Coatings in the electricity supply industry: past, present, and opportunities for the future

Surface and Coatings Technology 108–109 (1998) 1–9

Coatings in the electricity supply industry: past, present, and opportunities for the future John Stringer EPRI, 3412 Hillview Avenue, Palo Alto, CA 94304, USA

Abstract The cost of electricity, the reliability of its supply, the impact on the environment, and the global sustainability, are all forcing the supply industry to make greater demands on the materials of construction of the generation, transmission, and distribution components. Not only is the performance being enhanced, but the requirements for durability, and the ability to identify potential failures, to estimate remaining life using non-intrusive methods, and to repair or replace quickly and effectively, are also subject to greater demands. Coatings play an important role in all of these aspects. In this paper, a very general summary of some of the more important issues is presented.  1998 Elsevier Science S.A. All rights reserved. Keywords: Electricity supply; Corrosion; Erosion; Coatings; Claddings; Surface modification

1. Introduction

1.1. Performance degradation in the electricity supply industry The degradation of performance in the various parts of the electricity supply industry represents a significant cost penalty. The degradation may be associated with the loss of components, for example due to fracture induced by a time dependent deterioration process to the point where the component can no longer sustain the loads to which it is subjected in normal operation; or to a decay in performance, for example by the aerodynamic losses associated with roughening of an airfoil surface. In some cases, either of these may be associated with a degradation of the surfaces of the components, and it is in these situations that surface coatings may be of benefit. This is the subject of this presentation. Although the topic of this session is high-temperature coatings, in this presentation there will be some general discussion of processes which occur at lower temperatures, for completeness.

1.2. Component lifetime The lifetime of any component in an engineering system is determined by some degradation process, which may be as rapid as high-temperature oxidation or as slow as graphitization of mild steel. In a number of cases, the degradation is related to the component surface.

In some of these cases, the life-limiting process is obvious: loss of load-bearing section in general corrosion. In other cases less so: degradation of strength by the loss of subsurface alloy elements. And in others, indirect: fatigue failure of a turbine blade as a result of stress concentration due to pitting of the blade surface. Degradation may not involve an actual failure of a component: solid particle erosion in steam turbines (SPE) greatly reduces the power produced by the turbine stage; oxide build-up on a heat exchanger changes both the heat-transfer coefficient and the temperature distribution. The impact in both cases is economic, due to performance degradation.

1.3. The role of coatings Coatings are primarily used to restrict surface damage of components in practice, where other requirements prevent the substitution of an inherently resistant material. Generally, materials selected for a particular duty will last an adequate length of time, provided the designer has taken a proper account of all the factors affecting life. The lifetime is determined by some degradation process, which may be mechanical — fatigue, in the case of materials serving a low-temperature function where the stress varies, or creep, for a material subjected to high stress at elevated temperatures—or one of the processes listed later. In some cases, the separation of these processes is not so clear— thus, pits on a turbine blade will act as stress raisers, and

0257-8972 / 98 / $ – see front matter  1998 Elsevier Science S.A. All rights reserved. PII: S0257-8972( 98 )00642-2

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accelerate fatigue failure. Loss of section as a result of general corrosion or erosion will result in an increase in the stress experienced by a component and result in accelerated creep failure. Loss of load-bearing section, for example by internal penetration of corrosion or by nearsurface depletion of strengthening alloy elements, will have the same effect. The surface degradation processes may also adversely affect the performance of components—an example is the solid particle erosion (SPE) of steam turbine blades by spalled oxide particles entrained in the steam, in which the most important economic effect is the degradation of the performance of the turbine, rather than any macroscopic failure of components. The thermal conductivity of the corrosion product is usually very significantly less than that of the metal, and in a component exposed to a thermal flux, the growth of the corrosion product will result in changes in the temperature distribution. For oxide growth on the inner surface of heat exchanger tubes, the effect is to raise the metal mean temperature for a fixed heat flux, and this can lead to an overheating creep rupture failure: the root cause, however, is the oxidation. While the statement at the beginning of the last paragraph is true (no-one would build a machine if one knew at the beginning that it would have an inadequate life), the evolution of the products will inevitably lead to an effort to improve performance, and the usual way to do this is to improve the system design parameters, while keeping the overall materials and manufacturing specifications the same. Eventually, a point will be reached where the lifetime of some component will decrease to a level where the economical value of the overall system is compromised, and changes have to be made. So far as surface degradation processes are concerned, one initial option is to modify the surface while retaining the properties of the substrate, as part of the design bill-of-materials. However, more significant changes, which might be termed generational changes, in equipment will require radical changes in the materials, and in some of these, the solution is recognized from the beginning as requiring a materials system approach, in which a coating is an integral part rather than simply a band-aid. A second issue is that while the design specifications as regards mechanical properties are limited by national or international standards, this is seldom (if ever) true for surface properties, and when a new system is put into service unexpected surface degradations may be encountered. A remedial action, which may involve the selective coating of components at risk, is needed. Finally, the service parameters may change for one reason or another. An example relevant to power production is changes in fuel because of changes in fuel prices, or the appearance of new fuels at low costs, usually as a byproduct of some unrelated industry. Petroleum coke (Petcoke) and Orimulsion are two recent examples of this; increasing interest in the partial or total firing of biomass is another.

