Corrosion of Fossil Fuel Power Systems R.I. Jaffee, Electric Power Research Institute THE ELECTRIC POWER INDUSTRY uses three types of fossil-fired plants. The most common plant is the pulverized coal-fired steam power plant, which may be used either as a baseload plant (where the plant runs continuously at capacity except for scheduled outages for maintenance) or for intermediate loads between the steady baseload and higher loads needed daily. Gas turbines are used for peak loads that occur for an hour or two each day. Combined cycles using both gas and steam turbines are generally intended for baseload sustaining intermediate-load service. The fuels used in fossil-fired plants are natural gas, petroleum, and coal. Natural gas is generally extremely pure and does not constitute a corrosion threat, unless firing is substoichiometric for reducing NO x emissions. Petroleum fuels can be corrosive to boilers if they contain vanadium and alkali metals; these produce liquid vanadium oxides or alkali sulfates, both of which are highly corrosive to metals in the combustion chamber or hot-gas passages. Coal can contain such impurities as sulfur, chlorides, and alkali metals, which are extremely corrosive. Many coals are virtually unusable except under deaerated service conditions. Steam Power Plants Figure 1 shows an illustration of a fossil-fired steam power plant. Three fluid flow loops circulate through the system: fuel-air, water-steam, and condenser cooling. In the fuel-air loop, the fossil fuel is burned in air, transfers its heat to a series of heat exchangers, is cleaned of particulate matter, is scrubbed of sulfur oxides, and exits through the stack. In the water-steam loop, clean feedwater is converted into superheated steam in a boiler, which expands through a series of turbines, converting its heat into mechanical energy, and is condensed, conditioned, pumped, and heated as feedwater. In the condenser-cooling loop, cold water is passed through the condenser and can be recirculated if a cooling tower is used or an be exhausted back to the source of the cooling water. Each fluid loop possesses its unique corrosion problems. Fig. 1 Schematic of a coal-fired power plant The fossil fuel is burned in a very large chamber constructed of water walls consisting of vertical or spiral steel tubes about 60 mm (2.4 in.) in diameter that are welded together in a web about 20 mm (0.8 in.) wide. The feedwater ascends the water walls and is heated by the combusted fuel. In subcritical boilers, the generated steam is separated from the water such that the water is returned to the bottom of the water wall through downcomers, but the saturated steam is super- heated in tubular heat exchangers suspended in the gas stream. In supercritical boilers, the pressure is above the critical point, and the liquid becomes superheated vapor without undergoing a phase change. The feedwater is conditioned to be slightly alkaline, but the fluid in the boiler may become acidic or caustic, depending on the presence of corrosion deposits and flow interruptions. Under acidic conditions, the steel boiler tubes may be hydrogen embrittled; under caustic conditions, the tubes may be caustic gouged. In supercritical boilers, overheating and excessive internal scaling in water walls may occur if boiling undergoes departure from nucleate boiling conditions at the region near the critical pressure. The superheaters and reheaters are subject to steam oxidation on their inner surfaces and to hot corrosion on their outer surfaces. Steam oxidation results from attack by superheated steam, which acts similarly to oxygen at the same temperatures. For low-alloy steels, steam oxidation is of concern above 540 °C (100 °F). This is about the temperature at which creep strengths limit low-alloy steels, and it becomes necessary to use alloys with higher chromium contents for higher allowable stress and for better steam oxidation resistance. Fire-side corrosion in superheaters and reheaters is a typical problem. In coal-fired boilers, it exhibits a maximum rate at 700 to 750 °C (1290 to 1380 °F), where the corrodent is liquid, and decreases to a minimum at higher temperatures, where the corrodent does not condense. The liquid ash is generally an alkali sulfate or a complex alkali