Fireside Corrosion

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Chapter 16
Fireside Corrosion

16.1 Introduction

The problem of high temperature fireside corrosion in coal‐ and oil‐fired steam generating plants, and generally in heat‐recovery units, has been well recognized over the past decades.

Its practical importance is easily understood considering that damages are not always limited to the replacement of corroded tubes and to the consequent interruption of steam production. Indeed, the blowdown may cause well heavier losses as, for instance, the breaking off of steel production should the damage occur in a heat‐recovery unit of a steel plant.

Since the end of World War II, when the first cases of fireside corrosion were experienced, a great deal of research has been conducted in order to elucidate corrosion mechanisms and to assess methods of preventing it. Soon it became apparent that corrosion was primarily due to the condensation from the flue gases, on the comparatively cool metal tubing surfaces, of highly aggressive deposits that, at the operating tube temperature, were soft or liquid. Whether such deposits come entirely from the flue gases or are formed through a reaction between flue gas component and tube metal has been a matter of speculation, and some issues have not yet been fully resolved. Nevertheless, the important point is that whatever the origin of deposits, their aggressiveness largely depends on their physical state, i.e. the molten or semi‐molten state.

Deposits from fireside areas that have suffered external corrosion almost invariably contain appreciable quantities of alkali sulfates. The amount of such constituents largely depends on the nature of the burning fuel; it ranges from 35% to 50% sulfur reported as SO3 in coal‐fired furnaces to 25–45% in oil‐fired units. In every case, such deposits are water soluble, with a pH as low as 3, the acidity being due to the excess of SO3 in alkali sulfates released by hydrolysis. The nature of these complex deposits has been investigated since their existence was recognized more than 70 years ago. These sulfates are reported as complex trisulfates whose chemical stability depends primarily on temperature and SO3 content of the atmosphere. Actually, their formation could be explained by the following reaction:


Of the three reagents, at least two come from the flue gas and therefore from the fuel, the third, iron oxide, from the tube oxide scale. On the other hand, the formation of aluminum trisulfates, for example, may be entirely caused by reagents coming from the environments: that is the case of coal‐fired furnaces where larger bulks of aluminosilicate materials come from combustion residues.

Obviously enough, the early investigations attempted to reproduce in the laboratory the corrosion phenomena encountered in the field. These investigations helped to understand the fundamental role of SO3 in the progression of Reaction 16.1 as well as the importance of temperature level in deciding the stability of complex trisulfates. Their occurrence and hence their aggressiveness is restricted to a relatively narrow temperature range. Furthermore it was recognized that the SO3 concentrations usually encountered in flue gases (25–35 ppm) were insufficient to progress Reaction 16.1 in laboratory experiments where a SO3 concentration as high as 250 ppm was found necessary. Actually, the slow attainment of equilibrium of reaction


causes SO3 to be only about 1% of the SO2 in the flue gas. Thus, a good deal of research has been conducted to establish the catalytic effect of iron oxide surfaces to speed up the formation of SO3 in Reaction 16.2 in order to explain the practical occurrence of complex trisulfates.

It has been a matter of controversy the mechanism through which the tube wastage by molten complex sulfates takes place. Some authors maintain that the metal loss is essentially due to the scale‐destroying Reaction 16.1 in which complex sulfates are formed. Its progression depends on periodic tube deslagging and subsequent thermal decomposition of trisulfates to provide the necessary SO3. Others believe that losses are due to a direct redox reaction of complex sulfates on the tube metal through a scale‐creating irreversible pattern:


Reactions 16.1 and 16.3 are somewhat different, the latter taking place at higher temperatures and its progression generating in addition to iron oxide also iron sulfate as corrosion product. Furthermore, the complex sulfates are generated in the ash deposits, and the contact between the tube metal and the corrodent is provided by migration of molten deposits under a thermal gradient.

Previous discussion has been confined to molten sulfates as cause of metal wastage in boilers. Actually in oil‐fired units, deposits contain appreciable amounts of vanadium compounds. Vanadium comes from the oil, and vanadate formation takes place through an acid–base reaction in the flue gas with alkali metal species also coming from the fuel; vanadates subsequently condense on superheater tubes as liquid aggressive layers.

Other components that could be responsible for corrosion by flue gas deposits are chlorides. These can be found in both coal‐ and oil‐fired boilers; the conditions of their occurrence, as well as their general behavior, are well described by Lai (2007). The conclusions are that excepting the case of nonequilibrium conditions in which anomalous situations may arise, chlorides entering the system with fuel will remain mostly in the gas phase without participating in the corrosion process. Therefore, as written previously, high temperature fireside corrosion in coal or oil burning boilers is best outlined by admitting the presence of molten or semi‐molten deposits. Obviously, corrosion is affected by transport processes across deposits and by reactions occurring at gas–deposit interfaces and deposit‐metal surfaces. The presence of a molten phase is a sufficient prerequisite to stimulate both transport processes and heterogeneous reactions, providing a more intimate contact between metal and corrodents. An additional factor is the presence of SO3 (either as “excess” sulfate in complex sulfates or as dissolved sulfur trioxide) that, besides stabilizing the physical state of deposits, enhances corrosion by increasing the metal oxide solubility in the molten phase and, acting as oxygen carrier, by increasing the oxidizing power of deposits.