Generally speaking, coatings can be regarded as materials with greater resistance to the significant surface degradation process. In the case of corrosion, the coating itself has a greater resistance to the corrosive environment. In the case of erosion or wear, the coating is resistant to this aspect. However, the coating has a number of other important requirements. In brief, these are: (1) The coating must have good adherence to the substrate, throughout the range of conditions that the component is exposed in service. Most obviously, it must tolerate without spalling from the surface the temperature variations that the component experiences in service; and the strains and strain variations that the component will normally impose on the coating. This latter is because the coating is normally thin in comparison to the substrate, and thus will be forced to match the substrate strains. (2) A coating must not only be resistant to the condition for which it has been chosen, but any other condition to be experienced by the component. For example, in the case of a high-temperature coating, susceptibility to water damage of any kind when the system is down and the surface is cool is very undesirable. (3) The conditions required for the coating process must be consistent with the system to be coated: a process requiring a high vacuum is not appropriate for coating a boiler water wall in place. (4) The coating process must not damage the substrate. In general, this means that any process which involves heating the substrate to high temperatures needs to be assessed carefully. (5) A very similar issue is that during the coating process or use, interdiffusion of any species between the coating and the substrate must also be assessed carefully. It may not in fact be harmful, but more frequently it is. (6) The coating must not induce failure in the substrate. This means that the system should not allow a crack formed in the coating to propagate into the substrate, for example. (7) Interface properties are very sensitive to the presence of minor impurities, since chemisorption (for example) can result in the formation of a complete monolayer of an element at an interface even if volumetrically the concentration is very low. These impurities may come from the substrate itself, the coating process, or the environment.

1.4. Coating types It is not the purpose of this paper to review coating methods in any detail, but it is useful just to list the principal coating types in relation to the methods of application. Coatings resistant to high-temperature oxidation most frequently rely on the formation of a dense, adherent Al 2 O 3 (alumina) layer at the interface between the coating and the environment. This means that the coating itself must have enough aluminum for alumina to be the

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preferred oxide, and to provide an adequate reservoir to reform the protective oxide if it is removed, for example by spalling or by mechanical abrasion, a reasonable number of times. One such coating is aluminum itself: the melting point is too low, but by use of appropriate methods, it can be deposited on a surface, for example by flame spraying, and then allowed to react with the surface to form an aluminide. A slightly more sophisticated way of achieving the same result is to put the component in a pack containing either aluminum or an aluminum-containing alloy dispersed in an inert powder, together with an activator which is usually a halide. The aluminum is transferred from the pack to the substrate surface through the vapor phase by the halide which dissociates at the substrate surface, and diffuses into the substrate. This is called a diffusion aluminizing process, a pack aluminizing process, a pack cementation process or by a process name: alonizing is an example. Since in detail the actual deposition process involves the dissociation of a chemical vapor species, this technique can be regarded as one member of a larger group called chemical vapor deposition (CVD). Alumina is relatively soluble in molten alkali salts; and in some circumstances where a molten salt is a component of the corrosive environment a coating which will form a dense adherent Cr 2 O 3 (chromia) layer is preferable. This too can be applied by a pack cementation process, or by a CVD process where the chromium halide species is generated at some distance from the component to be coated. These pack diffusion processes involve the substrate alloy itself in the formation of the coating, and in some cases the requirement that the chemistry of the alloy surface layers should not be modified significantly may be incompatible. The process usually involves holding the component in the pack for a considerable time at a relatively high temperature, and this too may not always be acceptable. In a sense, electroplating can be regarded as a CVD process, and electroplating continues to be widely used. A recent example in a high-technology application is the widely used class of ‘platinum aluminide’ coatings for gas turbines: typically, a layer of platinum is first electroplated onto the component surface, and the component is then aluminized, usually by a pack cementation process. An alternative approach which does not involve the alloy itself in the coating process is the physical deposition of the coating composition on the substrate. One method of doing this is to evaporate the coating alloy from an ingot using an electron beam to form a melt pool; for more complex cases more than one such source may be used, either at the same time or sequentially. The vapor condenses on the component surface, which may be heated to improve the bond and the properties of the coating layer itself. This is called electron beam physical vapor deposition (EBPVD). Another approach involves the deposition of a coating