iron trisulfate. At higher temperature, corrosion is predominantly the oxidation of uncooled parts, such as hangers. Another types of boiler, the fluidized-bed boiler, was once thought to be free of fire-side corrosion because it operated under dry conditions at about 850 °C (1500 °F). The coal is burned in a fluidized bed composed of limestone or dolomite. The calcium sulfate (CaSO 4 ) product of desulfurization is in equilibrium with the calcium oxide (CaO) absorbant. At low oxygen potentials, such as those that occur in the condensed bed itself, the sulfur potential may rise high enough to sulfidize many otherwise very corrosion-resistant alloys. Following the coal-air loop in a conventional power plant further, the flue gas passes through heat exchangers for preheating combustion air. It is important to maintain the flue and gas temperature above its dew point in order to avoid the deposition of sulfuric acid (H 2 SO 4 ). After passage through the precipitator while above its dew point, the flue gas is scrubbed of its sulfur dioxide (SO 2 ) content in a flue gas desulfurization scrubber. There are many points of corrosion concern in the scrubber, but the most serious areas are the inlet duct, where the SO 2 -laden gas is hottest and a wet/dry interface exists, and the outlet duct, where the scrubbed gas, still containing sulfur trioxide (SO 3 ), begins to condense on the walls of the duct. Once the steam has been compressed and superheated, it leaves the boiler through heavy-wall pipes and enters the high- pressure turbine. There it expands and returns to the boiler for reheating before entering the intermediate-pressure turbine for a second expansion. After one or two expansions and reheatings, the steam enters the low-pressure turbine. As long as the steam is dry, there is little corrosion in the high- or intermediate-pressure turbines except when condensation of solid sodium hydroxide (NaOH) occurs. However, when expansion of the steam in the low-pressure turbine reaches the point of initial condensation (at the so-called Wilson Line), high-concentration chloride and sulfate salt solutions may deposit if the steam is contaminated. The distribution of salts between steam vapor and steam condensate is such that the condensate may be 10 6 times more concentrated than the vapor. Thus, the premissible impurity levels in the feedwater are measured in parts per billion in order to protect the low-pressure turbine at the Wilson Line, which generally occurs at the next to the last (L - 1, or last minus one) row of turbine blades. The Wilson Line shifts to a highest temperature point in the low-pressure turbine at reduced load such that in load-cycling plants there is alternate wetting and drying of the salt deposit as the load increases and decreases during cyclic operation. This is a serious condition for corrosion of blades and disks in the L - 1 row. The salt solution is often acidic as a result of evaporation of ammonia (NH 3 ) from the water-conditioning process. During shutdowns, oxygen and carbon dioxide (CO 2 ) may dissolve in the acidic salt, aggravating the corrosive condition at the L - 1 row of a low-pressure turbine. The commonly used 12% Cr turbine blade alloy becomes pitted under these conditions and may lose up to 90% of its fatigue strength. Corrective measures include using blades designed to be strong enough to operate with pitted surfaces, cleaning and maintaining the steam to avoid corrosive salt deposition, using more corrosion- resistant low-pressure turbine blade materials (such as titanium alloys), or protecting 12% Cr steel blades with corrosion- resistant coatings. Corrosion problems may occur in the condenser-cooling loop, especially if the cooling water is sulfide-contaminated seawater or brackish water acting on copper-base tubes or tubesheets. Also, pitting or crevice corrosion may occur under deposits or barnacles or between tubes and tubesheets. However, the primary concern with condensers is leakage of seawater or contaminated cooling water into the water-steam loop, which operates below atmospheric pressure; this leakage would result in drastic corrosion effects on boiler and turbine components. Gas Turbines In a gas turbine, inlet air is compressed in a compressor, reacted with fuel