It is the aim of this chapter to briefly delineate mechanisms, remedies, materials problems, and other current views related with this field of high temperature fireside corrosion. A brief summary of industrial experience of fireside corrosion in Denmark, Germany, Holland, the United Kingdom, and Japan is also included.

16.2 Coal‐Fired Boilers

The principle of a thermal power plant is to produce electricity by burning a fuel generally consisting of coal, biomass, or waste. Electricity is produced by the process of heating water in a boiler to yield steam. The steam under pressure, heated to high temperature in the superheater part, flows into a turbine, which drives a generator to produce electricity (Figure 16.1).


Figure 16.1 Principle of a coal‐fired power plant.

In today’s conventional coal‐fired power plants, the steam is brought to above 22 MPa and above 540 °C in a supercritical state.

Since the energy crisis in the 1970s, there has been a constant need for increasing the efficiency of thermal power plants. In other words, the development aimed at increasing the amount of electricity produced for the same fuel consumption. The general route that has been followed consists of increasing the steam parameters, temperature, and pressure in the plant. As an example, the total efficiency of a plant increases by nearly 6% when changing the steam parameters from 538 °C/18.5 MPa to 593 °C/30 MPa. It could even reach an 8% increase at 650 °C (Viswanathan and Bakker 2000). One of the most modern coal‐fired power plants commissioned in 2002 in Niederaussem in Germany demonstrates quite well the current state of the development with a fuel conversion efficiency of 43% and steam parameters up to 580 °C and 28 MPa (Heitmüller and Kather 1999). Furthermore, the Kyoto Protocol ratified in 1997 by many countries, including the European Union, plans a significant reduction of greenhouse effect gas emissions. These include first of all CO2 but also NOx (Kyoto Protocol 1997).

At the same time, predictions indicate that the global electricity demand will continue to increase at an average of 2% per year until 2020 (Parker 2002). To cover these new capacity demands, the global coal consumption is planned to increase by 60% between 2000 and 2020 (Figure 16.2). Coal is a cost‐effective fuel, which will have a significant role at least until the efficiency of renewable energy products is improved in the next 20 years.


Figure 16.2 Trends in global electricity production from 1971 to 2020 (Parker 2002).

The electricity production from waste or biomass is also planned to increase. Waste firing offers a solution for reducing the increasing amount of waste, especially municipal waste. Biomass, like wood or straw, is a renewable fuel that can be considered as a long‐term alternative to the decreasing amount of fossil sources.

Meeting both the Kyoto requirement and the increase of the electricity production leads to the need of improving the efficiency of the fuel to power conversion processes, which by extension means an increase of the steam parameters. For coal‐fired systems, temperatures up to 720 °C or even 760 °C with a pressure of 35 MPa are currently under consideration in Europe and in the United States, respectively. The aim is to achieve a thermal efficiency of 60% by the year of 2020 (Ruth 2003).

The superheater tube temperatures often exceed the steam temperature by as much as 30 °C (Viswanathan 2004). This application thus requires a material with high temperature creep resistance. During the last decades, high temperature steels or more recently nickel‐based alloys have demonstrated their potential with regard to high temperature creep strength. Nevertheless, metallic materials are well known for expanding when increasing the temperatures. The use of materials with low coefficient of thermal expansion is thus required in order to minimize the generated mechanical stresses. Moreover, the thermal conductivity of the superheater components has to be kept as high as possible in order to maximize the efficiency of the energy conversion. For building a superheater, several tubes must be welded together. Therefore, the weldability of the materials involved has also to be optimized.

Depending on the type of fuel, the combustion produces hot gases of various concentrations but is usually composed of O2, COx, SOx, HCl, H2O, and NOx. Furthermore, depending on the tube temperature, solid or liquid ashes and salts are deposited on the superheater tube surfaces. Table 16.1 gives the typical species found in various deposits. For coal‐fired plants, the deposits contain usually sodium or potassium sulfates, whereas for waste‐fired plants, the deposits are rather composed of alkali or heavy metal chlorides, due to the unceasing increase of the polyvinyl chloride (PVC) plastic content in refuses. Concerning biomass firing, the deposits are usually composed of potassium chlorides or potassium sulfates.

Table 16.1 Typical salt deposits found on superheater tubes

Type of fuel Typical salt deposits
Waste ZnCl2, PbCl2, KCl, NaCl
Straw KCl, K2SO4
Wood KCl, K2SO4, NaCl, Na2SO4
Coal Na2O4, K2SO4, (Na,K)2Fe(SO4)3

Molten sulfates and chlorides, as well as the gases mentioned earlier, are known for provoking corrosion damage at high temperature (Kofstad 1988). Moreover, on the inner side of the tube, the high temperature steam can lead to rapid oxidation. As a consequence, in addition to high creep strength, low thermal expansion, high thermal conductivity, and good weldability, the superheater tubes have to resist high temperature corrosion.