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alloy in molten form onto the component surface using a flame or a plasma torch. The alloy may be supplied to the torch in a number of ways: the most usual are either as a wire or as a powder. The powder is partially melted by the carrier, and accelerated towards the substrate, where the semi-molten droplets ‘splat’ onto the surface, generally cooling rapidly; once again the substrate may be heated. There is now a wide range of commercial techniques of this kind, which attempt to achieve higher impact velocities and thus higher densities. Vacuum plasma spray (VPS) or low-pressure plasma spray (LPPS) are two names for the same process, where the lowering of the pressure reduces the aerodynamic slowing down of the droplet as it approaches the surface. Other processes increase the velocity of the droplets by what amounts to a pulsed flame: the most important new technique of this type is the high-velocity oxy-fuel (HVOF) method. Whereas the lowpressure techniques cannot easily be applied to large components, such as boiler walls, the HVOF torch can, although the environment would be unpleasant for the workers. The deposition and densification steps can be separated, for example by using laser remelting of surface deposits. Post-deposition optimization of the substrate / coating system (however applied) by heat-treatments, shot-peening, hot isostatic pressing (HIPing), partial remelting, etc., is often part of the overall process. Thicker deposits are sometimes appropriate, and these can be achieved by weld-depositing material on the component surface (this is common in large chemical vessels); the attachment of a resistant alloy in sheet form by roll bonding, explosive bonding, HIPing (hot isostatic pressing); or, in the case of a tubular product, co-extruding a billet composed of the substrate alloy and the coating alloy. The last four of these require a relatively ductile coating material. It is possible to use more than one of these methods to develop a composite coating system, for example by depositing a coating using EBPVD and then increasing the surface aluminum content of that by pack aluminizing. By using multiple sources and a shutter system, coatings with progressively changing compositions and characteristics can be manufactured: these are sometimes called ‘functionally gradient materials’. This description is far from complete, but it will give some feeling for the choices available.

1.5. Other surface-modification issues It would not be complete not to mention other cases where the properties of surfaces may be modified by coatings. Electrical and optical properties of surfaces are commonly modified, of course; and also thermal properties. One high-technology example is the application of diamond coatings to produce a surface that has a high thermal conductivity but a very low electrical conductivity; in principle this surface could also have a very low

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coefficient of sliding friction and a high wear resistance. These aspects of surface modification by coatings will be covered in some detail by other parts of this Conference, and will not be discussed here: this does not imply that they are not important for the utility industry. One special example of this class is the thermal barrier coating (TBC) which is increasingly used in the hot sections of advanced gas turbines. The remainder of this paper will describe a few examples of surface degradation situations in the utility industry, and discuss the use—or otherwise!—of coating systems to combat the problems. With the exception of a brief mention of a problem in steam turbines, all of the aqueous corrosion problems will be ignored; this does not, however, imply that they are not important in our industry.

2. Examples of surface damage

2.1. In the electricity generation component (1) Accelerated high-temperature fire-side corrosion associated with the presence of molten alkali-containing salts of superheater and reheater tubing in fossil fuel-fired boilers. (2) Accelerated medium-temperature fire-side corrosion, associated with the presence of a low oxygen activity environment and sulfur, of water-wall tubes in coal-fired boilers; and of gas-cooler tubes in coal gasifiers. (3) Accelerated high-temperature corrosion of gas turbine vanes and blades: normally associated with alkali salt deposits. Type I at higher temperatures; Type II at lower temperatures. (4) Steam-side oxidation of tubing, piping, and valves in fossil fuel-fired boilers. (5) Pitting corrosion of late stages in steam turbines associated with first condensation. (6) Aqueous corrosion of components at the back end of boilers, including environmental control equipment. (7) Aqueous corrosion within generators. (8) Stress-corrosion cracking, particularly in nuclear plant. (9) Radiation-induced or enhanced stress-corrosion cracking (10) Exfoliation of steam-side oxide in boilers, leading to erosion of down-stream valves and steam turbine components. (11) Wastage (erosion or abrasive wear, sometimes coupled with corrosion) of fireside components in fluidized bed combustors, both bubbling and circulating. (12) Fireside erosion in coal-fired boilers; fly ash erosion and soot-blower erosion. (13) Erosion of combustion turbine components in dusty environments; e.g. expander turbines in pressurized fluidized bed combustors (pfbc). (14) Erosion of combustion turbine first stage vanes and

blades by carbon shed by improperly operating combustors, or by material collected by, and shed by, the compressor. (15) Water-droplet erosion of final stages in steam turbines by large droplets shed by an earlier stage. (16) Wastage by dense particle streams: for example, pulverized coal feed lines, pfbc ash removal lines. (17) Cavitation erosion of hydro turbines; of valves, and of tube bends. Another problem, which is not exactly surface damage, but is addressed by coating, is fouling, for example of water-flow measuring venturis in nuclear plant.

2.2. In the transmission component (1) Corrosion of overhead high-voltage insulators as a consequence of corona-formed nitric acid. (2) Corrosion of underground high-voltage cable conduits. (3) Corrosion of transformer tanks, particularly external corrosion of tanks in wet environments.