in a combustion chamber, and directed at stationary airfoil vanes and through rotor blades or buckets constituting the turbine stage. Thus, the entire fuel and air input passes through the gas turbine without an intermediate heat exchanger. Any corrosive impurities present in either fuel or air will affect the high-temperature components, primarily the combustor, nozzle diaphragm, and turbine. The principal threats are oxidation and hot corrosion. These have been largely met by using alloys of increased chromium content, particularly Ni20Cr and Co-30Cr alloys. However, as the turbine inlet temperature increased to achieve higher thermal efficiency, it became necessary to strengthen the alloys, which resulted in lower chromium contents and greater vulnerability to oxidation and hot corrosion. The use of bypass air cooling of the hot-section parts essentially reduced the metal temperature to a point at which the high-temperature strength was sufficient, while the gas temperature increased progressively. The high-temperature high-velocity gas stream causes evaporation of volatile chromium trioxide (CrO 3 ) from otherwise protective chromic oxide (Cr 2 O 3 ) scales. The alloys subjected to the highest turbine temperatures are protected by coatings containing over 5% Al, which from protective aluminum oxide (Al 2 O 3 ) scales. If the fuel or inlet air contains alkali metals, sulfur, or vanadium as impurities, hot corrosion may occur. This is combated by limiting these impurities in the fuel. Additives such as magnesium oxide (MgO) also help. Air filtration is used for reduce ingestion of airborn impurities. Vanes and blades are washed periodically to remove accumulated salts. The coatings that form Al 2 O 3 protective scales are sometimes improved by platinum metal additions or sublayers. Also, coatings with small additions of yttrium promote adherence of all Al 2 O 3 scale, which otherwise might spall off. Combined Cycle Plants In a combined cycle power plant, the gas turbine is used as a high-temperature topping cycle whose exhaust gas enters a waste heat boiler, which raises steam to operate the steam turbine and generator. To a large extent, corrosion problems in the combined cycle are simply the sum of the corrosion problems in the gas turbine and the steam boiler and turbine. Control of impurities in the inlet air and fuels is essential. Corrosion from the use of gasified coal, which may have caused severe problems in the gas turbine and steam generator, has largely been eliminated by scrubbing the gasified coal in a water-quenching operation. There are severe corrosion problems in the radiant cooler used to generate process steam from the raw gasified coal, which contains hydrogen sulfide (H 2 S) and other corrosive agents before the scrubbing operation. These problems can be handled by limiting the temperature of the radiant cooler to be commensurate with the heat- exchanger material used, which is generally coated or clad steel. Corrosion of Condensers Barry C. Syrett, Electric Power Research Institute; Roland L. Coit, Consultant A steam surface condenser is a shell and tube heat exchanger that is positioned immediately downstream of the low- pressure steam turbine. Heat is transferred from steam on the outside of the condenser tubes (the shell side or steam side) to water on the inside (the tube side or water side). A schematic of a typical electric power plant condenser is shown in Fig. 2. Fig. 2 Schematic of a typical condenser in an electric power plant The condenser is a particularly critical component in a power plant because its failure can affect many other components in the steam-water cycle. The root cause of many of the corrosion problems in fossil fuel boilers, nuclear steam generators, low-pressure steam turbines, and feedwater heaters has been traced to condensers that have leaked and allowed contamination of the steam condensate with raw cooling water and air. Most tube leaks are caused by corrosion, but some failures are purely mechanical, such as those caused by steam impingement (erosion), tube-to-tubesheet joint leaks, mechanical ruptures from foreign object impact, and tube vibration resulting in fretting wear and fatigue. Purely mechanical failures will not be discussed further. Corrosion mechanisms