The mechanisms describing this form of corrosion are various and complex with strong dependence on the type of material and environment. They involve reactions such as oxidation, chlorination, carburization, sulfidation, and chemical/electrochemical in molten or semi‐molten salt deposits. The reader can find detailed explanations on these reactions in Chapters (oxidation), 8 (sulfidation), 9 (carburization), 11 (chlorination), and 13 (molten salts).

A major piece of the equipment in the power plant is the boiler, which generates steam that is then delivered to the turbine for generation of electricity. This section reviews materials issues and corrosion problems associated with utility boilers. Therefore, the boiler basics, including its description and types of coal and coal ash, are now presented to help readers to better understand these matters. Then, important high temperature materials and corrosion problems in coal‐fired power plants will be discussed.

A large utility boiler consists of a large firebox, within which the combustion takes place. A number of burners are installed in the walls, through which the pulverized coal is blown. The walls of the firebox are manufactured with vertical tubes, typically between 70 and 100 mm of outside diameter, joined by webs of the order of 30 mm width. This is “membrane wall” construction. Preheated water enters the bottom of these walls, which are usually called the waterwalls, and boils at some location usually a little above the top of the burner array. The effective temperature in the combustion zone is in the range of 1200–1800 °C. As the combustion gases rise in the furnace, they cool; at the top of the furnace, the temperature is of the order of 1000–1200 °C, and the gas turns into a horizontal section. In this section, and sometimes at the top of the furnace itself, there are tubular platen heat exchangers hanging down into the combustion gas stream: these are commonly superheaters, and the principal corrosion problems are in the superheaters and the waterwalls (Meadowcroft 1987).

The majority of the utility boilers are subcritical recirculating boilers with a main steam pressure of approximately 16 MPa. The boiling point at this pressure is about 350 °C, and the outer surface of the waterwall tubes will be about 50 °C above this. The superheat temperature is 538 °C, and the maximum outer metal temperature in the superheater may be as much as 100 °C above this because of nonuniformities in the temperature distribution across the superheater bank.

The materials for the pressure parts are selected on the basis of their mechanical properties. For the lower temperature parts, the tensile strength is limiting; for the higher temperature parts, the creep strength is critical. The majority of the tubes, pipes, and drums are manufactured with plain carbon steel or low‐alloy ferritic steels; the highest ferritic alloy normally used is T (or P) 22, which is essentially 2Fe–1/4Cr–1Mo. The very last sections of the superheater and reheater exchangers may be manufactured with austenitic steel (Meadowcroft and Manning 1983).

There are two main high temperature corrosion problems that may be identified in utility boilers:

  1. The fireside corrosion of the superheaters and reheaters.
  2. The fireside corrosion of waterwalls.

Figure 16.3 indicates the typically affected regions in a fuel‐fired boiler.


Figure 16.3 Schematic of a typical fuel‐fired boiler showing areas of corrosion.

There are several methods for burning coal. Firing with pulverized coal has been the most dominant method for utility boilers. Coal is burned as fine powders suspended in the furnace and almost all types of coal from anthracite to lignite can be burned by pulverized firing. Pulverized coal in particle sizes of 50 μm diameter or smaller can be completely combusted in a matter of one to two seconds.

Stultz and Kitto (1992) developed the cyclone furnace for firing coal grades that have a low fusion temperature and are not suitable for pulverized coal firing because of potentially forming a molten slag, thus developing a severe slagging problem in superheaters. In cyclone boilers, the cyclone barrels burn coal in such a way that most of the coal ash is captured to form a molten slag that coats the inside surface of the cyclone barrels. The combustion flue gas from the cyclone barrels then enters the main furnace to generate steam (Stultz and Kitto 1992).

There are four different types of coal. The youngest, or lowest‐rank coal, is lignite, which is then followed by an older, or higher‐rank subbituminous coal, then bituminous coal, and then anthracite coal. Heating values, moisture content, volatile matter content, ash content, and sulfur content can be different among these different types of coal. Bituminous coal is the most commonly used coal for utility boilers in the United States. Subbituminous coal in the United States generally contains very low sulfur, with many deposits containing less than 1%. Table 16.2 shows the properties of some US coal. There is a great variation in moisture, ash content, ash softening temperatures, and sulfur content from various grades of coals. The material factors associated with coal can directly or indirectly affect the boiler tube material performance at different locations in the boiler.

