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Run hotter but take care

Several roadblocks and operational considerations must be taken into account with increased operating temperatures
Several roadblocks and operational considerations must be taken into account with increased operating temperatures
Credit: Emerson Process Management

As the global drive to cut emissions has gathered pace, so too has the need to boost coal plant efficiencies by increasing temperature and pressure, but there are vital operational issues that must be considered, writes Dean Huff

Improving the efficiency of coal-fired power plants by increasing their operating temperature and pressure has been pursued for decades.

Improving power plant thermal efficiency reduces fuel costs and the release of air pollutants and other emissions, such as SO2, NOX, mercury and CO2, to name a few.

CO2 is significant in view of the worldwide agreements to reduce CO2 emissions. For example, a one percentage point increase in the efficiency (from 39 per cent to 40 per cent) of an 800 MW power plant yields an approximate 2.6 per cent reduction in air emissions.

This would reduce the plant’s lifetime emissions of CO2 by nearly five million tonnes. There is no doubt that environmental factors have been a contributor leading to the building of ultra-supercritical (USC) plants in recent years.

A major challenge in continuing to increase the operating temperature of steam cycles is the availability of suitable materials for use in the steam generators. Research and development efforts are ongoing in Japan, the US and Europe to develop materials suitable for higher temperatures. For key components such as the superheater, reheater, water wall tubing, steam piping and steam headers, the materials have to provide sufficient creep strength.

In addition, heavy section components such as the steam piping and headers are subject to fatigue induced by thermal stresses as a result of warm-up and cool-down cycles.

Austenitic stainless steels are favoured for high-temperature superheat and reheat tubing for their higher creep rupture strength and higher resistance to fire-side and steam-side corrosion. Ferritic and martensitic steels are preferred for piping and headers because of their higher thermal conductivity and lower coefficient of thermal expansion, which makes them less prone to thermal fatigue than the austenitic stainless steels.

There are several roadblocks and operational considerations that must be taken into account with the increased operating temperatures. Some critical items are:

  • Long-term creep rupture stress and allowable design stress;
  • Steam-side oxidation resistance of the tube material; and
  • Fire-side corrosion resistance of the tube material.

Figure 1 shows a summary of the world experience as it relates to main and reheat steam temperatures, along with the introduction dates of two significant material advances, P91 and Super 304H. As evidenced by Figure 1, P91 had minimal impact on steam cycle temperature while Super 304H had a major impact on the steam cycle temperature.

Main and reheat steam temperatures experienced a major shift upward following the introduction of Super 304H. It should be noted that the increase in steam cycle temperatures after the introduction of Super 304H was facilitated by the availability of P91 for use as a steam header and piping material. This clearly shows the dependence of steam cycle efficiencies on the availability of suitable materials for boiler tubes.

Word Experience Summary
Figure 1: World experience of main and reheat steam temperatures
Figure 1: World experience of main and reheat steam temperatures
Credit: Burns & McDonnell

Furnace water wall material

In supercritical boilers at 600à‚ºC, the maximum temperature of the water/steam fluid in the water wall panels is approximately 450à‚ºC at the outlet. Because of the high heat fluxes in the furnace chamber and the formation of steam-side oxidation products on the inside walls of the tubes , after 10 years of operation the tube mid-wall temperature rises to approximately 490à‚°C. Under such conditions, T12 steel has adequate mechanical properties. However, many suppliers typically provide a higher alloy material, such as T22 or T23, for these boilers.

For supercritical boilers at 620à‚ºC, the expected water wall outlet temperature is approximately 475à‚ºC. Because of the high heat fluxes in the furnace chamber and the formation of steam-side oxidation products on the inside walls of the tubes, after 10 years of operation, the tube mid-wall temperature rises to approximately 515à‚°C. At these temperatures the mechanical properties of T11 and T22 are no longer adequate and advanced materials such as T23 and T24 are required.

For boilers operating in the 650à‚ºC to 700à‚ºC range, materials with a higher allowable stress will be required. Potential candidate materials include T91, T92 and T122. The use of these materials for membrane water walls will be a challenge since they require post-weld heat treatment (PWHT).

Superheater and reheater material

Superheater tubes must be designed to operate at temperatures above that of the steam, generally in the range of 30à‚ºC to 40à‚ºC above the steam temperature.

For steam temperatures up to 620à‚°C, the metal temperature in the final superheater will be around 655à‚°C. Fine-grained 347HFG and Super 304H both have the required creep rupture strength for operation at these conditions.