that have led to failure or serious problems in power plant condenser are summarized in Table 1. Table 1 reflects known service problems to date, rather than susceptibilities that might be inferred solely from laboratory tests; each form of failure occurs only under specific environmental and metallurgical conditions. Information on tubesheet materials requires special explanation. Because tubesheets are very thick (>25 mm, or 1 in.), corrosion rates can be 15 to 50 times higher than in condenser tubes and still be considered acceptable in most cases. Furthermore, even if corrosion is a serious problem in a tubesheet, inspections are usually scheduled frequently enough, and the tubesheet is thick enough, that suitable repair can made or corrosion protection procedures can be instituted along before the tubesheet is penetrated. Thus, although Table 1 indicates that copper alloy tubesheets have suffered significant (often severe) galvanic corrosion under certain conditions, leakage of cooling water through the tubesheet from the water side to the steam side has rarely occurred. Each of the corrosion mechanisms responsible for failures in condensers will be reviewed below. Some of the methods of preventing these failures will also be summarized. Table 1 Corrosion mechan isms that have caused problems in power plant condensers under certain conditions Corrosion mechanism Alloy Erosion- corrosion Sulfide attack Dealloying Crevice corrosion/ pitting Galvanic corrosion Environmental cracking Condensate corrosion Copper alloys Muntz metal (tubesheets) N (W) (W) N W N N Aluminum bronze (tubesheets) N (W) N N (W) N N Aluminum bronze W W (W) (W) (a) (W) (S) (S) 90Cu-10Ni W W (W) (W) (a) (W?) N (S) 70Cu-30Ni W W N (W) (a) (W?) N (S) Aluminum brass W W (W) W (a) W W/S S Admiralty brass W W (W) W (a) W W/S S Stainless steels AISI type 304 N N N W N (b) N N AL6X N N N (W) N (b) N N AL29-4C N N N N N (b) (W) N Sea-Cure N N N (W) (c) N (b) (W) N Titanium alloys Commercial-purity titanium N N N N N (b) (N) N W, water-side problem; S, steam- side problem; N, not a problem; ( ), slight sensitivity to problem; ?, problems have occurred in similar alloys. (a) Perhaps a problem only when sulfide is present. (b) Can induce galvanic- corrosion of adjacent copper alloys, iron, and carbon steels when used in seawater or other highly conductive waters. (c) A problem in heats containing only 25.5% Cr and 3% Mo Erosion-Corrosion Erosion-corrosion is a relatively common waterside phenomenon that is a problem only in copper alloy condenser tubes. It occurs in areas where the turbulence intensity at the metal surface is high enough to cause mechanical or electrochemical disruption of the protective oxide film. In these turbulent regions, pitlike features develop. Turbulence increases with increasing velocity and is greatly influenced by geometry. For example, turbulence intensity is much higher at tube inlets than it is several feet down the tubes; this results in the phenomenon of inlet-end erosion-corrosion. Tube inserts have been used to circumvent this problem. A tube insert is a tightly fitting internal sleeve, typically 150 to 300 mm (6 to 12 in.) long, made from a material resistant to erosion-corrosion that shields the susceptible tube ends. However, unless there is a smooth transition between the end of the insert and the tube, the insert can itself create turbulent conditions and promote erosion-corrosion further down the tube (Fig. 3). Recent experiments have demonstrated that inlet-end erosion-corrosion can also be prevented by installing a cathodic protection system in the water box region. Fig. 3 Erosion-corrosion occurring immediately downstream of a nylon insert in an aluminum brass condenser tube cooled by seawater Erosion-corrosion may also occur when marine life or debris in a tube creates a partial blockage, resulting in locally high velocities through the restricted opening. In these cases, the best solution is to keep the tubes clean, using one or more of the following methods: • Install or improve intake screens • Install on-line sponge ball cleaning • Periodically reverse flow (backwash) • Manually clean with brushes, balls, scrapers, and so on (off line) • Prevent biofouling by chlorination or thermal shock Alternatively, some