Table 16.2 Properties of several types of US coal (Stultz and Kitto 1992)

Coal type
Property Anthracite Illinois #6 bituminous, Illinois Spring Creek subbituminous, Wyoming Bryan lignite, Texas
Approximate composition (%)
Moisture 7.7 17.6 24.1 34.1
Volatile matter, dry 6.4 44.2 43.1 31.5
Fixed carbon, dry 83.1 45.0 51.2 18.1
Ash, dry 10.5 10.8 5.7 50.4
Composition (%)
Carbon 83.7 69.0 70.3 33.8
Hydrogen 1.9 4.9 5.0 3.3
Nitrogen 0.9 1.0 1.0 0.4
Sulfur 0.7 4.3 0.4 1.0
Oxygen 2.3 10.0 17.7 11.1
Ash 10.5 10.8 5.7 50.4
Thermal properties
Heating value (as received) Btu/lb 11 890 10 300 9 190 3 930
Ash fusion temperatures (reducing atmosphere) (°F)
Initial deformation 1 930 2 100 2 370
Softening 2 040 2 160 2 580
Fluid 2 700 2 700 2 900+
Ash analysisa (%)
SiO2 51.0 41.7 32.6 62.4
Al2O3 34.0 20.0 13.4 21.5
Fe2O3 3.5 19.0 7.5 3.0
TiO2 2.4 0.8 1.6 0.5
CaO 0.6 8.0 15.1 3.0
MgO 0.3 0.8 4.3 1.2
Na2O 0.7 1.6 7.4 0.6
K2O 2.6 1.6 0.9 0.9
P2O5 0.4
SO3 1.4 4.4 14.6 3.5

aElements present in the ash are determined and reported as oxides.

Sulfur is the most important impurity in coal for causing high temperature corrosion in the boiler. Sulfur is present in coal in the form of organic sulfur, pyritic sulfur (i.e. pyrite), and iron sulfate. High sulfur coals also cause SOx emission problems and require expensive air pollution control equipment. As a result of the US Federal Clean Air Act emissions issues, the low sulfur Powder River Basin (PRB) coal (a subbituminous coal) has become extremely popular in the past years. The PRB coal, which is from mines in southern Montana through northern Wyoming, contains less than 0.6 kg of sulfur per million Btu, making it compliant with the Clean Air Act emissions limits without air pollution control equipment.

One of the important characteristics of ash is its fusion temperature. Table 16.2 lists the ash fusion temperatures of several coals under reducing conditions. These fusion temperatures can affect the nature of the ash deposits, whether in the form of “dust” or a tenacious slag. If ash reaches the heat‐absorbing surface at a temperature near its softening temperature, the resulting deposits are likely to be porous and can be easily removed by sootblowing. Also, if such a deposit is subjected to high gas temperature, the ash deposit can reach its melting point (due to the thermal insulating properties of the ash) and run down the furnace wall surface. This solidified slag is tightly bonded and is difficult to remove. This slag may require water lances or water cannons to create thermal shock for the removal of this slag deposit. The furnace walls that are subject to radiant heat are likely locations for developing this slagging problem.

The analyses of ash for several types of US coal are shown in Table 16.2. The compositions shown in Table 16.2 are presented as oxides. However, most ash constituents in coal are minerals. Typical minerals found in coal are shown in Table 16.3. When these minerals are exposed to oxidizing environments at appropriate high temperatures, oxides and/or complex salts are formed as stable phases. This is illustrated in Table 16.4.

Table 16.3 Typical mineral species found in coal

Mineral species Formula
Kaolinite Al2O3·2SiO2·H2O
Illite K2O·3Al2O3·6SiO2·2H2O
Biotite K2O·MgO·Al2O3·3SiO2·H2O
Orthoclase K2O·Al2O3·6SiO2
Albite Na2O·Al2O3·6SiO2
Calcite CaCO3
Dolomite CaCO3·MgCO3
Siderite FeCO3
Pyrite FeS2
Gypsum CaSO4·2H2O
Quartz SiO2
Hematite Fe2O3
Magnetite Fe3O4
Rutile TiO2
Halite NaCl
Sylvite KCl

Source: Singer (1991).

Table 16.4 Melting points of coal‐ash constituents

Element Oxide Melting point, °C (°F) Compound Melting point, °C (°F)
Si SiO2 1715 (3120) Na2SiO3 877 (1610)
Al Al2O3 2043 (3710) K2SiO3 977 (1790)
Ti TiO2 1838 (3340) Al2O3·Na2O·6SiO2 1099 (2010)
Fe Fe2O3 1565 (2850) Al2O3·K2O·6SiO2 1149 (2100)
Ca CaO 2521 (4570) FeSiO3 1143 (2090)
Mg MgO 2799 (5070) CaO·Fe2O3 1249 (2280)
Na Na2O Sublimes at 1277 (2330) CaO·MgO·2SiO2 1391 (2535)
K K2O Decomposes at 349 (660) CaSiO3 1540 (2804)

Source: Singer (1991).