For boilers operating in the 650à‚ºC to 700à‚ºC range, materials with a higher allowable stress value will be required. While fine-grained 347HFG and Super 304H both have the required creep rupture strength for operation to approximately 650à‚°C, the inadequate fire-side corrosion resistance offered by chromium contents of around 18 per cent limits their practical operating steam temperatures to approximately 620à‚°C. Sufficient strength and steam-side corrosion resistance for operation at steam temperature up to approximately 660à‚ºC is provided by 310HCbN (HR3C).

For operation above this temperature, more advanced materials, such as a nickel alloy, will be required. Alloy 617 and Inconel 740 are potential candidates, both of which have been approved for use by the American Society of Mechanical Engineers (ASME).

Steam-side oxidation

Steam-side corrosion products form on the inside surfaces of boiler tube materials. The primary reaction involved in the steam-side corrosion of high temperature boilers is the formation of magnetite, the growth of which is dominated by solid state diffusion through the scale. Increasing the steam temperature leads to more rapid growth of oxide scales on the bore of the tube. There are three main consequences as a result of the oxide layer formation: it reduces the tube metal thickness; it does not conduct heat as well as the tube material and thus acts as an insulating barrier to heat transfer; and the thicker it becomes the more likely it is to flake off (exfoliate or spall).

Due to the insulating qualities of the corrosion products layer, the wall temperature of the tube progressively increases with increasing service life. Such an increase in wall temperature not only leads to the more rapid accumulation of creep damage, it also results in higher fire-side and steam-side corrosion rates.

There is more difference in the coefficient of thermal expansion of the oxide layer from that of austenitic stainless steels than there is from that of ferritic steels. Thus, upon temperature changes such as those experienced during startup and shut down, for a given oxide layer thickness, the oxide layer is more likely to spall from austenite stainless steels than from ferritic steels.

These steam-side corrosion particles cause damage to the steam turbine, which is called solid particle erosion (SPE). The size of the exfoliated particle is much larger for austenitic stainless steels than for ferritic steels.

In terms of the relative steam-side oxidation rate for various boiler tube materials, increasing the chromium content of the tubes is critical to controlling the steam-side oxidation rate of tubes operating at elevated temperatures. For materials with equivalent chromium contents, the fine-grained materials such as Super 304H and 347HFG are less susceptible to steam-side oxidation than coarse-grained materials such as TP304H and TP347H.

Mechanically working the inside of the tube by shot blasting also improves the steam-side oxidation resistance of austenitic stainless steels. The reduction in the steam-side oxidation rate is more pronounced for coarse-grained materials than it is for fine-grained materials. The shot peening process reduces the grain size and increases the chromium content at the tube surface.

These two effects combine to enhance the steam-side oxidation resistance, especially for coarse-grained materials. The shot blasting of coarse-grained stainless steels will improve their oxidation resistance to be about equivalent to that of the fine-grained stainless steels.

Shot blasting fine-grained stainless steels also improves their oxidation resistance so that their acceptable operating temperature can be increased. However, the shot-blasting effect is lost during the process of welding or when stress relief annealing is necessary, such as after bending.

Figure 2 shows the relationship between the oxide layer thickness, the strain between the oxide layer and the tube base metal, and whether or not the oxide layer is likely to spall. Figure 3 shows the strain between a magnetite oxide layer and the base metal for various common tube materials when cooled from the indicated temperature room temperature. Note that the strain for T91 and T122 is much greater than the strain for T22. This tends to reduce the effectiveness of the slower oxide growth rates for these materials.

Figure 2: Expected scale thickness before exfoliation
Figure 2: Expected scale thickness before exfoliation
Credit: Burns & McDonnell
Figure 3: Strain when cooled
Figure 3: Strain when cooled
Credit: Burns & McDonnell

A frequently expressed concern is whether or not the use of oxygenated water treatment affects the steam-side oxidation. The typical oxygenated treatment oxygen feed rates of 30 ppb to 150 ppb are not likely to affect the oxidation potential of the steam produced, since such oxygen levels are significantly lower than the oxygen partial pressure level set by the equilibrium dissociation of steam.

Fire-side corrosion

Fire-side corrosion is not a significant consideration for low sulfur fuels, but it becomes increasingly important as the sulfur level of the fuel increases. Coal with less than 1 per cent sulfur is generally considered a low sulfur fuel, while sulfur contents greater than 1.5-2 per cent are considered high sulfur fuels.