copper alloys benefit from periodic dosing of the water with ferrous ions (Fe 2+ ), which are usually added as ferrous sulfate (FeSO 4 ) solution. The Fe 2+ ions deposit as a protective lepidocrocite [FeO(OH)] layer on the copper alloy surface. Sulfide Attack This form of attack affects only copper alloys and occurs when the cooling water, most often brackish water or seawater, is polluted with sulfides, polysulfides, or elemental sulfur. As little as 10 mg/m 3 (10 ppb) of sulfide in the cooling water can have a detrimental effect, and concentrations far greater than this are often measured in polluted harbors and estuaries. Sulfide attack manifests itself in many ways. It can greatly increase general corrosion rates, and it can induce or accelerate dealloying, pitting, erosion-corrosion, intergranular attack, and galvanic corrosion. Penetration rates in polluted waters can be extraordinarily high, sometimes as high as 20 mm/yr (80 mils/yr). No copper alloy is resistant to sulfide attack, and the relative performance of copper alloys in polluted or brackish waters seems to depend on the precise environmental conditions. If the incoming water contains sulfide and there is no obvious method of eliminating the source, the most successful method of reducing or preventing the problem is to dose the water periodically or continuously with FeSO 4 or some other source of Fe 2+ ions. However, sulfide attack can also occur in condensers cooled with nominally unpolluted water if marine organisms trapped within the condenser during downtime are allowed to die and putrefy to produce sulfides. This can probably be prevented, or at least reduced, by turning on the pumps for an hour or two each day to flush out the condenser with fresh seawater. In addition, sulfate-reducing bacteria can produce sulfides under debris and deposits where the oxygen content is low. Thus, the risk of sulfide attack is greatly reduced if the copper alloy tubes are regularly cleaned. Dealloying Another water-side problem in brass-tubed condensers is dealloying. Dezincification is an example of dealloying that has been observed in utility condensers. In dezincification, zinc is selectively removed from brass alloys to leave a copper- rich surface layer. Dealloying is rarely the cause of condenser tube failure, but when it does occur, it is normally restricted to localized areas, such as beneath deposits or at hot spots. This results in plug-type dealloying. Clearly, maintaining clean tubes will reduce the incidence of this type of failure. A much less localized from of dealloying, termed layer-type dealloying, is rare in tubes, but has occasionally occurred in brass tubesheets, particularly in conjunction with galvanic corrosion in induce by titanium or stainless steel condenser tubes. Under such circumstances, a cathodic protection system installed in the water box will control both galvanic-corrosion and dealloying. Crevice Corrosion and Pitting Some stainless steels and cooper alloys are susceptible to water-side pitting and crevice corrosion. Brass and austenitic stainless steel condenser tubes, in particular, are known to have failed by pitting and crevice corrosion. There is limited evidence that copper alloys have adequate resistance to these forms of corrosion if the cooling water is completely free of sulfide. Certainly, susceptibility seems to be greatly increased when sulfide is present. Pitting and crevice corrosion of stainless steels are more dependent on the chloride content of the cooling water than on the sulfide content, although laboratory data have demonstrated that the detrimental effects of chloride are accentuated in the presence of sulfide. Some alloys, such as AISI type 304 and 316 stainless steels, which generally perform well in freshwaters or slightly brackish waters, suffer rapid pitting and crevice corrosion in seawater (Fig. 4). The newer, more highly alloyed stainless steels, including AL6X (UNS NO8366), AL29-4C (Fe-29Cr-4Mo-0.35Si-0.02C-0.02N-0.24Ti), and Sea-Cure (Fe-27.5Cr-3.4Mo-1.7Ni-0.4Mn-0.4Si-0.02C-0.5Ti+Nb), generally perform well even in seawater. However, a few failures have been reported for AL6X and for some of the early heats of Sea-Cure. Fig. 4 Example of pitting in AISI type 316 stainless steel in seawater