3. High-temperature corrosion

3.1. Coal-fired boilers: fire-side issues 3.1.1. Superheaters and reheaters This is an area which has received a great deal of study over the years; for some discussion of the current views see Dooley and McNaughton [1]. It is generally agreed that in the case of fire-side corrosion of low-alloy ferritic superheaters and reheaters, such as T22 (2.25Cr–1Mo) accelerated attack is due to the presence of a molten or partially melted complex alkali metal sulfate deposit on the metal surface, typically beneath an ash deposit. For US boilers, the temperature of the superheated steam at the exit from the finishing superheater is typically 5388C (10008F). Variations in the flow of steam though a large number of parallel circuits can mean that local steam temperatures are higher than this. The gas temperature in the vicinity of the entrance to the superheater is typically 1350–14008C (2462–25528F) and again there are variations across the face of the superheater. The range of metal temperatures over which the alkali salt accelerated corrosion is observed is defined by the solidus temperature of the salt mixture (incipient melting) at the lower end, and the dissociation temperature of the complex sulfate at the upper end. Both of these temperatures, but particularly the high one, are dependent on the local SO 3 partial pressure; but a range something like 600–7008C is reasonable. The most important single factor, given that the boiler was appropriately designed in the first place (see earlier), is the coal chemistry. High sulfur, high alkali fuels will result in more corrosion; under some circumstances chlorine may

J. Stringer / Surface and Coatings Technology 108 – 109 (1998) 1 – 9

play a role; there are variations in the corrosiveness of coals for which there are no fully convincing explanations. A second factor is temperature, specifically the metal temperature: European systems often use a superheat temperature of 5658C (10508F) and suffer more severe corrosion; units in the US with superheat temperatures below 5388C suffer no corrosion [1]. In boilers suffering from superheater corrosion, given that a fuel change cannot be made, coatings have been used over the years with limited success. Aluminum thermal spray coatings have been the most common, but they are used as palliatives on the most severely corroded regions. In the event that the superheater (or reheater) has to be replaced the UK utilities (formerly CEGB; now Powergen and National Power) have favored coextruded tubing, with the outer layer being a corrosion-resistant material, such as Ni–50%Cr, or Type 310 stainless steel, and the inner a conventional high strength austenitic steel, which in the UK is Esshete 1250. Dooley and McNaughton [1] remark that these coextruded tubes have been used in the UK since 1976, and over 230 km has been installed in 12 units. They refer to a paper by Flatley and Thursfeld describing the experience up to 1984 [2]. A typical application used 54 mm outside diameter tubes with a Type 310 layer of 2.9 mm thickness over a 2.0 mm thick Esshete 1250 inner layer. Performance improvements of between 2 and 5 times better than the unclad Esshete 1250 were reported. In the US, for a time Incoclad was installed in a number of units: here, the corrosion-resistant cladding was Incoloy 800. However, the relatively lower impact of fireside corrosion here appears to have made this approach uneconomic.

3.1.2. Waterwalls A utility boiler is of waterwall construction. This means that the walls are formed of tubes within which water flows, boiling at some location, the steam then entering the superheaters at the top of the combustion chamber. In a US boiler, the tubes are typically about 50 mm outside diameter, and are joined to each other by strips of steel approximately 10 mm wide. In the US, the tubes are vertical; in some cases in Europe the Benson design is preferred, in which the tubes form an ascending helix around the boiler, but these will not be discussed here. Pulverized coal is pneumatically injected into the boiler through burners, which are in an array approximately one-third of the way up the combustion chamber. The exact way the burners are arranged varies considerably: some boilers are rectangular in horizontal cross-section, with burners on one long face, or both long faces; the furnace may be square in section, some with burners at the corners. The objective is to create a ‘fireball’ in the furnace, as far as possible from the walls themselves. Heat is transferred to the water in the tubes by radiation, and the water starts to boil at about the top of the burners. There are two options: the first is the ‘subcritical’ boiler, where

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the pressure is below the critical value where the change from liquid water to vapor takes place without a two-phase water1steam zone; and the supercritical boiler. In a subcritical boiler, above the level where the water begins to boil there is a two-phase mixture all the way up the boiler, with the fraction of water progressively diminishing. At the top of the boiler combustor, the remaining water is separated from the steam in a cyclone system in what is called the steam drum and returned to the bottom of the boiler. Since the fluid inside the tubes above the point where boiling starts is a two-phase mixture, it follows that the temperature is constant (since the pressure is essentially constant). US subcritical utility boilers operate at a main steam pressure of 16.548 MPa (2400 psi) at which the temperature of the equilibrium steam / water mixture is 348.88C (661.68F). The temperature of the clean metal surface temperature can be easily calculated if the heat flux and the tube wall thickness and thermal conductivity are known, since the temperature drop through the internal boundary layer will be very small. However, the real situation is different, principally because of the presence of a magnetite layer on the internal surface of the tube, which means that the metal surface temperature will be higher than that. One can guess therefore that the maximum metal temperature will be 4008C or so just above the burner zone, and may diminish a little going up the furnace because the heat transfer flux will drop. The presence of heavy water-side deposits may increase this figure in the near-burner zone. The situation in supercritical boilers is different, because there is no two-phase water-steam region, and the temperature of the fluid may rise continuously as it ascends. However, the maximum superheat temperature is generally the same, and the external heat transfer coefficients and materials conductivities are also the same. The water-side heat transfer coefficient will increase somewhat, because of the greater pressure, but the temperature drop on that side of the system is small, anyway. As a result, the wall temperatures may not be all that different. The material for the waterwall tubes is generally a plain carbon steel, and at these temperatures the oxidation rate both on the steam-side and the fire-side is slow enough to provide an adequate lifetime. At these temperatures, wustite (FeO) is not stable, and the oxide consists of magnetite (Fe 3 O 4 ) and a relatively thin outer layer of hematite (Fe 2 O 3 ). On the steam-side, hematite may be absent depending on the oxygen content of the water. Accelerated oxidation on the fire-side is associated with a condition where the normal ash deposit contains significant amounts of unburnt carbon and unoxidized pyrite (FeS). Obviously, these circumstances correspond to a very low local oxygen partial pressure environment, often called ‘reducing conditions’. Early literature had suggested, by analogy with the superheater corrosion referred to above, that a low-melting point alkali sulfate might be responsible, and a pyrosulfate was identified that might be