If the ash constituents are present as oxides, the ratio of basic oxides (e.g. Fe2O3, CaO, MgO, Na2O, and K2O) to acidic oxides (e.g. SiO2, Al2O3, and TiO2) may determine the fusion (fusibility) temperature of the reaction product. It was reported that the ash may exhibit low fusibility temperature with higher slagging potential when its base–acid ratio is in a range of 0.4–0.7. Many other parameters, such as SiO2/Al2O3 ratio, Fe2O3/CaO ratio, Fe2O3/(CaO + MgO) ratio, (Na2O + K2O), and so forth, are also used for predicting the fusibility temperature of the coal ash. It has been suggested that SiO2 is more likely than Al2O3 to form lower‐melting species. The fusibility temperature of coal ash will be lowered when the Fe2O3/CaO ratios are in a range of 0.2–10. Alkalis are important in affecting the fusibility of coal ash and the furnace slagging potential. Many sodium compounds melt at temperatures below 900 °C, playing an aggressive role in fireside corrosion.

Chlorine content is also an important indication for fouling potential. When chlorine in coal is greater than 0.3%, fouling potential becomes high. Alkali metals and chlorine can also play a significant role in high temperature corrosion in boilers.

We have been discussing complex corrosion phenomena and other issues in typical boilers being evident that to help the reader’s understanding, the important high temperature corrosion aspects in coal‐fired power plants should be rapidly summarized at this stage.

In coal‐fired power plants, besides corrosion damage due to molten salts, corrosion can occur by oxidizing flue gas and other reactions as already reported. Depending on the way the combustion is carried out, the gases emanating from the combustion can be either reducing or oxidizing. The typical gaseous species encountered in oxidizing conditions are O2, NOx, HCl, SOx, H2O, and COx.

With respect to the high sulfur content in some types of coals, particular attention has to be given to sulfur‐containing gases. Indeed, it is well known that in most cases, sulfidation kinetics are much faster than those of oxidation and that sulfides are usually non‐protective other than oxides.

The second corrosive element is chlorine, which is usually found as HCl in combustion products. Chlorine is particularly detrimental because of the formation of low temperature eutectic melts and high volatile metallic chlorides that can form at high temperature and lead to rapid metal loss. Furthermore, Rahmel and Tobolski (1965) proposed a mechanism explaining the acceleration of the oxidation of pure iron in the presence of water vapor or CO2. This mechanism is based on the formation of cracks within the oxide scale. After some time, these cracks are filled with H2O/H2 or CO2/CO, respectively. As shown in Figure 16.4 for H2O‐affected oxidation, a repeated reduction of H2O at the metal surface and oxidation of H2 at the gas–oxide interface is put in place within the crack. As a consequence, the presence of H2O or CO2 enables further oxidation of the metal without substantial inhibition. This mechanism is still accepted nowadays. Many studies focused on the corrosion mechanisms of one or two types of corrosive species, for example, SOx or SOx combined with O2 as reviewed by Kofstad (1988). Others focused on the effect of chlorine, in particular HCl combined with O2 (Zahs et al. 1998). On the other hand, in‐plant studies are generally governed by molten salt corrosion and are hardly comparable due to differences in plant operation and the difficulty for precisely analyzing the combustion gases. In fact, there seems to be only a limited number of studies addressing the corrosion resistance of 9–12% Cr steels in simulated coal firing flue gas, containing three or more oxidizing species, as will be presented later.


Figure 16.4 Acceleration of the oxidation mechanism by the formation of metal oxide bridges due to the presence of H2/H2O in a crack between iron and wustite (Rahmel and Tobolski 1965). The same mechanism applies for CO/CO2.

Fireside corrosion of the steam‐containing superheater and reheater tubes due to the deposition of fuel impurities from the flue gas at its highest temperature is a significant problem, and considerable research has been carried out concerning this corrosion process. Since it has been shown that accelerated wastage of superheater and reheater tubes occurred under an ash deposit, much research work has involved exposing metals and alloys to molten salt baths, building up a thin sulfate film of around 1–2 mm thickness, to replicate typical deposits found on the tubes (Figure 16.5).


Figure 16.5 Section showing deposit layers on a leading superheater or reheater tube.

The black inner layer is iron oxide, essentially Fe3O4, and is typically 2.20 μm thick. The white layer contains majorly sulfates of Na, K, and Al, with some Fe. This is the molten sulfate layer and is usually around 1 mm thick. The “red slag” layer is high in Fe, low in alkali, and with a sulfate content intermediate between that of the white deposit and the ash. The adhering fly ash is rich in Fe2O3 and remains porous, even if sintered. Dissolution of both white and red layers in water produces acidic solutions.

Figure 16.6 shows the temperature distribution through the system for a typical set of conditions. This diagram is however oversimplified. The overall heat flux to a superheater tube is of the order of 0.2 MW m−2. It is however evident from Figure 16.5 that the thickness of the insulating ash layer is greater at the front, leading, position of the tube than the rear, trailing, area. This results in a variation in the heat flux around the tube. Wastage takes place at the “2 o’clock” and “10 o’clock” positions relative to the flow of the flue gases, the “12 o’clock” position. The heavy buildup of ash on the front surface reduces the temperature flux within the deposit below that required for the salt layer to be molten. The thinner ash levels at the side of the tube allow for a higher heat flux, and a molten layer beneath, at the deposit–metal interface.