service Again, tube cleanliness is a critical issue because debris and deposits promote the formation of concentration cells (the precursor to crevice corrosion) and because they favor the production of sulfides. The tube-cleaning techniques summarized earlier in this section are therefore equally useful in preventing crevice corrosion and pitting in copper alloys and stainless steels. Galvanic Corrosion Galvanic corrosion is not a problem is poorly conducting waters, such as those normally found on the steam side of condensers. However, it can be a water-side problem in condensers cooled with seawater or with medium- or high- conductivity fresh and brackish waters. In seawater, tube materials, such as copper-nickel alloys, stainless steels, and titanium, are more noble than tubesheet materials, such as Muntz metal and aluminum bronze. Consequently, the tubesheet may suffer galvanic attack when fitted with these more noble tubes (Fig. 5). Laboratory tests have demonstrated that the rate of galvanic corrosion of a Muntz metal tubesheet fitted with titanium or stainless steel tubes can exceed 5 mm/yr (200 mils/yr) in seawater. Similarly, if stainless steel inserts are installed in copper alloy tubes to prevent inlet-end erosion-corrosion, rapid galvanic corrosion can be promoted in the tube close to the insert/tube interface. Fig. 5 Galvanic corrosion of a Muntz metal tubesheet, fitted with AL6X stainless steel tubes, after 1 year of service Other galvanic couples can exist in a condenser, but in each case, the recommended method of alleviating the problem is to install a cathodic protection system in the water box. Cathodic protection current requirements can be reduced by coating the tubesheet and water box with a nonconducting material. Environmental Cracking Stress-corrosion cracking (SCC) and hydrogen embrittlement cracking are forms of environmental cracking that can affect condensers. Hydrogen embrittlement cracking was identified as a problem on the water side of ferritic stainless steel tubes in a couple of condensers fitted with cathodic protection systems. It is believed that hydrogen was generated on the surface of the tubes by the passage of too high a cathodic protection current and that this hydrogen promoted slow crack growth and failures at the ends of the tubes. The tube ends were particularly susceptible to hydrogen embrittlement cracking because roller expansion during fabrication introduced higher-than-normal residual stresses in these zones. Entry of hydrogen into cathodically protected titanium tubes is also possible if too high a cathodic protection current is delivered. In such cases, the absorbed hydrogen can react with the metal to form a brittle titanium hydride phase which could conceivably crack and lead to premature failure. However, so far no titanium condenser tube failures have been reported. One electric utility that grossly overprotected the waterbox region of a titanium-tubed condenser discovered that the ends of the tubes were severely hydrided, but even here the affected tubes did not leak. Apart from the rather unusual failures in ferritic stainless steels, environmental cracking is a problem only in copper alloys, specifically the brasses. Here, SCC (not hydrogen embrittlement cracking) is the mechanism of failure. Most SCC failures initiate on the steam side of the tubes, and all occur when the steam condensate contains high concentrations of NH 3 and oxygen. The NH 3 is derived from the chemicals added for boiler feedwater chemistry control, and oxygen originates from air that leaks into the system through imperfectly maintained turbine glands, expansion joints, valve packing glands, and so on. The NH 3 and oxygen concentrations are particularly high in the air removal section, and it is here that SCC occurs most frequently. Steam-side SCC can be controlled by ensuring that the condensate on the tubes has a low oxygen concentration. The maintenance of an airtight system requires continuing attention to all seals, glands, and joints that are subjected to internal pressures less than atmospheric during start-up, normal operation, or shutdown. Helium tracer and similar techniques allow leaks to be detected with moderate ease. Water-side SCC of brasses has occurred less frequently than