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molten at the appropriate temperatures. However, this compound is only stable under very high partial pressures of SO 3 , which corresponds to highly oxidizing conditions, and consequently it could not possibly be involved. In fact, the wastage much more closely resembles that in a ‘sulfidizing / oxidizing’ reaction: as has been shown by Lin et al. [3], amongst others, the presence of carbon in the environment enhances this process, and may even be necessary to enable it. Cutler and Raask [4] described CEGB studies which illustrated the mechanism of waterwall corrosion, emphasizing the necessity for ‘reducing’ zones near the walls. Frequently, this could be attributed to damage or misalignment of burners; in other cases it was attributable to a change in coal. The first of these factors can be corrected by proper maintenance; the second may be more of a problem. CEGB were in the habit of using rectangular cross-section front-wall fired boilers, and the end walls of these boilers were particularly prone to this form of corrosion: flame spraying of aluminum was applied as a ‘band-aid’ until something more substantial could be done. Lewis and Plumley [5] described some of Combustion Engineering’s (now ABB Combustion) work on surface coatings and claddings; most importantly, diffused aluminum coatings were unsatisfactory, but diffused chromium coatings behaved well. In addition, the possibility of arranging a ‘curtain of air’ against the walls has been considered, with limited success. This situation has become of considerably greater importance with the introduction of ‘Low NO x ’ firing schemes. Typically, the initial flame is substoichiometric, with the balance of the air being ‘over fired’—that is, injected at a somewhat higher level in the boiler. Under these circumstances, a longer, ‘lazier’ flame is produced, with a much higher probability of incompletely oxidized species reaching the opposite wall. Boiler makers are investigating coatings for protection with considerably more vigor, not only as repair techniques, but as part of the initially specified bill of materials. In this case, pack cementation techniques are possible, and ABB Combustion continues to advocate chromizing; in one case a chromized layer has lasted for over 10 years in a boiler environment in which the corrosion rate had previously been in the range of 0.75 mm / year (30 mils / year) [6]. However, in this environment coatings generally have a limited lifetime. Coatings companies offer guarantees of the order of 5 years, but often under conditions which allow them to inspect and refurbish on a yearly basis. As a consequence, field-applicable techniques are generally preferred. HVOF techniques are now field applicable, and advances in the control of these systems to reduce the ‘art’ component are in active development. The current state of knowledge and experience has recently been reviewed by Sherlock et al. [7] who remark that ‘‘the shortest and least reliable solutions (1–3 years) are those applied by thermal spraying with the variability very dependent on the preparation and application pro-

cedures. The longest protection (8–10 years) is currently predicted to be provided by weld overlaying with IN625 alloy, or by applying chromized tubing. However, neither option has had more than a couple of years exposure under the very severe reducing and corrosive environments’’.

3.2. Coal-fired boilers: water- and steam-side issues There are two particular issues which relate to the water and steam sides of utility boilers. These (and others) are presented at length in Ref. [1]. The first relates to the transfer of oxide through the water-touched part of the system. This amounts to the dissolution of magnetite in one part of the system and its deposition elsewhere as a result of the temperature differences. The deposition of this can lead to high metal temperatures and potential tube failure. The second is the exfoliation (spalling) of oxide, particularly from the primary and secondary steam circuits, and its transport in the steam, causing erosion damage in the steam valves and in the early stages of the high pressure and intermediate pressure steam turbines. In some cases, the exfoliated scale may collect in the bottom of pendant superheater elements, blocking the flow of steam, and leading to overheating and failure. From a coatings or surface treatment point of view, the second of these issues is the more interesting. There are three possible approaches: (i) reduce the rate of growth of the steam-side oxide; (ii) improve the adhesion of the oxide, reducing its tendency to spall; (iii) ‘harden’ the down-stream components at risk. For completeness, it should also be pointed out that methods which prevent or limit the transport of the oxide debris to the down-stream components may be considered. Where the high-temperature parts of the steam circuits— the finishing stages of the superheaters and reheaters, and the superheat and reheat steam lines—are fabricated of austenitic steels, a surface treatment which encourages the formation of a chromium-rich M 2 O 3 oxide (where M is a mixture of Cr and Fe) rather than M 3 O 4 can be very effective: the Japanese demonstrated a method of shotpeening the internal surfaces of these components which had this effect. In the US, where low alloy ferritic steels are more common, a magnetite Fe 3 O 4 oxide scale is usual; cold-working the surfaces of these alloys does not promote the formation of M 2 O 3 . Babcock and Wilcox have promoted the internal chromizing of these components, using a CVD technique: this is effective, but it cannot be done in place. An alternative approach was developed by FosterWheeler, with support from EPRI [8]. This involved forming a chromium-rich oxide deposit on the internal surface of the tube by the conversion of a chromate solution in situ. Unfortunately, the temperature and pressure required to convert the chromate to a good adherent chromium-rich oxide was acceptable for the superheater, but not for the reheater. Nonetheless, the performance in service was very good [9]. It is possible that the intro-