Figure 16.6 Schematic of a typical thermal gradient through a deposit from flue gas to superheater metal.

The origin and role of the molten salt layer, and its associated fly ash, may be summarized as follows. The cations arise largely from the clay component of the coal, and the sulfate ions from the oxidation of the sulfur in the fuel to SO2. The air entering the combustion chamber contains about 10% more oxygen than necessary for stoichiometric combustion, and Fe2O3 in the fly ash acts as a catalyst to convert the SO2 to SO3. Fuels containing vanadium, such as fuel oil, often used in the start‐up process in boilers, provide an even more effective catalyst for SO3 formation. SO3 readily dissolves in the molten sulfate, forming essentially pyrosulfate ions [S2O7]2−: SO3 and O2 are the main oxidants and SO2 is insoluble in sulfate melts.

The SO3 present in the flue gas has the major effect on the corrosion of metal tubes, since this determines the oxidizing potential of the sulfate deposit, in terms of the redox equilibria:


The corrosion process is thus two separate reactions. First, an anodic oxidation, by


to form metal ions in the corrodant (n may be 2 or 3 but here will be assumed as 2). Thus


Second, the cathodic reaction is transfer of electrons to the oxidizing agent


More specifically, for the reduction of images and/or SO3, we can write



These equations are oversimplified and the reaction mechanism is better understood by considering a steady state in which SO2 and O2 from the flue gas enter the porous fly ash. The catalytic action of Fe2O3 then produces equilibrium concentrations of SO3. SO3 dissolves in the melt and migrates to the oxide–melt interface. Then, it diffuses through the porous oxide to the oxide–metal interface.


This is regarded as the overall result of the electrode Reactions 16.6 and 16.7. Solid metal oxides and sulfates result from the subsequent oxidation of the metal together with metal ions in the sulfate melt. Dissolution of the metal oxides at the oxide–melt interface takes place, viz.


with some of the metal sulfide being converted to the oxide, introducing imperfections in the oxide scale as it forms.

The solubility and stability of the dissolved metal ions in the melt is dependent upon both SO3 partial pressure and temperature, increasing with increase in SO3 content, but decreasing with increasing temperature. A mutual opposition is thus seen for the effects of SO3 partial pressure and temperature on traversing from the oxide–melt to the melt–fly ash interface such that a temperature is reached where the dissolved metal ion is precipitated as the oxide. A resulting concentration gradient of dissolved metal ions across the melt was thus envisioned and has been shown (Griffiths et al. 1982).

The corrosion process is therefore considered as the continuous dissolution of metal and metal oxide, reprocessing to form a non‐protective layer at the melt–fly ash interface. Considering all the factors involved, the rate‐determining step for the dissolution of the protective layer that the steel tubes generate, the overall rate of corrosion process, is that of the diffusion of metal ions away from the metal–metal oxide interface.

The transition metal ions from the steel tubes in the sulfate melt do not behave like the alkali metal ions Na+ and K+ – they form complexes with the sulfate ions:


The evidence for this comes from the electronic absorption spectra of such melt systems. The spectra obtained all correspond to the presence in solution of the metal ions surrounded octahedrally by six oxygen atoms. It is therefore concluded that each of the metal ions has three bidentate sulfate ions coordinating to it.

In 2002, Masuyama presented a review of the last 50 years of alloy development for power plant applications. Four generations of the evolution of ferritic steels since the 1950s are distinguished on the basis of their creep properties. The alloy development has indeed been motivated by the enhancement of the creep strength. The 105 hour creep‐rupture strength at 600 °C is the parameter typically used for alloy classification (Figure 16.7). It reaches 140 MPa in the current state of the art. But among the commercialized 9% Cr steels, the P91 has been extensively used for heaters and steam pipes in plants operating at temperatures up to 593 °C.


Figure 16.7 Development progress of ferritic steels (Masuyama 2002). Some commercial steels are indicated in italics.

From a metallurgical point of view, the steels presented in Figure 16.7 are either called ferritic or martensitic steels. In fact, both designations are correct depending on the heat treatment. For instance, P91 results from a specific heat treatment that consists of an austenitization step followed by rapid cooling for the martensitic transformation. A subsequent tempering is then required to transform part of the martensite into ferrite and allow carbides to precipitate homogeneously within the martensite.

The steel development shown in Figure 16.7 has mainly consisted of adding alloying elements with strengthening effects (Viswanathan and Bakker 2000). W, Cr, Mo, and Co are used for solid solution strengthening, and the latest tendency was to replace Mo by the more beneficial W. W, Cr, and Mo also contribute to precipitation strengthening by formation of carbides, whereas V and Nb used in junction with N contribute to precipitation strengthening by forming carbonitrides. Although carbon is required for the fine carbide precipitation, the carbon content remains limited, below 0.12 wt%, in order to obtain a good weldability. Nickel additions improve the toughness but are detrimental to creep strength. Therefore, some developments, such as for HCM12A, consisted of replacing part of the Ni by Cu. Finally, Cr additions have been rather motivated by the enhancement of the corrosion resistance, which will be discussed.