steam-side attack, and in most cases, the species responsible for the failure were not positively identified. However, NH 3 and its derivatives (nitrates and nitrites) are often suspected of promoting SCC. Possible sources of these species are farm fertilizers (runoff) and decaying organisms in polluted water. Water-side failures frequently initiate beneath surface deposits, probably because the deleterious species can concentrate beneath the deposit to levels that favor SCC. Thus, once again, tube cleanliness is important, and cleaning techniques can be used to minimize water-side SCC. No matter which side of the tube is susceptible to environmental cracking, the incidence of cracking can be controlled by reducing or eliminating residual tensile stresses. Roller expansion of the tubes during installation will always introduce some residual stresses, but care should be taken to avoid expansion beyond the back of the tubesheet, and event that can lead to particularly high residual stresses. In addition, fully stress-relieved tubes should be used, and during installation, they should not be bent or mechanically abused. Condensate Corrosion Copper alloy condenser tubes, particularly brass condenser tubes, are susceptible to condensate corrosion in steam condensate that contains high concentrations of HN 3 and oxygen. Consequently, condensate corrosion, like SCC, is most prevalent in the air removal section. Condensate corrosion, also known as NH 3 attack, is a form of corrosion that is localized not by microstructural features in the metal but by the localization of the corrosive environment (Fig. 6). For example, the slight tilt routinely given to condenser tubes may promote flow of some of the steam condensate toward one side of a tube support plate. There, the flow from a large number of tubes can collect and run down the plate surface. Such localized flow can create deep circumferential grooves, termed condensate grooving, in the tubes immediately next to the support plate (Fig. 6b) if the condensate contains high levels of HN 3 and oxygen. Condensate corrosion can be controlled by reducing the oxygen concentration in the condensate, as discussed previously for steam-side SCC, or by selecting more resistant alloys, such as copper-nickel alloys, or completely resistant alloys, such as stainless steels and titanium. Fig. 6 Examples of NH 3 attack on admiralty brass. (a) The unattacked tube end (left) was protected by the tubesheet. (b) Condensate grooving that occurred at one side of a support plate Corrosion Prevention Many corrosion modes operating in condensers can be prevented if only two maintenance procedures are followed. First, if air is eliminated from the steam, condensate corrosion and SCC of copper alloy tubes can be prevented. Second, if condenser tubes are kept clean and free of deposits, debris, and biofouling on the water side, sulfide attack, dealloying, erosion-corrosion, crevice corrosion, pitting, and SCC can be prevented or minimized. Corrosion of Deaerators and Feedwater Heaters Robert J. Bell, Heat Exchanger Systems, Inc. Deaerators (direct contact deaerating feedwater heaters are used in fossil and a few nuclear power plants primarily to remove dissolved gases (mostly oxygen and nitrogen) from condensate/feedwater and to raise the condensate temperature by exchange with extraction steam by mechanical deaeration. Another function is to provide deaerator storage capacity and proper suction conditions for the boiler feed pump. Closed feedwater heaters (Fig. 7) are used in power plants to increase the overall cycle efficiency of the plant by delivering to the boiler or steam generator water at higher temperatures, thereby reducing the heat required to produce steam. This is accomplished by heating the feedwater (condensate) using extraction steam from the turbine. [...]