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duction of oxygenated water treatment, which does result in the formation of an outer layer of hematite (Fe 2 O 3 ) may reduce the exfoliation. If the oxide spallation cannot be eliminated, or at least significantly reduced, the alternative is the application of an erosion-resistant coating to the components at risk

4. Pitting corrosion of low-pressure steam turbine blades The steam from the boiler enters the steam turbine, and cools as it expands. As indicated above, the superheated steam enters a high-pressure (HP) turbine, and at the end of this typically returns to the boiler to be reheated. The reheat steam enters an intermediate pressure (IP) turbine; and the exhaust from this enters the low-pressure (LP) turbine. The exhaust from the LP turbine is condensed in a large condenser, generally cooled with water from the sea or a local river; and the condensate is returned to the boiler through a series of water heaters. In a fossil fuel-fired boiler, the steam reaches its dew-point within the late stages of the turbine, and condensate begins to appear at what is called the Wilson line. Most commonly, the condensate appears in the next-to-last stage of the turbine, which is called the L-1 stage. The problem to be discussed here is related to corrosion, but it is worth commenting that the water flows over the surface of the next stage of stators, and falls away from the trailing edge as relatively large, slowly moving drops; these are struck by the last stage rotors, which may suffer significant erosion damage. This erosion damage is combated in a number of ways, most commonly by the use of inserts of hard metals at the leading edge locations where the damage is worst. However, erosion-resistant coatings are also a possibility. This topic will not be considered further here. Problems were encountered on the L-1 stage of utility steam turbines, beginning around the early 1970s, and increasing progressively over the next several years [10]. In part, this was due to a change in the water chemistry control procedures. Even if the concentration of chlorides, sulfates, and caustic in the water is as low as 1–10 ppb (parts per billion by weight), the initial condensate can have concentrations as high as 10%. These droplets can cause pitting corrosion on the blades, and the pits can act as stress raisers, leading to fatigue failures. EPRI research in relation to this problem has followed three paths: (a) substitution of Ti–6Al–4V for the steels commonly used; (b) improvement in water quality; (c) the use of corrosionresistant coatings. The attraction of the coating route is that the materials with which the designer is comfortable and has most operating experience can be retained; and even with improved water treatment, problems arising from such events as condenser leaks do not initiate damage—the system is more ‘tolerant’. Initial studies [11] identified four

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promising coating systems: (1) ion-vapor deposited aluminum; (2) nickel–cadmium electroplate; (3) sulfamate nickel electroplate; and (4) teflon. Laboratory and in-service tests, which examined the durability of the coatings and their effectiveness in limiting the degradation of the materials properties [10], concluded that the nickel–cadmium electroplate and the ion-vapordeposited aluminum coatings were most effective, and recommended them for service use.

5. Fluidized-bed combustion Fluidized bed combustion is a technology which has a number of potentially important applications. A bed of particles, fluidized by a gas flowing upwards through it, is a remarkable system for gas / solid contact; it is therefore ideal for combustion, in that reaction between a solid fuel and a gaseous oxidant can approach completion quickly at temperatures well below that normally required. Furthermore, other harmful gaseous species can be captured by solid reactants within the bed. Finally, since the particle size most appropriate for the kinds of reactions of concern to utilities is of the order of 1 mm, the solid charge preparation is relatively simple. Control of temperature within the reacting bed may require an in-bed heat exchanger, and the durability of this when it is in constant contact with a mass of moving solid particles is clearly an issue. A variety of the fluidized bed combustor (FBC) operates at a rather higher gas velocity: some part of the particulate charge is transported out of the combustion chamber by the flowing gas, is caught by a cyclone at the exit to the combustion chamber, and recycled. This is a circulating fluidized bed (CFBC). Finally, both types of fluidized bed may be operated at elevated pressure, when a step in the cycle involves extraction of energy by expanding the exhaust gas through a turbine; these are called pressurized fluidized bed combustors (PFBC and PCFBC). While in some systems corrosion may be an issue, the major materials issues in fluidized bed systems are related to erosion or abrasion; and combating these has required the use of coatings or overlay systems. This topic has received considerable exposure, and it is not appropriate to rehearse it here. However, attempts to develop wearresistant coatings using the conventional wisdom have revealed an important principle. The conventional materials depend on having very hard materials, such as refractory metal carbides, bonded together by a ductile metal matrix. Although the mean particle size in a utility fluidized bed is of the order of 1 mm, the bed contains a significant number of very much smaller particles; and thus the separation distance between the hard particles in the wear-resistant alloy has to be small. Otherwise, the erodent particles wear away the relatively soft matrix bond material, and the hard particles just fall out.