The oxidation resistance of 9–12% Cr steels, especially the P91, has been extensively studied in various environments including air in order to simulate fireside corrosion.

It was demonstrated that changes of the surface conditions of the 9% Cr steels influence the formation of a protective chromia layer (Grabke et al. 1997), in particular during the very early stage of oxidation. First of all, the early formation of chromia is strongly influenced by the Cr diffusivity toward the surface. This is enhanced when the dislocation density is increased by previous deformation of the subsurface zone, using sandblasting, for instance (Ostwald and Grabke 2004). Moreover, in the first 10–15 minutes of oxidation, local effects are of great importance. Fast Cr diffusion along grain boundaries lead to the nucleation and growth of chromia. However, in other areas, formation of less protective Fe‐rich oxides was reported for 9% Cr, whereas a Cr content higher than 11% is more favorable for the formation of Cr‐rich oxides without local differences (Grabke et al. 2004).

By considering exposure times of several thousand hours, the minimum Cr content required for the formation of a protective chromia scale was estimated to about 7.2 wt% (Vossen et al. 1997).

Obviously, a little drop in the Cr content completely changes the nature of the oxide scale. As a consequence, the evolution with time of the Cr content in the subsurface zone has to be considered with care. Indeed, the oxidation is consuming Cr; thus, after some time, the Cr concentration falls under the level required for forming the protective oxide layer. This can be particularly detrimental in the case of scale cracking, because the Cr‐depleted metal is then directly in contact with the corrosive environment. The resulting oxide scale is thus not protective anymore. This phenomenon explains the high corrosion rates observed for cyclic oxidation (Pillai et al. 2004). In this case, scale cracking is accelerated due to the repeated cooling process and leads to accelerated Cr depletion.

Grünling et al. (1979) reviewed the corrosion mechanisms that can lead to a decrease in creep resistance. A few examples of these mechanisms are pore formation near the surface due to the growth of an oxide scale by cationic diffusion, depletion of the matrix in solid solution‐hardening elements as a result of selective oxidation, decomposition of hardening precipitates, and enhanced grain boundary slip by diffusion of noxious elements into the grain boundaries. More recently, it has also been suggested that injection of vacancies deep into the metal due to cationic oxidation may also play a role in the reduction of creep resistance due to oxidation (Dryepondt et al. 2005).

As mentioned before, the heat exchanger tubes are submitted to several constraints, resulting in creep, e.g. due to the high pressures inside the tube or other operational parameters. The formation of thick oxide scales has therefore several consequences for the service behavior of components:

  1. The loss of material reduces the availability load‐bearing cross section, so that as oxidation proceeds, the stresses acting on the component increase. The magnitude of the effect will, of course, depend on the initial wall thickness and the oxidation rate. By considering creep data measured in air as well as the oxidation rates mentioned earlier for steam and simulated coal firing, Ennis et al. (1993) and Nickel et al. (1998) evaluated the influence of oxidation on the creep resistance. For example, for a thin‐walled heat exchanger tube of about 5 mm wall thickness, the reduction of the load‐bearing cross section due to corrosion would have severe consequences for service life.
  2. The thermal insulation effect of a thick oxide scale, which reduces the heat transfer across the component wall, can lead to overheating. A small increase in component operating temperature can reduce the stress‐rupture life considerably.
  3. The matrix becomes depleted in those elements that are selectively oxidized to form the thick oxide scales, leading to microstructural changes and associated potential effects on the long‐term strength. This effect has been investigated in particular by comparing the creep‐rupture time in air of specimens preoxidized in steam with heat‐treated specimens (Ennis et al. 1993).

By the same method of testing the creep resistance in air of specimens preoxidized in steam, Schütze et al. (2004) investigated the effect of load on the oxidation behavior. This method particularly allowed comparing the healing properties of the oxide scale. Indeed, the imposed load brings the oxide scale to crack. The ability of the material to reform a protective scale will thus be crucial for its lifetime. For 9% Cr steels, it was shown that silicon offers some advantages for healing the protective oxide scale, but this effect is spoiled in the presence of Mo in dry environment.

The preceding description of the properties of 9–12% Cr steels shows that further increasing the heat exchanger temperatures will require higher corrosion resistance and creep strength. If this has to be achieved with chromia‐forming alloys, higher Cr contents are required (Staubli et al. 2002; Viswanathan et al. 2002). Table 16.5 shows the benefit of higher Cr contents with regard to corrosion resistance.