... to SCC) Table 3 Corrosion mechanisms in steam turbine components Component Material Rotor Shell Disks, bucket wheels Dovetail pins Blades, buckets Bucket tie wires Shrouds, bucket covers Stationary blades Expansion bellows Erosion shields Forged Cr-Mo-V or Ni-Cr-Mo-V low-alloy steel Cast carbon or Cr-Mo-V low-alloy steel Forged Cr-Mo-V, Ni-Cr-Mo-V or Ni-Cr-Mo low-alloy steel Cr-Mo low-alloy steel Stainless... stems (a) Corrosion mechanisms(a) P, SCC, CF, E SCC, E-C P, SCC, CF, E-C SCC P, CF, SCC, E SCC, P, CF P, SCC SCC, SCC-LCF SCC, SCC-LCF SCC, E SCC, SCC-LCF E-C P, OX P, pitting: SCC, stress -corrosion cracking; CF, corrosion fatigue; E, erosion; E-C, erosion -corrosion; LCF, low-cycle fatigue; OX, oxidation in steam General corrosion is experienced by all carbon and low-alloy steel components Solid-particle... an alloy more or less susceptible to hot corrosion are known The near standardization of such alloys as IN-738 and IN-939 for first-stage blades and buckets, as well as FSX 414 (Co-0.25C-29.5Cr-10.5Ni-7W-2maxFe-1maxMn-1maxSi-0.012B) for first-stage vanes and nozzles, implies that these are the accepted best compromises between high-temperature strength and hot corrosion resistance It has also been possible... high-pressure and intermediate-pressure inlets (nozzle blocks, stationary and rotating blades, and valves) It is caused by exfoliation of steam-grown oxides in superheater tubes and in steam pipes Fig 14 Schematics showing locations of corrosion in steam turbine components P, pitting; CF, corrosion fatigue; SCC, stress -corrosion cracking; C, crevice corrosion; G, galvanic corrosion; E, erosion; E-C,... the Na2SO4-CoSO4 eutectic is 545 °C (1 013 °F) Unlike type I hot corrosion, a partial pressure of SO3 in the gas is critical for the reactions to occur in low-temperature hot corrosion Knowledge of the relationships between SO3partial pressure and temperature inside a turbine allows some prediction of where layer-type hot corrosion can occur Because first-stage blade metal temperatures in heavy-duty engines... the range of 705 to 760 °C (130 0 to 140 0 °F), is characterized by an uneven scale/metal interface containing intermittent pockets of subscale precipitate- depleted zones and sulfides The layer-type and the transitional corrosion to gather are variously referred to as type II hot corrosion, low temperature hot corrosion, and low-power corrosion Fig 22 Three forms of hot corrosion in Udimet 710 turbine... Tube materials can vary from carbon steels to low-chromium ferritic (ASME SA- 213, grades T-11, T-22) to austenitic stainless steels (ASME SA- 213, grades T304, T321, and T347) Normal Protective Oxide Growth Chromium-containing steels exposed to high-pressure power station steam at metal temperatures from 550 to 650 °C (1020 to 1200 °F) initially form a spinel-type oxide consisting of two layers whose relative... Superheaters and High-Temperature Air Heaters John Stringer, Electric Power Research Institute Corrosion of superheaters and air heaters is inevitable in coal-fired boilers and in fluidized-bed combustors This section will discuss factors that cause corrosion as well as measures that can be taken to minimize corrosion in these applications Superheater Corrosion in Coal-Fired Boilers The fire-side corrosion of... bellows, and piping corrosion, the total annual cost of utility turbine corrosion in the United States is about $600 million The cost of replacement power can be as much as two orders of magnitude higher than that of replacement parts Major Corrosion Problems in Steam Turbines Corrosion fatigue, SCC, pitting, and erosion -corrosion are the primary corrosion mechanisms in steam turbines Figure 14 and Table... ASME Boiler Codes Material SA-106 carbon steel Ferritic alloy steels 0.5Cr-0.5Mo 1.25Cr-0.5Mo 2.5Cr-1Mo 9Cr-1Mo Austenitic stainless steel Type 304H (a) Maximum-use temperature Oxidation graphitization criteria, metal surface(a) °C °F 40 0-5 00 75 0-9 30 Strength criteria, metal midsection °C °F 425 795 550 565 580 650 1020 1050 1075 1200 510 560 595 650 950 1040 1105 1200 760 140 0 815 1500 In the fired . Shell Cast carbon or Cr-Mo-V low-alloy steel SCC, E-C Disks, bucket wheels Forged Cr-Mo-V, Ni-Cr-Mo-V or Ni-Cr-Mo low-alloy steel P, SCC, CF, E-C Dovetail pins Cr-Mo low-alloy steel SCC Blades,. corrosion in seawater (Fig. 4). The newer, more highly alloyed stainless steels, including AL6X (UNS NO8366), AL2 9-4 C (Fe-29Cr-4Mo-0.35Si-0.02C-0.02N-0.24Ti), and Sea-Cure (Fe-27.5Cr-3.4Mo-1.7Ni-0.4Mn-0.4Si-0.02C-0.5Ti+Nb),. 3 Corrosion mechanisms in steam turbine components Component Material Corrosion mechanisms (a) Rotor Forged Cr-Mo-V or Ni-Cr-Mo-V low-alloy steel P, SCC, CF, E Shell Cast carbon or Cr-Mo-V