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6. Combustion turbines This topic has been left to the last, because (a) it is the one of most concern to the audience in this meeting; and (b) there are a number of other papers here that relate to it. From the utility point of view, the major issues in combustion turbines that relate to coatings are: (1) oxidation resistance of the hot section materials under cyclic conditions; (2) hot corrosion resistance—that is, resistance to the accelerated corrosion attack resulting from the presence of key impurities, such as alkali salts, vanadium, sulfur; (3) erosion resistance, due to the impact of solid particles which may derive from the intake air; graphite formation in the combustor; or the shedding of salts collected on the later stages of the compressor (in this last case, corrosion may also play a part). In early times, it was believed that if an engine was fueled with a clean fuel such as natural gas, and the air was carefully filtered, a superalloy capable of forming a protective alumina scale did not require coating. Coatings were first introduced for the first stage vanes and blades of military aircraft, and the need escalated when aircraft increasingly were used for relatively low over-sea missions, and salt-induced hot corrosion became a problem. The first alloys developed for gas turbines were based on two commercial heat-resisting materials: Ni–20%Cr and Co–35%Cr. The greater strengths required for the rotating blades led to a progressive development of the nickel-based alloys, because of the existence of the phase Ni 3 (Al,Ti)-g9 (‘gamma prime’)—which forms coherent or semicoherent boundaries with the matrix: the strengthening associated with these boundaries was very important. Increasing the volume fraction of the gamma prime led to a progressive increase in the Al and Ti contents of the nickel-base ‘superalloys’: the Cr content progressively decreased to increase the high-temperature solubility of the Al and Ti, thus increasing the volume fraction of the gamma prime formed on cooling. The original Ni–20%Cr alloy forms a chromia protective scale, but the lower Cr alloys became unable to form this oxide. Fortunately, if the Al content is high enough, the superalloy will form a protective alumina scale; but the stability of this is not very high. In fact, as the use temperature rose, the chromia scale became inadequate, because of its further oxidation to CrO 3 , which is volatile: the highest temperature for which a chromia scale is acceptable is approximately 8008C, and this depends on the gas velocity. The ability of an alloy to form an alumina scale is promoted by relatively small amounts of chromium, for reasons which are still not altogether clear: an alloy with as little as 5 wt% (approximately 10 at%) Al can form an alumina scale, provided there is at least 10%Cr. However, as the chromium content is further reduced, the alloy’s ability to form a protective scale is compromised. The reaction to this was to raise the aluminum content of the

surface by pack aluminizing forming a layer of NiAl, and this provided adequate high-temperature oxidation resistance. However, the adhesion of the alumina scale to the substrate is questionable in thermal cycling. This can be combated by electroplating the surface with platinum prior to aluminizing; the excellent adhesion of the alumina to this is still not fully understood. A further issue is the brittleness of the aluminide coating. NiAl exhibits a strain to cracking of approximately 0.4% below 6508C [12]. Cracking in the coating not only may allow oxygen access to the underlying alloy, but also lower the fatigue lifetime [13]. Aluminide coats generally do not show adequate resistance to hot corrosion. There are two forms of salt-accelerated corrosion in gas turbines. These are called Type I and Type II. Type I, or high-temperature hot corrosion, is characterized by a macroscopically uniform corrosion front, which involves an internal layer of internal oxidation, which may also contain internal sulfides and carbides. The external oxide is not protective, and is composed of the oxides of the base metal (nickel or cobalt); and the oxides of the other constituents, particularly chromium and aluminum. It is known that this attack is induced by alkali sulfates, (Na,K) 2 SO 4 , and the attack is found in a temperature range defined by the melting point of the salt and its dew point in the engine. This is typically 825–9508C. Type II, or low-temperature (or low-power) hot corrosion, is characterized by a pitting attack: there is little or no internal attack beneath the pits. This is induced by a complex sulfate, involving not only the alkali metals but also the base metal, which is stabilized by SO 3 in the combustion gas. It is found in a temperature defined by the melting-point of the complex sulfate, and its dissociation temperature; this last depends on the SO 3 partial pressure. The range is typically 670–7508C. Both of the temperature ranges given above are approximate, and depend on the compositions of the molten salts, the combustion gas composition, and the composition of the surface in contact with the salt (coating or base metal). For example, molybdenum in the alloy produces an acidic oxide species, which can enhance attack above a critical concentration; and if the Mo is present in the alloy as a coarse carbide, this may disrupt the coating and promote local attack. The classification of the form of the attack (Type I or Type II) is primarily based on the morphology of the attack, and not the temperature. Examples of Type I attack have been reported at metal temperatures as low as 7008C, for example. While aluminide coatings are generally not adequate for aggressive hot corrosion conditions, they can provide adequate protection against relatively mild Type I conditions. Platinum aluminide coatings generally show good resistance to this form of attack. However, it is generally agreed that the coating should contain a significant chromium content to provide adequate resistance under more severe conditions, and this is certainly true for Type

