti-knock additives and phosphorus ignition control additives, may increase this accelerated attack. To test the roles of the various possible salt species the effect of mixtures of sodium sulphate and lead phosphate, sodium sulphate and sodium phosphate, lead sulphate and lead phosphate, and sodium sulphate and phosphorus pentoxide on the corrosion of a stainless steel, Fe-18% Cr, the cobalt-base alloy X-40 and the nickel-base alloy Nimonic 115 in a crucible test have been studied.The results show that the presence of sulphates markedly enhances corrosion, with internal sulphides being formed: in alloys containing nickel a liquid sulphide can be formed resulting in accelerated attack. The presence of phosphorus enhances the attack of sodium sulphate: for these alloys pure sodium sulphate is not particularly aggressive, but the addition of phosphate salts resulted in heavy corrosion.Phosphorus-rich mixtures appeared to be capable of producing a type of corrosion involving direct participation of phosphorus, forming phosphides or phosphates of the metals.The presence of sodium is not essential for heavy attack. Lead sulphate-lead phosphate mixtures produced heavy corrosion of all the alloys studied.     

Corrosion of carbon steel underneath a lead/potassium chloride salt mixture

High amounts of lead in waste/recycled wood fuel are known to be a contributing factor to the increased corrosion often related to this type of fuel. In combination with potassium, usually present in the fuel, low‐melting point salt mixtures between lead chloride (PbCl ₂) and potassium chloride (KCl) are expected to form. The purpose of this study is to investigate reactions in the mixed salt of PbCl ₂ and KCl and its interactions with carbon steel P265GH and its oxide. Laboratory exposures were performed in an isothermal tube furnace with a salt mixture of PbCl ₂/KCl (50/50 mol%) put on steel samples. The test duration was 24 hr at either 300°C or 340°C in an atmosphere of 100 ppm HCl and 20 vol% H ₂O in synthetic air. After exposure, the salt mixture consists of distinct areas of KCl and PbCl ₂ but also the compounds K ₂PbCl ₄ and KPb ₂Cl ₅. A general observation is that the oxide thickness increases with temperature and that areas with Pb/K‐mixed salt are frequently found in close connection to more corroded areas. Often the more lead‐rich phase KPb ₂Cl ₅ is located closest to the corrosion product indicating its importance for the corrosion.