The fire-side corrosion mechanism is different for the water walls and the superheater and reheater sections of the boiler. Corrosion rates greater than 1 mm/10 years are generally considered corrosive, while rates over 3 mm/10 years are generally considered severely corrosive.

CEZ Ledvice supercritical coal plant
CEZ Ledvice supercritical coal plant
Credit: Emerson Process Management

Water wall wastage

All boiler manufacturers offer some form of staged combustion (low NOX burners and overfire air) to limit the NOX emissions. This creates sub-stoichiometric conditions in the burner zone. Sub-stoichiometric conditions increase the danger of fire-side corrosion of the furnace water walls, which can lead to rapid thinning and result in early failure, especially when higher sulfur fuels are used. This method of water wall corrosion is called sulfidation, the rate of which is largely a function of the hydrogen sulfide (H2S) concentration at the tube wall. The reducing (sub-stoichiometric) conditions favor the formation of H2S, while an oxidizing atmosphere favors the formation of water and SO2.

None of the tube materials currently used provides sufficient corrosion resistance to withstand sulfidation when higher sulfur fuels are used. In these cases, an Inconel weld overlay is typically applied to the tubes in the burner zone to control the fire-side corrosion rate.

Some boiler suppliers will offer a single-stage combustion system to maintain an oxidizing atmosphere to reduce the rate of fire-side water wall corrosion. Typically the resulting increased NOX production must be taken into account in the design of the NOX removal system.

When using low sulfur fuels, the weld overlay is not required.

Liquid phase corrosion

The fundamental mechanism of fire-side corrosion of the superheater and reheater is called liquid phase corrosion. Liquid phase corrosion of tubes at high temperatures depends on the SO2 content in the flue gas, the tube metal temperature and the tube composition.

The cause of this type of corrosion is generally accepted to be liquid alkali iron trisulfates on the surface of the superheater and reheater tubes beneath an overlying ash deposit. Since this type of corrosion is dependent on the alkali iron trisulfates being in the liquid form, it is therefore temperature-dependent. Increasing the material chrome content also reduces the rate of liquid phase.

Welding requirements

The ability to quickly repair boiler tubes is an important consideration for the superheater and reheater tubes, as they are more susceptible to corrosion and failure, especially when high sulfur fuel is utilized.

Depending on the tube material, the time required to repair a boiler tube may need to include the time required to preheat and apply PWHT to the weld.

The need for PWHT is a function of wall thickness for some materials, thus the need cannot be stated with certainty until the design is complete and the wall thickness is known. To reduce the time and expense associated with repair, it may be desirable to limit the use of materials that require PWHT in those areas of the superheat and reheater where the operating temperature is such that liquid phase corrosion not likely occur.


Several roadblocks and operational considerations must be taken into account when increased operating temperatures are being considered. They include tube material long-term creep rupture stress and allowable design stress; steam-side oxidation of the tube material and fire-side corrosion of the tube material.

For low sulfur coal applications, the temperature will be limited by the selected material’s allowable stress and rate of steam-side oxidation. Based on the review of boiler supplier experience lists, the highest main steam/reheat steam conditions in operation are 605à‚ºC/623à‚ºC.

These conditions are approaching the limit of the steam-side oxidation resistance of shot peened fine grain 18 per cent Cr and 25 per cent Cr stainless steels. Moving to temperatures much above these, such as 650à‚ºC, will require the use of more advanced alloys, such as a nickel-based alloy. The use of nickel-based alloys will greatly increase the cost of the boiler tubes.

For high sulfur applications, the need to limit the fire-side corrosion rate will be a main determining criterion. The 25 per cent Cr alloys, such as 310HCbN, are expected to provide acceptable fire-side corrosion rates up to 565à‚ºC.

Moving to temperatures much above these, such as 600à‚ºC, will require the use of more advanced alloys, such as a nickel-based alloy, which will greatly increase the cost of the boiler.

Dean Huff is a Senior Associate Mechanical Engineer, Energy, at Burns & McDonnell

Sub, super and ultra-critical

The distinction between subcritical and supercritical is defined by the critical point of water, which occurs at about 221 bar and 374à‚ºC. There is not a similar physical distinction between supercritical and ultra-supercritical. Early in its use, the term ultra-supercritical was used to refer to units with a steam temperature of at least 580à‚ºC. However, it has become generally accepted as referring to a unit with a steam temperature of at least 600à‚ºC. These units generally have a steam pressure between 250 and 270 bar, which is similar to but generally slightly higher than those of a supercritical cycle.

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