Table 16.5 Comparison of the properties of the ferritic–martensitic steel P91 (Haarmann et al. 2002), the austenitic steels AISI 347H (Wegst 1995), Incoloy Alloy 800, and the nickel‐based Inconel Alloy 617

Concentration in wt% 105 h Creep rupture stress
Type of material Cr Ni Coefficient of thermal expansion (10−6 K−1)a Thermal conductivity at 650 °C (W m−1 K−1) 650 °C 550 °C Hot corrosion weight loss at 650 °C/5 hb
Ferritic–martensitic P91 9 12.7 30 48 162 >40
Austenitic AISI 347H (1.4961) 17 13 18.6 24 64 170 17
Austenitic Alloy 800 20 32 17.3 22 60 200 10
Ni‐based IN617 22 Bal. 14.4 23 160 10

aCoefficient of linear thermal expansion from room temperature to 650 °C (10−6/°C).

bThe corrosion data is taken from Ikeshima for simulated coal firing tests with molten salts (Ikeshima 1983).

Furthermore, steam oxidation tests showed that depending on the grain structure, a minimum of 20–25 wt% is recommended for forming protective Cr2O3 oxide scale at 650 °C (Otsuka et al. 1989). This amount lies clearly above the limit of martensitic steels, and since body‐centered cubic ferritic steels have poor mechanical properties, the ferritic–martensitic steels are preferentially replaced by austenitic steels or Ni‐based alloys. However, at higher temperature, the low Cr diffusivities in austenitic steels limit the Cr supply toward the metal–oxide interface and therefore the ability of the alloys for healing a cracked oxide scale. In austenitic steels, increasing the Ni content seems to have a beneficial effect on the resistance to water vapor oxidation (Peraldi and Pint 2004). However, when comparing other properties of these materials, not only the higher costs are a drawback for the replacement of ferritic–martensitic steels. Firstly, the lower thermal conductivities of austenitics and nickel‐based materials limit the heat transfer (Table 16.5). Secondly, a higher thermal expansion has to be taken into account for plant design. This also means that the thermal expansion mismatch between the alloy and the oxide scale is higher, resulting in a higher tendency for oxide spallation. Thus, even though some austenitic steels form a thin protective Cr2O3 layer, with a thermal expansion of about 8 × 10−6 K−1 (Robertson and Manning 1990), this might spall off due to temperature changes. For comparison, up to 400 °C, the thermal coefficient for magnesite lies between 11 and 14 × 10−6 K−1 (Armilt et al. 1978), which is close to the expansion of P91. The tendency for oxide scale spallation is thus higher on austenitic steels compared with ferritic–martensitic ones. The concern is that spalled flakes appearing inside the exchanger tube lead to erosion and blocking of the steam turbine components. Yet, Peraldi and Pint (2004) observed that increasing the Ni content in austenitic steels reduces spallation. A minimum of 20 wt% Ni is nonetheless recommended for observing a significant effect at 650 °C.

Eventually, from a mechanical point of view, ferritic–martensitic steels offer the best creep properties at low temperature. The most recent modifications could be used up to 650 °C. Furthermore, austenitic steels can be used in a small range up to 670 °C. Higher temperatures require the use of Ni‐based alloys (Smith and Shoemaker 2004; Viswanathan et al. 2002).

16.3 Coal‐ash Corrosion

Corrosion in coal‐fired boilers is frequently referred to as coal‐ash corrosion particularly when the aggressive phenomena are mainly due to the nature of the ash that deposits on the heat‐absorbing surfaces of metallic components (waterwalls, superheater, and reheater tubes of boilers and furnaces).

The waterwall tubes can undergo a very rapid wastage even though the metal temperature may have been over 400 °C and sometimes would have been cooler than this. In the vicinity of the combustion zone, much of the ash will still be molten, and some of this is deposited on the waterwalls as a slag layer. The combustion zone is designed to be located in the center of the furnace enclosure, at a distance from the walls. Poor adjustment of the burners, wear of the burner nozzles, a change in the combustion characteristics of the coal, or several other factors can result in the combustion zone being displaced, or simply being larger than had been expected. In this case, the slag deposit in the region where the combustion zone approaches the walls contains unburnt carbon and unoxidized pyrite. It is under these circumstances that rapid wastage can result.

Early investigators thought that this wastage was also associated with alkali sulfate species. In fact, alkali sulfates deposited on the waterwalls may react with SO2 or SO3 to form pyrosulfates, such as potassium pyrosulfate (K2S2O7) and sodium pyrosulfate (Na2S2O7), or possibly complex alkali iron trisulfate. The latter compounds are formed in thicker deposits after long periods of time at about 480 °C. The K2SO4–K2S2O7 system forms a molten salt mixture at 407 °C when SO3 concentration is 150 ppm. The corresponding sodium system can become liquid at about 400 °C, but it requires about 2000 ppm SO3 for this to occur; such levels of sulfur oxides are likely only under deposits. Thus, molten salt attack on the tube metal by K2S2O7 is more likely and occurs according to the reaction


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Aug 11, 2021 | Posted by in Fluid Flow and Transfer Proccesses | Comments Off on Fireside Corrosion
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