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II attack. Note that the protective scale is still usually Al 2 O 3 , with very little chromium present. There is still no general agreement on how the chromium confers benefit, but there is no doubt that it does. There is a wide range of coatings and coating techniques that are employed for utility combustion turbine hot components, and there are a number of data bases which list those currently in use, which are frequently updated as both techniques and knowledge improve: as new alloys are introduced, it is necessary also to optimize their coatings. This meeting includes a number of examples, and in this paper no further discussion will be presented.

7. Concluding remarks Protective coatings are of major importance to the electricity supply industry. The objectives of the industry are to produce high-quality power reliably, with the least damage to the environment, sustainably, and at the lowest possible cost. For the attainment of all these objectives, the use of protective coatings, properly designed as part of the overall system, maintainable, and capable of non-intrusive remaining-life evaluation, is of great value. The brief summaries presented here give only a superficial view of some specific instances: studies supported by EPRI and others associated with the electricity enterprise deal with many of these examples in much greater detail.

References [1] R.B. Dooley, W.P. McNaughton, Boiler Tube Failures: Theory and Practice, Electric Power Research Institute, Palo Alto, CA, USA, 1996. [2] T. Flatley, T. Thursfield, Review of corrosion resistant co-extruded tube development for power boilers, in: 1984 ASM Conference on Coatings and Bimetallics for Energy Systems and Chemical Process Environments held at Hilton Head, SC, 12–14 November 1984.

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[3] J.-S. Lin, D.A. Stevenson and J. Stringer, The role of carbon in the in-bed corrosion of alloys in FBC, in: J.P. Mustonen (Ed.), Proc. 1987 Int. Conf. on Fluidized Bed Combustion, American Society of Mechanical Engineers, New York, NY, 1987, pp. 656–662. See also J. Stringer, Mixed oxidant corrosion in coal combustion and conversion systems: manifestations and mechanisms, in: J.D. Embury (Ed.), High Temperature Oxidation and Sulphidation Processes, Pergamon Press, Toronto, 1990, pp. 257–275. [4] A.J.B. Cutler, E. Raask, Corr. Sci. 21 (1981) 789. [5] E.C. Lewis, A.L. Plumley, Chromizing for combating fireside corrosion, in: R. Viswanathan, R.I. Jaffee (Eds.), Advances in Material Technology for Fossil Power Plants, ASM International, Materials Park, OH, 1987, pp. 291–296. [6] A. Bonnington, T. Cullen, Mitigation of circumferential cracking and fireside corrosion on supercritical boilers by installation of chromized waterwall panels, in: Proceedings: EPRI Conference— Welding and Repair Technology. Electric Power Research Institute, Palo Alto, CA, 1994. [7] T.P. Sherlock, C.H. Wells, R.B. Dooley, R. Tilley, State of knowledge assessment for accelerated waterwall corrosion with low NO x Burners, EPRI Final Report TR-107775, Electric Power Research Institute, Palo Alto, CA, 1997. [8] I.M. Rehn, Corrosion problems in coal-fired boiler superheater and reheater tubes: steam-side oxidation and exfoliation, EPRI Final Report CS-1811 on Project, Electric Power Research Institute, Palo Alto, CA, 1981. [9] I.M. Rehn, Long-term performance of chromate-treated superheater and reheater tubes, in: R. Viswanathan, R.I. Jaffee (Eds.), Advances in Material Technology for Fossil Power Plants, ASM International, Materials Park, OH, 1987, pp. 297–304. [10] J.L. Kratz, R.J. Ortolano, L.D. Kramer, Corrosion-resistant Coatings For Low-pressure Steam Turbines, EPRI Final Report CS-5013 on Project 1408-1, Electric Power Research Institute, Palo Alto, CA, 1987. [11] J. Mancuso, L.E. Willertz, L.D. Kramer, R.J. Ortolano, Development of Low-pressure Turbine Coatings Resistant to Steam-borne Corrodents, vol. 1: Initial Studies; J.L. Kratz, L.D. Kramer, R.J. Ortolano, vol. 2: Detailed Studies, EPRI Interim Report CS-3139 on Project 1408-1, Electric Power Research Institute, Palo Alto, CA, 1983. [12] R. Viswanathan, Damage Mechanisms and Life Assessment of High Temperature Components, ASM International, Metals Park, OH, 1989, p. 447. [13] J.W. Fairbanks, R.J. Hecht, The durability and performance of coatings in gas turbine and diesel engines, Mater. Sci. Eng. 88 (1987) 321–330.